20250131Direct J. Diluciano_Exhibits.pdf

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

1 I. INTRODUCTION
2 Q. Please state your name, employer, and business address.
3 A. My name is Joshua D. DiLuciano and I am employed as the Vice President of
4 Energy Delivery for Avista Utilities (Avista or Company), at 1411 East Mission Avenue,
5 Spokane, Washington.
6 Q. Would you briefly describe your educational background and
7 professional experience?
8 A. Yes. I am a graduate of Washington State University (WSU), from which I
9 earned a Bachelor of Science degree in Electrical Engineering. I also earned a Master of
10 Science degree in Management and Leadership from Western Governors University and am
11 a licensed electrical engineer in Washington State. I joined Avista in 2006 as an Engineer and
12 have held a variety of technical engineering roles since. I have managed several groups, most
13 recently as Director of Electrical Engineering where I had responsibility for Washington
14 Advanced Metering Infrastructure (AMI), the Company's geographic information system
15 (GIS) Refresh, Transmission Engineering, Distribution Engineering, Protection Engineering,
16 Substation Engineering, Drafting and Edit, Maximo, and Engineering Technical Services. I
17 was awarded my current position in September 2022, where I have responsibility for electric
18 and natural gas engineering, operations, transmission operations and system planning, and
19 shared services.
20 Additionally, I am a U.S. Navy veteran, and I currently serve on the board of the West
21 Central Community Center.
22 Q. What is the scope of your testimony?
23 A. I will provide an overview of the Company's electric and natural gas energy
24 delivery facilities and explain the factors driving our continuing investment in electric
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Avista Corporation

I distribution infrastructure. I will explain how our efforts to maintain the asset health and
2 performance of our electric transmission system, including compliance with mandatory
3 federal standards for transmission planning and operations, is driving a continuing demand
4 for new investment. I will also describe why our investments in natural gas distribution are
5 necessary in the time frames completed, and why each capital investment in our operations
6 facilities and fleet operations is needed to support the efficient delivery of service to our
7 customers today, and into the future. Furthermore, I will address the electric and natural gas
8 distribution, transmission, general plant, and fleet related capital additions included in the
9 Company's Two-Year Rate Plan filed in this case,for the periods July 1,2024,through August
10 31, 2027. A table of the contents for my testimony is as follows:
11 Description Page
12 I. INTRODUCTION 1
13 II. OVERVIEW OF AVISTA'S ENERGY DELIVERY SERVICE 3
14 III. INVESTMENTS IN THE COMPANY'S ELECTRIC
15 DISTRIBUTION SYSTEM 6
16 IV. INVESTMENTS IN THE COMPANY'S ELECTRIC
17 TRANSMISSION SYSTEM 13
18 V. INVESTMENTS IN THE COMPANY'S NATURAL GAS
19 SYSTEM 20
20 VI. INVESTMENTS IN THE COMPANY'S OPERATIONS,
21 FACILITIES AND FLEET SERVICES 25
22
23 Q. Are you sponsoring any exhibits in this proceeding?
24 A. Yes. I am sponsoring the following Schedules as a part of Exhibit No. 10:
25 0 Schedule 1, Avista's Priority Aldyl-A Protocol Report
26 • Schedule 2, Study of Aldyl-A Mainline Pipe Leaks - 2024 Update
27 • Schedule 3, Capital Business Case documents for each of the capital projects
28 and programs described in my testimony.
29
30 Q. Will you be providing an overview of Avista's Wildfire Resiliency Plan in
31 your testimony?
32 A. While I am the officer responsible for our work in this important area,
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Avista Corporation

I Company witness Mr. Malensky will provide an overview of the strategy and actions
2 comprising the plan, including the investments the Company is making under the plan.
3
4 II. OVERVIEW OF AVISTA'S ENERGY DELIVERY SERVICE
5 Q. Please describe Avista's electric and natural gas utility operations.
6 A. Avista operates a vertically integrated electric system in Washington and
7 Idaho, and natural gas local distribution operations in Washington, Idaho, and Oregon. In
8 addition to the hydroelectric, renewable, and thermal generating resources, the Company has
9 an electric transmission system comprised of approximately 700 miles of 230 kV lines and
10 1,600 miles of 115 kV lines and approximately 19,300 miles of primary and secondary electric
11 distribution lines. Additionally, the Company owns and operates approximately 8,000 miles
12 of natural gas distribution lines, served from the Williams Northwest and Gas Transmission
13 Northwest (GTN) pipelines. A map showing the Company's electric and natural gas service
14 area in Washington, Idaho and Oregon is provided by Company witness Ms. Rosentrater.
15 As detailed in the Company's 2023 Electric Integrated Resource Plan (IRP),1 Avista
16 expects retail electric sales growth to average 0.33% annually for the next ten years in our
17 service territory, a small increase from our 2023 IRP. Also, based on Avista's 2023 Natural
18 Gas IRP,2 in Idaho and Washington the number of natural gas customers is projected to
19 increase at an average annual rate of 1.1% between 2023 and 2045, with demand growing at
20 a compounded average annual rate of 0.52%.
21 Q. How many customers are served by Avista in the State of Idaho?
22 A. Of the Company's approximate 422,000 electric and 383,000 natural gas
1 The Company's 2025 Electric IRP has been provided by Mr.Kinney(Exhibit No. 6, Schedule 1).
2 The Company's 2023 Natural Gas IRP has been provided by Mr.Kinney(Exhibit No.6, Schedule 3).
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Avista Corporation

I customers, approximately 148,000 and 97,000, respectively, are Idaho customers.
2 Q. Please list the Company's operations service centers that support electric
3 and natural gas customers in Idaho.
4 A. The Company has construction offices in Coeur d'Alene, Sandpoint, St.
5 Maries, Kellogg, Grangeville, Moscow/Pullman, and Lewiston/Clarkston.
6 Q. Please describe the Company's Service Quality Measures Program.
7 A. Avista's Service Quality Measures (SQM) Program was approved by the
8 Commission in November 2018, and includes the following measures:3
9 ✓ Reporting on two (2) measures of electric service reliability.
10 ✓ Seven (7) individual service standards, where Avista provides customers a
11 payment of bill credit in the event the Company does not deliver the required
12 service level (Customer Service Guarantees), and
13 ✓ Five (5) individual measures of the level of customer service and satisfaction
14 the Company must achieve each year.
15
16 The Company is pleased to report we exceeded all six Customer Service Measure benchmarks
17 for our most recent reporting year in 2023 and noted a continuing,relatively stable, long-term
18 trend in electric service reliability.4 Results for Avista's 2023 Customer Service Measures are
19 provided in Table No. 1:
s Order No.34181 in Case Nos.AVU-E-18-10 and AVU-G-18-06.
a Avista annually reports results for its Service Quality programs at the end of April for the prior reporting year.
Accordingly,the Company will have complete results for 2024 by April 30,2025.
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Avista Corporation

I Table No. 1 —2023 Results for Avista's Customer Service Measures
2 Customer Service Measures Benchmark 2023Performance
Percent of customers satisfied with our Contact Center services, At least 90% 96M. �/
3 based on survey results
Percent of customers satisfied with field services,based on survey results At least 90% 97% V/
4 Number of complaints to the WUTC per 1,000 customers,per year Less than 0.40 0.04 `/
Percent of calls answered live within 60 seconds by our Contact Center At least 80% 83% V/
5 Average time from customer call to arrival of field technicians No more than 47 minutes
in response to electric system emergencies,per year 80 minutes
Average time from customer call to arrival of field technicians No more than 50 minutes
6 in response to natural gas system emergencies,per year 55 minutes
7 � .
Frequency of non-major-storm power interruptions, 0.96 OJ9 0.004
per year,per customer(SAIFI)
8 Length of power outages,per year,per customer(SAIDI) 138 minutes 113 minutes -2.6 minutes
9 Q. Please describe the approach used by Avista for evaluating and managing
10 the energy delivery capital investments required to serve our customers.
11 A. The Company's process for determining which projects should be
12 recommended for funding each year includes reviewing comprehensive planning studies,
13 engineering and asset management analyses, and scheduled upgrades and replacements
14 identified across our operations districts and Transmission Engineering. These projects
15 undergo internal review by multiple stakeholders, who help ensure all system needs and
16 alternatives have been identified and evaluated.
17 As discussed by Company witness Mr. Christie,projects advanced for funding enter a
18 formal review process and are reviewed and prioritized by higher-level committees, such as
19 Avista's Engineering Round Table (ERT), the Aldyl A Pipe Advisory Group, and the
20 Facilities Steering Committee. These groups carefully review the need for each project, the
21 primary business driver, the alternatives considered, and the justification for the approach
22 recommended. During the review, the potential benefits of any cross-business-unit synergies
23 that could better optimize project benefits and scope are also identified and evaluated. The
24 result of this process is a prioritized list of recommended projects that serves as a roadmap of
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Avista Corporation

I investments sequenced by year. Using this roadmap, each department can plan ahead for the
2 work they will be responsible to execute once projects are approved for funding and
3 implementation. Once evaluated,prioritized, and sequenced,these projects are recommended
4 to the Capital Planning Group (discussed by Mr. Christie) for final review and funding
5 allocation.
6 Q. Are alternatives vetted for these projects before approvals are given?
7 A. Yes. Where there are reasonable alternatives, the evaluation of those is
8 discussed in each business case (business case documents for the capital projects I am
9 sponsoring have been included as Exhibit No. 10, Schedule 3).
10 Q. How is Avista's leadership informed of the program status?
11 A. As described above,project and program status and results are communicated
12 up departmental lines through various committees, and to me by my director-level direct
13 reports.Program and project results are also reported directly to the Company's senior leaders,
14 including myself,through steering committees, various business meetings, and presentations.
15
16 III. INVESTMENTS IN THE COMPANY'S ELECTRIC DISTRIBUTION SYSTEM
17 Q. Please summarize the need for continuing investments in the electric
18 distribution system.
19 A. Avista, like utilities across the country, continues to prudently fund the
20 increasing demand for investment in electric distribution infrastructure. The pattern of our
21 investments bears a striking resemblance to that of the industry, which should not be a
22 surprise, since we are all responding to the same predominant needs: first, the need to supply
23 our customers with safe and reliable electricity, which creates the need to annually replace an
24 increasing amount of infrastructure that has reached the end of its useful life (based on asset
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Avista Corporation

I conditions). Second, we are responding to the need for technology investments required to
2 build an integrated energy services grid. To provide better visibility of the factors driving this
3 need for investment, we continue to organize the Company's planned spending over the
4 current five-year planning horizon by "Investment Driver" categories shown below, and as
5 discussed by Mr. Christie.
6 1. Respond to customer requests for new service or enhancements;
7 2. Meet our customers' expectations for service quality and reliability;
8 3. Meet regulatory and other mandatory obligations;
9 4. Address system performance and capacity needs;
10 5. Replace infrastructure at the end of its useful life based on asset condition; and,
11 6. Replace equipment that is damaged or fails, and support field operations.
12
13 Q. Would you please summarize the capital investments in electric
14 distribution plant completed in 2024 and planned for over the Two-Year Rate Plan?
15 A. Yes. As discussed by Company witnesses Ms. Schultz and Ms. Benjamin,
16 Avista's capital witnesses, including myself, describe the capital projects included in the
17 Company's proposed Two-Year Rate Plan, reflecting pro forma capital additions for the
18 period between July 1, 2024 and August 31, 2027. The completed and planned investments
19 related to electric distribution, presented on a system basis, are shown below in Table No. 2,
20 and described below. See also the detailed narrative for each electric distribution Business
21 Case at Exhibit No. 10, Schedule 3, pages 3 — 170.
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Avista Corporation

I Table No. 2-Electric Distribution Capital Proiects (System)
2
3 Electric Distribution Capital Projects(System)In$(000's)
4 Rate Year 1 Rate Year 2
Line July 2024- Sept 2025- Sept 2026-
5 # Business Case Name Investment Driver August 2025 Aug 2026 Aug2027
6
7 1 Distribution Grid Modernization Asset Condition $ 451 $ 799 $ 1,411
2 Distribution Minor Rebuild Asset Condition 14,562 13,833 14,657
8 3 Distribution System Enhancements Performance&Capacity 11,399 10,063 10,719
9 4 East CDA Lake Reinforcement Program Performance&Capacity 243 694 -
10 5 Elec Relocation and Replacement Program Mandatory&Compliance 9,968 6,960 7,020
1 1 6 Electric Storm Failed Plant&Operations 2,836 2,529 2,529
7 Joint Use Mandatory&Compliance 4,530 4,167 3,667
12 8 Meter Minor Blanket Faded Plant&Operations 274 250 250
13 9 Metro 115kV Substation Asset Condition 3,990 - 9,315
14 10 New Revenue-Growth Customer Requested 78,190 62,629 66,746
11 Substation-Asset Condition Asset Condition 26,781 19,003 6,895
15 12 Substation-Performance and Capacity Performance&Capacity 15,594 11,517 14,660
16 13 Substation Faded Plant Failed Plant&Operations 1,000 1,500 1,500
17 14 Wood Pole Management Asset Condition 8,797 11,573 12,577
18 Total Planned Electric Distribution Capital Projects $ 178,616 $ 145,517 $ 151,946
19
20
21 Distribution Grid Modernization (July 2024-August 2025: $451,000, RY1: $799,000,
22 RY2: $1,411,000)
23 The purpose of this program is to rebuild and upgrade every electric feeder in Avista's
24 distribution system. Some objectives within this program are replacing end of life assets,while
25 evaluating improvements in feeder design to bolster service reliability, capture energy
26 efficiency savings, and improve operational ability, code compliance and safety.5 These
27 objectives are accomplished through the systematic replacement of end-of-life equipment,
28 such as old poles,conductor,and transformers,with new and more energy-efficient equipment
29 that ensures the long-term, efficient operability of the system. Other issues addressed on each
30 feeder include pole realignment to address accessibility issues and right-of-way concerns,
31 potential feeder undergrounding, coordination of joint use facilities, and clear zone
32 compliance. On qualifying feeders,additional system reliability value is captured by installing
33 distribution line automation devices to help isolate outages and reduce the number of
34 customers that experience a sustained outage (also known as feeder automation). This
35 business case results in direct O&M offsets by reducing the number of service calls received.
36 The annual system estimated value of these Direct Offsets is expected at $101,839 in 2025,
37 $161,456 in 2026 and $198,726 in 2027. Idaho's share is prorated over the Two-Year Rate
38 Plan and included in the Company's revenue requirement as a reduction in expense within pro
39 forma Adjustments 3.10 (Rate Year 1) and 26.05 (Rate Year 2).
40
41 Distribution Minor Rebuild (July 2024-August 2025: $14,562,000, RY1: $13,833,000,
42 RY2: $14,657,000)
43 Distribution Minor Rebuild is an ongoing program that focuses on keeping the distribution
5 Instead of simply replacing equipment like poles in place and in kind,Grid Modernization looks at the overall
feeder design to evaluate the opportunity for gains captured through new designs, feeder alignment, dividing
feeders,and new technology.
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Avista Corporation

I system in a safe and reliable condition for customers, ensuring responsiveness to unplanned
2 damages on distribution assets (car hit pole, broken crossarm, burned up transformer, etc.)
3 that are not related to weather events, as well as small customer driven rebuilds. Throughout
4 the entire distribution system, minor rebuilds, or replacement of asset units are required to be
5 completed to maintain system reliability and safety. The work includes failed asset
6 replacements, small mandatory or compliance driven work, smaller performance and capacity
7 improvements, or unplanned customer requests. Occasionally, larger projects with an
8 identified need and short timeframe for implementation are constructed under the Distribution
9 Minor Rebuild business case.Even though the work is unplanned,Minor Rebuild work occurs
10 regularly due to the nature of the utility business and our numerous assets in the field spread
11 over a wide geographical area. An adverse accumulation of unrepaired assets would greatly
12 put line workers and the public at risk as minor asset failures begin to deteriorate pockets of
13 the distribution system, as well as decreasing the reliability of the distribution system.
14
15 Distribution System Reinforcements (July 2024-August 2025: $11,399,000, RY1:
16 $10,063,000,RY2: $10,719,000)
17 Avista's electric distribution system consists of 370 discrete primary electric circuits (feeders)
18 encompassing over 19,300 circuit miles of overhead conductors and underground cables,
19 along with the other equipment needed to operate an electric distribution system. Load
20 demands on the grid are dynamic with load patterns changing due to factors such weather,
21 temperature, economic conditions, conservation efforts, and seasonal variations. The
22 distribution grid is managed by division or `Operations Engineers' and centralized
23 Distribution Planning. The performance and capacity needs of this system are constantly
24 changing, and this business case is the main tool available to our Operations Engineers so that
25 they can keep up with these system demands. Most of the work completed with this business
26 case addresses capacity constraints driven by load growth, which we anticipate being higher
27 in coming years than historical growth rates, throughout the system.
28
29 The main driver for this business case is load growth on our electric distribution system. It is
30 primarily focused on ensuring that our electric distribution system can accommodate our load
31 growth. Our engineers are looking at the system as a whole and identifying the projects needed
32 that will keep the system operating within acceptable parameters. Other drivers for this
33 business case include power quality investigations and subsequent mitigation projects which
34 are initiated by customer inquiries or engineering analysis work. Work is also driven by
35 reliability, system performance issues, and safety concerns that are identified by our engineers
36 and/or operations personnel. Power quality, reliability and safety driven projects completed
37 through this business case are meant to mitigate code violations and observed system issues
38 that will help maintain adequate levels of service in these areas for our customers. Operational
39 flexibility can also drive the need to upgrade electric circuits,install switching equipment, and
40 other infrastructure as needed.
41
42 East CDA Lake Reinforcement Program (July 2024-August 2025: $243,000, RY1:
43 $694,000, RY2: $0)
44 The East Lake Coeur d'Alene System Reinforcement project provides additional capacity to
45 a system which is critical to serving our customers and unlocking pathways to growth. The
46 population and load demand growth on the east side of Lake Coeur D'Alene has caused Avista
47 concerns that we may not be able to reliably support new customers at the far-reaching end of
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Avista Corporation

I two distribution feeders. Currently,two distribution feeders serve the east shore of Lake Coeur
2 D'Alene, one originating from the Blue Creek Substation, and the other from the O'Gara
3 Substation. The feeders have reached their capacity and cannot support additional growth in
4 the area. A 13.2kV distribution system is constrained in serving long distances due to
5 protection coordination issues distinguishing fault current from load current. The consequence
6 customers will experience as a result of protection coordination is increased outages due to
7 fault detection devices tripping under heavy load conditions. Equipment capacity issues have
8 emerged, including overloaded feeder cable, voltage drop, voltage imbalance, reduced fault
9 current, overloaded fusing and feeder protection, and cold load pickup. To prevent
10 overloading equipment, Avista would need to disrupt service to customers to reduce loading
11 or risk the equipment becoming damaged, which would lead to longer outage duration for
12 customers.
13
14 Electric Relocation and Replacement Program (July 2024-August 2025: $9,968,000,
15 RY1: $6,960,000,RY2: $7,020,000)
16 Placement of the Company's electric facilities is generally located in easements provided in
17 public right of ways that are governed by jurisdictional franchise agreements.When requested
18 by the local jurisdiction, typically related to transportation projects, the Company must
19 relocate its facilities in the right of way to accommodate these projects. Avista is obligated
20 under terms of its franchise agreements to move its facilities at its own expense and within the
21 timeframe specified by the local jurisdiction. Using public rights-of-way for our many
22 thousands of miles of electric infrastructure provides a cost-effective way to serve our
23 customers, even considering the costs associated with the requirement for their periodic
24 relocation. Agreeing to move our facilities when requested is an important provision that
25 allows the Company to negotiate favorable franchise agreements, which in turn, allows us to
26 continue providing reliable service to our customers at an affordable cost. The need for electric
27 relocations and replacements is driven by the plans of our local jurisdictions, and as such, is
28 not an activity that Avista can anticipate in definitive terms,plan for, or manage like a project
29 internal to the Company. Accordingly, the annual spending levels can be quite variable so
30 Avista budgets for this activity in coming years based on the spending levels experienced in
31 the prior five-year period. The actual spending level each year is determined by the number
32 and size of projects the Company is required to complete.
33
34 Electric Storm (July 2024-August 2025: $2,836,000,RY1: $2,529,000,RY2: $2,529,000)
35 The Electric Storm investments cover the cost of restoring Avista's electric transmission,
36 substation, and distribution systems to serviceable condition when damaged during a
37 significant weather (storm) event or other natural disaster. These storm events include high
38 winds, heavy wet snow, ice, lightning strikes, flooding, and wildfire. Most of this damage
39 typically occurs on the Company's extensive electric distribution system, however, some
40 storm events also impact our electric transmission system. Significant storm events are best
41 understood as random forces6 that often occur with short notice and are beyond the control of
6 Though the incidence of major storm events can follow cyclical patterns based on season of the year,we refer
to them as random events because their occurrence,timing and magnitude cannot be predicted.
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Avista Corporation

I the Company.'
2
3 Investments made to restore our electric system after major events include replacement of
4 wood poles, crossarms, conductor, transformers, and customers' secondary service lines.
5 Making the area safe after an event, and quickly replacing damaged equipment is crucial to
6 promptly restoring service for our customers. The need for investments in infrastructure
7 restoration is difficult to predict year-to-year, requiring the Company to consider recent
8 history and long-term trends in setting forecast budgets for these types of investments.
9
10 Joint Use Projects (July 2024-August 2025: $4,530,000, RY1: $4,167,000, RY2:
11 $3,667,000)
12 Joint Use is the regulated use of utility poles and other structures by third-party
13 telecommunications companies in order for them to provide their services to the customers
14 we have in common.Avista licenses 73 unique entities that are attached to over 150,000 poles
15 across Avista's service territory and is required by federal, state, and local laws to allow non-
16 discriminatory access to those assets. Even though this relationship is mandated by law and is
17 compliance driven, Avista agrees that this practice provides a direct benefit to our customers
18 who desire those services. Part of this requirement includes the obligation of Avista to replace
19 infrastructure to taller stronger structures in order to accommodate or "make ready" those
20 facilities for new attachments. This make ready work falls under capital expense and Avista
21 is allowed to recover the actual costs from the requesting party. Avista is also allowed to
22 recover a portion of the cost of replacing & maintaining shared infrastructure via a regulated
23 yearly pole rental fee. This benefits our customers by offsetting the cost of upgrading
24 infrastructure,improving reliability,and ensuring telecommunications companies can provide
25 their services to our shared customers.
26
27 Meter Minor Blanket(July 2024-August 2025: $274,000,RY1: $250,000,RY2: $250,000)
28 The meter minor blanket is used to charge the labor associated with new electric meter
29 installations in Washington and Idaho,due to the replacement of failed plant(meters)that can
30 no longer gather or communicate accurate consumption data. Failed plant can occur for
31 various reasons including but not limited to, age, weather/environmental damage, hardware
32 failure, or radio communication failures. A meter must be installed as soon as possible to
33 accurately capture customer energy consumption data. For this reason, Avista must maintain
34 a continuous stock of each electric meter type, and budget the required labor to install these
35 meters. The Meter Minor Blanket is driven by tariff requirements that mandate Avista's
36 obligation to serve existing customer load within our franchised area.
37
38 Metro 115kV Substation(July 2024-August 2025: $3,990,000,RY1: $0,RY2: $9,315,000)
39 The Metro 115kV Substation serves the urban core of downtown Spokane and has done so
40 reliably for almost 50 years.Now this substation has components that are approaching the end
41 of life, equipment that no longer meets present safety standards,and a unique site that imposes
7 Beyond the control of the Company refers to the fact that these"outside forces"exceed the ability of our system
to withstand them without some resulting failures. While it is possible to have a system capable of better
withstanding these events it would require a substantial redesign of our system and massive capital investments
to rebuild it. One example of `system redesign' would be to convert substantial portions of our electric
distribution system from overhead to underground service where it would be relatively more immune to these
outside forces.
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Avista Corporation

I severe operational constraints. The existing transformers are 40+years old, are unique and do
2 not have spares, and lack the option of the mobile transformer at Metro. These constraints
3 threaten to create significant and extended customer outages in the event of major equipment
4 failure for a significant portion of the downtown area. This project will address both the
5 equipment and site issues in the most efficient and affordable way possible, based on the
6 alternatives and risk analysis performed for this substation that are detailed further in the
7 included Business Case. The result of this project will be a flexible and reliable station that
8 fulfills needs in multiple operating divisions. The new substation will provide safer
9 equipment, necessary redundancy, increased capacity, and a design that enables a longer
10 station lifespan where individual pieces of equipment can be safely serviced and upgraded
11 without prohibitive site/outage constraints.
12
13 Electric New Revenue-Growth(July 2024-August 2025: $78,190,000,RY1: $62,629,000,
14 RY2: $66,746,000)
15 Avista defines these investments as "customer requests for new service connections, line
16 extensions, transmission interconnections, or system reinforcements to serve a single large
17 customer." In the past we have referred to new service connects as "growth,"which refers to
18 growth in the number of customers Avista services. It's important to note that these
19 investments are beyond the control of the Company, and as such they do not reflect a plan or
20 strategy on the part of Avista. Typical projects include installing electric to new housing or
21 commercial developments, installing or replacing electric meters, or adding street or area
22 lights at the request of a customer, city, or county agency. As would be expected, fluctuation
23 in the number of new customer connections is largely dependent on local economic conditions
24 both in the housing and business sectors. The Company has included Idaho electric offsetting
25 revenues of $3,296,000 in Rate Year 1 in Adjustments 3.10 and offsetting revenues of
26 $1,716,000 in Rate Year 2 in Adjustment 26.05.
27
28 Substation — Asset Condition (July 2024-August 2025: $26,781,000, RY1: $19,003,000,
29 RY2: $6,895,000)
30 The Substation Asset Condition Business Case is comprised of three Projects. The first
31 includes major equipment spares (power transformers, high voltage breakers, etc.) that are
32 held in stock until they are transferred to a location. The second includes major substation
33 projects that contain multiple equipment asset condition issues, compliance updates and
34 capacity upgrades. A substation rebuild is planned when several equipment types are at end
35 of life. These projects also include significant Distribution system, Transmission system and
36 Communication system work. The third includes small substation projects(single transformer
37 replacements, regulator upgrades, etc.) that have been deemed necessary due to asset
38 conditions, leading to imminent equipment failure. Equipment failures for capital items that
39 have been run to failure are funded through this project. In the end, substation equipment
40 needs to be replaced when it fails to fulfill its intended function and may also need to be
41 replaced when it has become obsolete. Obsolete equipment is due to parts or software not
42 being available to maintain a piece of equipment.
43
44 Substation — Performance and Capacity (July 2024-August 2025: $15,594,000, RY1:
45 $11,517,000, RY2: $14,660,000)
46 Avista actively monitors the customer loads placed on its energy delivery systems, identifies
47 portions of its infrastructure where capacity has been reached or exceeded, evaluates options
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Avista Corporation

I for best addressing these priority capacity constraints and invests in solutions to ensure we
2 meet current and long-term customer needs. This program is focused on investments needed
3 to add new electrical capacity to our distribution substations in response to growth in demand
4 on the feeders supported by these stations. Beyond just meeting capacity requirements these
5 investments provide Avista with greater operational flexibility, ease of maintenance, and
6 electric service reliability for our customers.
7
8 Substation Failed Plant (July 2024-August 2025: $1,000,000, RY1: $1,500,000, RY2:
9 $1,500,000)
10 The Substation — Failed Plant Business Case is focused on restoring Avista's substation
11 systems into serviceable condition after equipment fails due to animal `contact', lightning, or
12 other sudden equipment failures. These equipment failure events are random and cannot be
13 planned. This business case funds a rapid response to unexpected damage, so customer
14 outages are minimized. In the past, these replacements were completed under the Substation
15 —Asset Condition Business Case, but better overview and tracking was desired by Electrical
16 Engineering. Therefore, a decision was made to create a separate business case for more
17 visibility into any substation equipment failures or possible equipment manufacturer/model
18 issues that occurred. Future maintenance practices and programs will also be reviewed in light
19 of these equipment failures. The importance of quickly replacing damaged equipment is vital
20 to supplying reliable service to our customers. This affects electrical customers in
21 Washington, Idaho, and Montana.
22
23 Distribution Wood Pole Management (July 2024-August 2025: $8,797,000, RY1:
24 $11,573,000,RY2: $12,577,000)
25 Avista has approximately 240,000 wood poles'in its electric distribution system and a portion
26 of these must be replaced each year due to asset condition. These are replacement of poles
27 and attachments that have reached the end of their useful service life. Our wood poles are
28 inspected on an approximate 20-year cycle, resulting in the inspection of approximately
29 12,000 poles each year.9 Individual poles or attached equipment that don't meet our inspection
30 requirements are replaced as part of capital follow-up work. Attached equipment includes
31 overhead distribution transformers, cutouts, insulators and pins, wildlife guards, lightning
32 arresters, cross arms, pole guying, and grounds. The primary alternative to this proactive
33 inspection and replacement program is to simply replace poles as they fail in service and fall
34 down (asset strategy known as "run to fail"). Sub-alternatives evaluated include inspecting
35 the pole population on a cycle time either shorter or longer than the current 20-year cycle.
36
37 IV. INVESTMENTS IN THE COMPANY'S ELECTRIC TRANSMISSION SYSTEM
38 Q. Would you please summarize the need for continuing investments in
39 electric transmission infrastructure?
' Under the current inspection program, individual poles are validated by location, age, and material in our
geographic information system,leading to an overall refinement in the population size.
9 Avista's Wood Pole Inspection Program is funded as an expense.
DiLuciano, Di 13
Avista Corporation

I A. The nation's electric utilities are facing unprecedented challenges from many
2 forces that are driving the continuing need for new investment in transmission infrastructure,
3 and Avista is no different. This rapidly growing demand for new investment has challenged
4 our ability to fund all our high priority needs for electric transmission, which are out of
5 proportion to the investment requirements of our other infrastructure. Drivers for new
6 investment include:
7 • System improvements required to meet the myriad and expanding federal regulations
8 governing nearly every aspect of our transmission business. Specifically, the
9 tightening requirements to meet increasingly restrictive transmission operations and
10 planning standards that could potentially result in financial penalties for
11 noncompliance.
12
13 • Timely replacement of end-of-life assets based on condition. This need is at an all-
14 time high across the industry and will continue to increase annually for at least the
15 next two decades. This need is tied to the major expansion of new electric
16 infrastructure built during the economic boom following the end of World War II.
17 Because these assets are now at or near the end of their useful lives, a substantial boost
18 in new investment is required to maintain existing systems.
19
20 • External demands on our transmission system including new transmission
21 interconnections required for third parties to integrate new variable energy resources,
22 particularly wind and solar. These interconnections require significant capital
23 investment to extend or reinforce our transmission system and often take priority over
24 investments required to provide for native load service on our system.
25
26 • A further driver is related to supporting the development of the new energy services
27 grid of the future. Emerging technologies are driving an increase in digitization,
28 distributed generation, energy storage, and other technologies that require adapting
29 and upgrading the existing system, including new ways of engaging with our
30 customers. Though primarily focused on the distribution level, these changes in our
31 energy delivery business model also impact transmission investments. This increased
32 digitalization brings with it the potential for greater cyber vulnerability and the need
33 for continuing investment to provide for the safety and security of our bulk power
34 system.
35
36 • Siting, permitting, and constructing transmission assets has become more complex,
37 time-consuming, and expensive. This is due, in part, to increasing environmental
38 regulation, property rights, and land-use requirements. Permitting can extend over
39 several years and typically includes conditions constraining how utilities site, design,
40 construct and maintain these assets.
DiLuciano, Di 14
Avista Corporation

I When it comes to the impact on our customers, who must ultimately pay for these
2 requirements and investments, an exacerbating factor is our relatively low load growth due to
3 declining use-per-customer, over time. This translates into nearly flat revenues, which means
4 that new capital investments must be covered by higher customer rates.
5 Q. Please describe the Company's process for ensuring it is making timely
6 investments in electric transmission to maintain compliance with mandatory federal
7 standards.
8 A. The Company's process for determining which projects should be
9 recommended for funding each year includes results of comprehensive planning studies,
10 engineering and asset management analyses, and scheduled upgrades and replacements
11 identified in our operations districts and Transmission Engineering. These projects undergo
12 internal review by multiple stakeholders, who help ensure all system needs and alternatives
13 have been identified and evaluated.
14 As discussed by Mr. Christie, projects advanced for funding enter a formal review
15 process referred to as the Engineering Roundtable. This group carefully reviews the need for
16 each project,the primary business driver, the alternatives considered, and the justification for
17 the approach recommended. During the review, the potential benefits of any cross-business-
18 unit synergies that could better optimize project benefits and scope are also identified and
19 evaluated. The result of this process is a prioritized list of recommended projects that serves
20 as a roadmap of investments, sequenced by year, for at least a ten-year timeframe. Using this
21 roadmap, each department can plan ahead for the work they will be responsible to execute
22 once projects are approved for funding and implementation. Once evaluated, prioritized, and
23 sequenced, these projects are recommended to the Capital Planning Group (discussed by Mr.
24 Christie) for final review and funding allocation. Representatives from eleven business units
DiLuciano, Di 15
Avista Corporation

I participate in the Engineering Roundtable process.
2 Q. Would you please summarize the capital investments in electric
3 transmission plant completed in 2024 and planned for over the Two-Year Rate Plan?
4 A. Yes, the completed and planned investments related to transmission
5 investment,presented on a system basis, are shown in Table No. 3, and described below. See
6 also the detailed narrative for each electric transmission Business Case at Exhibit No. 10,
7 Schedule 3, pages 171 —272.
8 Table No. 3 —Electric Transmission Capital Proiects (System)
9 Electric Transmission Capital Projects(System)In$(000's)
10 Rate Year 1 Rate Year 2
Line July 2024- Sept 2025- Sept 2026-
1 1 # Business Case Name Investment Driver August 2025 Aug2026 Aug2027
12
13 1 Ambient-Adjusted Transmission Line Ratings Mandatory&Compliance $ - $ 1,200 $
14 2 Colstrip Transmission Mandatory&Compliance 1,251 1,094 588
3 Electric Storm Faded Plant&Operations 1,931 1,471 1,471
15 4 SCADA-SOO and BuCC Asset Condition 960 1,011 1,148
16 5 Substation-West Plains System Reinforcement Project Mandatory&Compliance 1,667 3,592 37,992
17 6 Transmission-Minor Rebuild Asset Condition 5,494 4,000 4,000
18 7 Transmission Construction-Compliance Mandatory&Compliance 382 500 500
8 Transmission Critical Crossing Reinforcement Asset Condition 500 - -
19 9 Transmission Major Rebuild-Asset Condition Asset Condition 7,817 4,303 3,789
20 10 Transmission NERC Low-Risk Priority Lines Mitigation Mandatory&Compliance 3,051 - -
21 11 Westside 230/115kV Station Brownfield Rebuild Project Mandatory&Compliance 2,978 - -
22 Total Planned Electric Transmission Capital Projects $ 26,030 $ 17,171 $ 49,489
23
24
25 Ambient-Adjusted Transmission Line Ratings (July 2024-August 2025: $0, RY1:
26 $1,200,000,RY2: $0)
27 This business case provides for engineering and deployment of new applications and
28 technology as required to address FERC Order 881 regulatory and business requirements.
29 FERC Order 881,issued on December 16,2021,requires transmission providers to implement
30 and use ambient-adjusted ratings (AARs) for transmission lines used in providing
31 transmission service by 2025. These AARs ensure that line ratings align closely with actual
32 operating conditions. The goal is to utilize the transmission grid and lower costs more
33 efficiently for consumers by improving the accuracy and transparency of line ratings.
34 Transmission providers were required to submit compliance filings within 120 days of the
35 effective date of the rule, and all requirements in this rule were to be implemented no more
36 than three years from the compliance filing due date.
37
38 Colstrip Transmission Operation and Maintenance(July 2024-August 2025: $1,251,000,
39 RY1: $1,094,000, RY2: $588,000)
DiLuciano, Di 16
Avista Corporation

I Avista is a joint owner in the 500kV Colstrip Transmission System and is obligated under the
2 agreement to fund its commensurate share of necessary construction and maintenance
3 programs. Examples of recent and pending capital expenditures in the Colstrip Transmission
4 System include microwave communication upgrades,replacement of original remedial action
5 scheme, and ballistic substation protection.
6
7 Electric Storm (July 2024-August 2025: $1,931,000, RYl: $1,471,000, RY2: $1,471,000)
8 Please see this program above (titled the same) under electric distribution plant for the
9 description of the Company's investments under the category of electric storms. This capital
10 business case is similar in all respects to the program for electric distribution repair except it
11 is focused on repairs to our electric transmission system.
12
13 SCADA—System Operations Office&Backup Control Center (July 2024-August 2025:
14 $960,000, RY1: $1,011,000, RY2: $1,148,000)
15 The Company increasingly relies on comprehensive digital monitoring of critical power
16 system infrastructure and communication interconnectivity that provides real-time visibility,
17 status, and the ability for remote and automated operations. Avista relies on the industry-
18 standard system known as Supervisory Control and Data Acquisition(or SCADA)to provide
19 this functionality.10 The Company is required to continuously upgrade and enhance its
20 SCADA systems to replace end-of-life technology and to meet expanding regulatory
21 requirements and business needs. This particular project is replacing and upgrading existing
22 SCADA communications for our electric and natural gas control centers. The control systems
23 addressed under this program provide real-time visibility, situational awareness, remote
24 operation, and control of these systems. The investments made in our SCADA systems ensure
25 we can continue to operate our energy delivery systems safely and remain in compliance with
26 a broad range of FERC orders, NERC standards, and federal pipeline safety requirements
27 under PHMSA.
28
29 Substation — West Plains System Reinforcement Project (July 2024-August 2025:
30 $1,667,000,RY1: $3,592,000, RY2: $37,992,000)
31 The West Plains area load has increased in the past few years and continues to grow at a rate
32 outpacing Avista's average service territory load growth rate. Between 2018-2022,a 3 -3 1/2%
33 growth rate has been observed and is forecasted to continue for the next 5-10 years. The
34 growth has strained the transmission system to the extent that system reliability cannot be
35 maintained while accommodating system outages as required under applicable operational
36 performance requirements and NERC TPL-001-5. Government, tribal, public, and private
37 entities have invested significant time and money in the area and are working to establish area
38 backbone infrastructure. Avista is being asked to join these efforts by readying and fortifying
39 the electric grid to accommodate future expanding economic development. The West Plains
40 area requires a new 230kV source into the area to support the system and improve reliability
41 and operability while offloading existing 230/115kV transformers in Spokane. The new
42 230kV source will improve contingency situation results and give increased ability to meet
43 existing and future customer demand. The project will reduce the potential of customer
io SCADA, and extension of industrial process control, has been around since the early 1960s, and the term
"SCADA"became commonly used by the mid-1970s.SCADA systems,naturally,have evolved through several
major generations as computing and communications technologies have evolved and advanced.
DiLuciano, Di 17
Avista Corporation

I outages under heavy summer loading scenarios. Without the project, customers may have
2 power turned off under certain outage combination conditions. The scope of the project
3 includes a new 230/115kV station near the West Plains at Garden Springs,new 230kV station
4 to interconnect with the Bonneville Power Administration called Bluebird, and a new 12-mile
5 230kV transmission line. The new infrastructure is major investment in the transmission
6 system which is needed to serve our customers.
7
8 Transmission Minor Rebuild (July 2024-August 2025: $5,494,000, RY1: $4,000,000,
9 RY2: $4,000,000)
10 This Business Case covers the Transmission rebuild and reconductor work necessary to
11 maintain compliance with the North American Electric Reliability Corporation (NERC)
12 Reliability Standard FAC-501-WECC-1 as applied through Avista's Transmission
13 Maintenance Inspection Program (TMIP). These standard mandates that specific
14 Transmission lines be inspected annually and assessed for corrective actions to be
15 implemented to remedy any system performance deficiencies. During routinely scheduled
16 inspections, issues are discovered regarding the condition of assets, including items such as
17 rotten poles, broken/split/rotten crossarms, broken conductor or ground/shield wire, and air
18 switches that no longer operate safely or reliably. The TMIP applies the same inspection
19 methodology to the entire Avista system with the understanding that only a portion of the
20 mitigation work is recognized as Mandatory and Compliance. The remaining work undertaken
21 within this Business Case is recognized as Customer Requested, Failed Plant and Asset
22 Condition.
23
24 Transmission Construction — Compliance (July 2024-August 2025: $382,000, RY1:
25 $500,000, RY2: $500,000)
26 This program covers the transmission rebuild and reconductor work identified by the
27 Company as necessary to maintain compliance with the NERC reliability standards." The
28 applicable standard requires Avista to complete an annual planning assessment, to identify
29 shortfalls and corrective actions, and for those actions to be timely implemented within
30 specific timeframes to remedy identified system performance deficiencies. Avista's
31 Transmission Construction - Compliance Program identifies funding needed to mitigate
32 identified reliability issues, ensuring our compliance with NERC requirements. In addition to
33 meeting NERC standards, this program also includes construction to remedy issues on any
34 transmission line that is not compliant with the current capacity criteria under the National
35 Electric Safety Code (NESC).
36
37 Transmission — Critical Crossing Reinforcement (July 2024-August 2025: $500,000,
38 RY1: $0,RY2: $0)
39 The Transmission Critical Crossing Reinforcements Business Case identifies high failure
40 consequence asset/structure locations;that,if subject to failure,would create life loss or injury
41 conditions. Avista is dedicated to providing safe and reliable service to our customers,
42 ensuring failures that could lead to these conditions are avoided; and that trust with Avista's
11NERC Reliability Standard TPL-001-4 — Transmission System Planning Performance Requirements
("Standard"), has 8 requirements and 57 sub-requirements related to planning and analysis, including the
requirement for robust system models to determine system stability, voltage levels and system performance
under various scenarios.
DiLuciano, Di 18
Avista Corporation

I service territory community remains. These locations are specifically highway, railway, and
2 waterway crossings.
3
4 Transmission Major Rebuild - Asset Condition (July 2024-August 2025: $7,817,000,
5 RY1: $4,303,000,RY2: $3,789,000)
6 This program provides for the major rebuild of electric transmission lines that are nearing the
7 end of their useful service life based on overall condition of the assets, the rating probability
8 of a failure, and magnitude of the consequence. Factors such as operational issues, ease of
9 access during outages; and potential benefits of communications build-out are considered
10 when planning and prioritizing the work to be completed. This business case results in direct
11 offsets to O&M by eliminating unplanned outages. The annual system estimated value of these
12 Direct Offsets is expected at $10,000 beginning in 2025. Idaho's share is included in the
13 Company's revenue requirement as a reduction in expense within pro forma Adjustment 3.10.
14
15 Transmission — NERC Low-Risk Priority Lines Mitigation (July 2024-August 2025:
16 $3,051,000,RYl: $0, RY2: $0)
17 Avista's compliance with this mandatory standard requires that we conduct LiDAR surveys 12
18 on all subject transmission circuits to determine any discrepancies between the design
19 specifications and field measurements for conductor sag.13 While the subject NERC standard
20 was offered as a recommendation to the industry, our compliance with minimum clearance
21 requirements is also required by the National Electric Safety Code. NERC, however, is also
22 closely monitoring the progress made by each utility in complying with these requirements,
23 via a required status report filed with them every six months by each subject utility. When
24 Avista identifies discrepancies through the surveys it evaluates a range of actions to be taken
25 to ensure we meet the stated clearance requirements. The actions include reconfiguring
26 insulator attachments, rebuilding or replacing structures and removing earth below the span
27 of line in question.
28
29 Westside 230/115kV Station Rebuild(July 2024-August 2025: $2,978,000,RY1: $0,RY2:
30 $0)
31 A P1 is a single element failure where we lose one of the two 230/115 kV autotransformers.
32 The existing Westside#1 230/115 kV transformer exceeds its applicable facility rating for the
33 P1 event of the Westside#2 230/115 kV transformer. System performance analysis indicated
34 an inability of the system to meet the performance requirements in Table 1 of NERC TPL-
35 001-4 in scenarios representing 2017 Heavy Summer for P1 events. The problem prior to
36 construction at the Westside Substation was that a P1 resulted in another element exceeding
37 its rated capacity, which is not allowable under NERC TPL-001-4. We mitigated this issue
38 by replacing the transformers with larger-capacity units. In order to facilitate these
39 replacements, construction in the surrounding station also took place. The end result included
40 necessary adjacent upgrades to connect the autotransformers, including increased
12 Light Detection and Ranging(LiDAR)is a method of measuring distances(ranging)by illuminating a target
with laser light and measuring the reflection with a sensor.Differences in in laser light return times to the sensor
and wavelengths are used to create a digital three-dimension representation of the target. Typically conducted
on electric transmission by aerial flights.
" Sag refers to the lowest point (closest to the earth) of the electrical conductor between any two supporting
structures(poles),measured as the vertical distance from the top of the supports to the lowest hanging point of
the conductor between them.
DiLuciano, Di 19
Avista Corporation

I switching/bus-work capacity,and more reliable and functional protection schemes. While the
2 site is now technically in compliance with the NERC TPL standard,the adjacent construction
3 work to match switching and bus capabilities to the new transformers is still finishing up in
4 2024.
5
6 IV. INVESTMENTS IN THE COMPANY'S NATURAL GAS SYSTEM
7 Q. Please summarize the need for ongoing investment in Avista's natural gas
8 distribution system.
9 A. In 2023,natural gas was the top source and provided the fuel for approximately
10 43% of the nation's electric generation fleet,14 it heats more than half of America's homes,
11 and provides the vital energy for cooling, heating, industrial processes, commerce, and
12 industry. The Company has experienced steady growth in natural gas customers in the prior
13 decade. In recent years, the annual number of new connects has remained steady with an
14 average of 4,644 over the last five years, with a five-year average of 1,979 in the State of
15 Idaho. The increase in new customers has required continuing investment in new connects, in
16 addition to investments to provide the capacity requirements needed to serve increasing loads.
17 Another substantial driver for new investments is maintaining compliance with federal
18 and state regulatory requirements and effectively managing the safety risks associated with
19 our natural gas distribution system. Over the last decade, the Company's investments to meet
20 customer requests for new service and to comply with a range of growing regulatory
21 obligations has grown from approximately $15.5 million in 2010 to nearly $59 million in
22 2024.
23 Q. Would you please summarize the capital investments in natural gas
24 infrastructure completed in 2024 and planned for over the Two-Year Rate Plan?
25 A. Yes, the completed and planned investments related to natural gas
14 https://www.eia.aov/energyeMlained/electricii /electricity-in-the-us.php
DiLuciano, Di 20
Avista Corporation

I infrastructure, presented on a system basis, and grouped by investment driver, are shown in
2 Table No. 4, and described below. See also the detailed narrative for each electric
3 transmission Business Case at Exhibit No. 10, Schedule 3,pages 273 - 415.
4 Table No. 4-Natural Gas Capital Projects (System)
5 Natural Gas Distribution Capital Projects(System)In$(000's)
Rate Year 1 Rate Year 2
Line July 2024- Sept 2025- Sept 2026-
6 # Business Case Name Investment Driver August 2025 Aug 2026 Aug 2027
1 Gas Above Grade Pipe Remediation Program Mandatory&Compliance $ 738 $ 657 $ 643
7 2 Gas Cathodic Protection Program Mandatory&Compliance 757 1,002 600
Gas Facility Replacement Program(GFRP)Aldyl A Pipe
8 3 Replacement Mandatory&Compliance 30,530 28,265 29,682
4 Gas Isolated Steel Replacement Program Mandatory&Compliance 2,440 2,000 2,000
5 Gas Non-Revenue Program Failed Plant&Operations 11,419 10,850 11,437
9 6 Gas PMC Program Mandatory&Compliance 4,205 3,810 3,670
7 Gas Regulator Station Replacement Program Asset Condition 1,094 1,051 1,050
10 8 Gas Reinforcement Program Performance&Capacity 5,020 1,115 1,025
9 Gas Replacement Street and Highway Program Mandatory&Compliance 5,427 5,665 5,757
10 Gas Telemetry Program Performance&Capacity 98 - -
1 1 11 Gas Transient Voltage Mitigation Program Mandatory&Compliance 1,165 154 313
12 Jackson Prairie Natural Gas Storage Facility Performance&Capacity 2,256 2,386 2,376
12 13 New Revenue-Growth Customer Requested 30,723 25,016 25,333
Total Planned Natural Gas Distribution Capital Projects $ 95,873 $ 81,971 $ 83,886
13
14 Gas Above Grade Pipe Remediation Program (July 2024-August 2025: $738,000, RY1:
15 $657,000, RY2: $643,000)
16 Within Avista's natural gas distribution system there are sections of gas pipelines located
17 above grade at locations such as bridges, small ditches, irrigation canals, and other crossings
18 where it is difficult to install buried pipelines. These above grade facilities vary in age,
19 condition, design, compliance, and overall risk. The Company's investment in the Gas Above
20 Grade Remediation Program provides capital funding for remediating the highest risk
21 locations that cannot be sufficiently mitigated or resolved through O&M maintenance
22 activities(e.g.pipe support replacement,coating/wrap repairs, etc.). This business case results
23 in direct offsets to O&M due to the reduction in maintenance and patrols required. The annual
24 natural gas system estimated value of these Direct Offsets is expected at $7,983 in 2024,
25 $7,983 in 2025, $9,677 in 2026 and$11,371 in 2027. Idaho's share is prorated over the Two-
26 Year Rate Plan and included in the Company's revenue requirement as a reduction in expense
27 within pro forma Adjustments 3.10 (Rate Year 1) and 26.05 (Rate Year 2).
28
29 Gas Cathodic Protection Program (July 2024-August 2025: $757,000, RY1: $1,002,000,
30 RY2: $600,000)
31 Avista uses cathodic protection anode systems to reduce corrosion on buried steel gas piping.
32 There are approximately 250 anode systems in use throughout our service territory. The
33 anodes used in these systems corrode over time and need to be replaced every 20 -30 years.
34 Additionally, as pipe coating degrades over time, additional anode systems must be added.
DiLuciano, Di 21
Avista Corporation

I The investments made under this program include installing new and replacement anodes and
2 electronic equipment used to remotely control and monitor the anode systems. Providing
3 cathodic protection for our steel natural gas piping protects our community from the potential
4 consequence of leaks on our system and helps ensure they receive the full lifecycle value of
5 the investments made in our natural gas. Besides a prudent business practice, Avista is
6 mandated by the U.S. Department of Transportation to provide effective cathodic protection
7 for its steel natural gas pipelines. Since cathodic systems can have variable service lives,
8 depending on local soil conditions and the propensity for corrosion, and because all the
9 component parts are buried in the earth,the only way to determine whether a system needs to
10 be replaced is through annual performance monitoring. It is often difficult to predict in
11 advance when a specific replacement will be required so the amount of replacement work
12 experienced each year across our system can be somewhat variable. Therefore, the annual
13 funding for this program in future years is based on Avista's experience in prior years.
14
15 Gas Facility Replacement Program (GFRP) Aldyl A Pipe Replacement (July 2024-
16 August 2025: $30,530,000, RY1: $28,265,000, RY2: $29,682,000)
17 The Aldyl A Pipe Replacement Program15 is a 20-year structured pipe replacement effort with
18 dedicated internal and external resources focused on reducing natural gas system risk, on a
19 prioritized basis, by replacing priority Aldyl A pipe throughout Avista's natural gas
20 distribution system. The program was initiated in 2011 and was slated to be completed by
21 2032. However, this timeframe has been extended in Idaho to 2037 due to decreased risk in
22 our most recent analysis. This is due in part to the reduction of slow crack growth failures in
23 Idaho coupled with the number of failures in Washington remaining steady, despite nearly
24 half of the Aldyl-A pipe having been replaced since the program's inception. Extending
25 Avista's Aldyl-A replacement work in Idaho to 2037 will allow us the opportunity to balance
26 affordability and overall impact to our customers with the more recent risk analysis. The work
27 under this business case results in direct O&M offsets due to the reduction in necessary leak
28 surveys. The annual natural gas system estimated value of these Direct Offsets is expected at
29 $1,465 in 2024, $1,604 in 2025, $4,129 in 2026 and$7,495 in 2027. Idaho's share is prorated
30 over the Two-Year Rate Plan and included in the Company's revenue requirement as a
31 reduction in expense within pro forma Adjustments 3.10 (Rate Year 1) and 26.05 (Rate Year
32 2).
33
34 Gas Isolated Steel Replacement Program (July 2024-August 2025: $2,440,000, RY1:
35 $2,000,000,RY2: $2,000,000)
36 Related to our cathodic protection systems,the Company is required to identify portions of its
37 natural gas system where we have "cathodically isolated" sections of steel piping, including
38 natural gas service risers, and to replace them with non-corrosive pipe within a specified
39 timeframe.Isolated steel sections are just that,they are electrically separated from the cathodic
40 protection system by sections of non-corrosive (plastic) pipe or by fittings that are insulated
41 and prohibit the transmission of cathodic protection. Because these sections are not connected
42 to the cathodic protection system, they are not afforded the extra level of protection beyond
is This pipe replacement program is managed by the Company's Gas Facility Replacement Program, which is
the organizational program responsible for managing all aspects of replacement planning and execution of all
individual replacement projects.Multiple individual projects are carried out across our natural gas service area
each year. For a detailed description of this program, please see Avista's Priority Aldyl A Protocol Report,
provided as Exhibit No. 10, Schedule 1.
DiLuciano, Di 22
Avista Corporation

I their protective coating. Identifying and replacing isolated steel sections of pipe is required by
2 federal and state regulations.16
3
4 Gas Non-Revenue Program (July 2024-August 2025: $11,419,000, RY1: $10,850,000,
5 RY2: $11,437,000)
6 The work in this annual program is mostly reactionary, unscheduled work and is therefore
7 difficult to predict aside from using historical trends. The following situations are typical
8 triggers for such work: shallow facilities found by excavation(the excavation may or may not
9 be related to gas construction), relocation of facilities as requested by customers (except for
10 road and highway relocations), leak repairs on mains or services, remediation of cathodic
11 protection (CP) issues, farm tap elimination, and overbuilds. Gas Engineering is responsible
12 for projects under the Gas Non-Revenue program that require substantial design efforts such
13 as farm tap retirements,highway, or river crossings, and replacing steel pipelines with plastic
14 pipe, but it's the local districts that manage the work.
15
16 Gas PMC Program (July 2024-August 2025: $4,205,000, RY1: $3,810,000, RY2:
17 $3,670,000)
18 Avista is required by Commission rules and tariffs in its three state jurisdictions to annually
19 test a portion of its natural gas meters for accuracy, and to ensure overall meter performance.
20 This program is known as the Planned Meter Changeout Program(PMC)and uses a statistical
21 sampling methodology17 to determine the number of meter changeouts that must be completed
22 each year. If samples from a meter "family" are not meeting accuracy standards, then the
23 Company will remove that population of meters from service. Conversely, if the results meet
24 our standards of accuracy, then the sample size for that meter family may be reduced in the
25 future. These analytics help control costs and remove meters quickly when not performing
26 well.
27
28 Gas Regulator Station Replacement Program(July 2024-August 2025: $1,094,000,RY1:
29 $1,051,000,RY2: $1,050,000)
30 This program addresses needed replacements of existing `at-risk' natural gas gate stations,
31 regulator stations and industrial customer meter sets ("stations") located across Avista's
32 natural gas service territory. The stations set to be replaced have reached the end of their useful
33 service life, failed to meet the Company's current natural gas standards, and can no longer be
34 properly maintained because of obsolete equipment. These replacements improve system
35 operating performance, enhance operating safety, remove operating equipment that is no
36 longer supported, and ensure the reliable operation of metering and regulating equipment.
37 This business case results in direct offsets to O&M due to the reduction time needed for station
38 maintenance. The annual natural gas system estimated value of these Direct Offsets is
39 expected at$3,400 in 2024, $5,300 in 2025, $7,200 in 2026 and$9,300 in 2027. Idaho's share
40 is prorated over the Two-Year Rate Plan and included in the Company's revenue requirement
41 as a reduction in expense within pro forma Adjustments 3.10 (Rate Year 1) and 26.05 (Rate
42 Year 2).
43
44 Gas Reinforcement Program (July 2024-August 2025: $5,020,000, RY1: $1,115,000,
16 Docket PG-100049.
17 ANSI Z1.9"Sampling Procedures and Tables for Inspection by Variables for Percent Nonconforming."
DiLuciano, Di 23
Avista Corporation

I RY2: $1,025,000)
2 This annual program will identify and provide for necessary capacity reinforcements to the
3 existing natural gas distribution system in Washington, Idaho, and Oregon. Avista has an
4 obligation to serve existing gas customers by providing adequate capacity on design day
5 weather conditions.The design day is defined as the 30-year coldest average daily temperature
6 of a weather region,with 99%probability of happening. Periodic reinforcement of the system
7 is required to reliably serve customers due to increased demand at existing service locations
8 and new customers being added to the system. Execution of this program on an annual basis
9 will ensure the continuation of reliable gas service that is of adequate pressure and capacity.
10 This business case results in direct offsets to O&M due to the reduction in activation of the
11 Cold Weather Action Plan. The annual natural gas system estimated value of these Direct
12 Offsets is expected at $22,800 beginning in 2024. Idaho's share of is included in the
13 Company's revenue requirement as a reduction in expense within pro forma Adjustment 3.10
14 (Rate Year 1).
15
16 Gas Replacement Street and Highway Program (July 2024-August 2025: $5,427,000,
17 RYl: $5,665,000,RY2: $5,757,000)
18 Nearly all Avista's natural gas pipelines are located in public utility easements set aside for
19 this purpose, which are controlled by jurisdictional franchise agreements. Avista is required
20 under these agreements to relocate its facilities, at our cost, when local jurisdictional projects,
21 typically transportation, require the move. In some instances, the Company will have a
22 substantial lead time to plan,budget,design,and permit for the move,but in most cases,we're
23 notified of the need to move during the year the project must be completed. Due to the
24 unpredictability of this work, historical averages are used to determine the necessary budget.
25
26 Gas Telemetry Program (July 2024-August 2025: $98,000,RY1: $0,RY2: $0)
27 This investment provides funding for additions, improvements, and replacements to Avista's
28 existing Gas Telemetry system. Telemetry facilities include flow computers, electronic
29 volume correctors, and electronic pressure monitors. The Gas Telemetry System provides
30 safety related pressure monitoring and alarms at gate stations, regulator stations, pipelines,
31 odorizers, and transportation customers. This data is critical for gas procurement, billing,
32 engineering analysis, system operations and compliance with Federal Codes.
33
34 Gas Transient Voltage Mitigation Program (July 2024-August 2025: $1,165,000, RYl:
35 $154,000, RY2: $313,000)
36 Avista has experienced safety issues including fires at Gas Regulator Stations due to transient
37 voltage spikes from faults on the adjacent electric transmission system. The purpose of this
38 program will be to identify high pressure gas piping systems that are at risk of these conditions,
39 identify systems that have high steady state voltage, and to then install mitigation measures to
40 reduce both these scenarios on the pipelines. These efforts will protect the pipeline and
41 equipment from being damaged and reduce the voltages exposure to below compliance limits
42 keeping our employees safe. Common approaches to this include the installation of gradient
43 mats, solid state decouplers (SSD), and copper counterpoise conductor. This business case
44 results in direct offsets to O&M due to the reduction in labor for safety procedures and labor
45 and materials for the response to fault damage events needing repairs. The annual natural gas
46 system estimated value of these Direct Offsets is expected at$8,500 in 2024, $8,700 in 2025,
47 $9,000 in 2026 and $9,300 in 2027. Idaho's share is prorated over the Two-Year Rate Plan
DiLuciano, Di 24
Avista Corporation

I and included in the Company's revenue requirement as a reduction in expense within pro
2 forma Adjustments 3.10 (Rate Year 1) and 26.05 (Rate Year 2).
3
4 Jackson Prairie Natural Gas Storage Facility(July 2024-August 2025: $2,256,000,RY1:
5 $2,386,000,RY2: $2,376,000)
6 Avista is one third joint owner in the Jackson Prairie Natural Gas Storage Project and has long
7 relied on this asset to optimize gas prices and supply for the benefit of its customers. Like any
8 asset, investments must be made in the facility each year to ensure the integrity of its safe,
9 efficient, and cost-effective operation. Avista participates with its joint owners to identify and
10 vet upcoming capital needs and to approve annual investments to be made in the facility.
11 Company witness Mr. Kinney provides further information regarding Avista's ownership in
12 Jackson Prairie.
13
14 Gas New Revenue - Growth (July 2024-August 2025: $30,723,000, RY1: $25,016,000,
15 RY2: $25,333,000)
16 Avista defines these investments as "customer requests for new service connections, line
17 extensions, transmission interconnections, or system reinforcements to serve a single large
18 customer." In the past we have referred to new service connects as "growth,"which refers to
19 growth in the number of customers Avista services. It's important to note that these
20 investments are beyond the control of the Company, and as such they do not reflect a plan or
21 strategy on the part of Avista. Typical projects include installing gas facilities to new housing
22 or commercial developments or installing or replacing gas meters at the request of a customer,
23 city, or county agency. As would be expected, fluctuation in the number of new customer
24 connections is largely dependent on local economic conditions both in the housing and
25 business sectors. The Company has included Idaho natural gas offsetting revenues of
26 $1,384,000 in Rate Year 1 in Adjustment 3.10 and offsetting revenues of$732,000 in Rate
27 Year 2 in Adjustment 26.05.
28
29
30 IV. INVESTMENTS IN THE COMPANY'S OPERATIONS, FACILITIES AND
31 FLEET RESOURCES
32
33 Q. Please summarize the need for ongoing investment in Avista's operations,
34 facilities and fleet resources.
35 A. Adequate operating facilities are a critical ingredient to the success of utilities
36 like Avista. Avista's operating facilities encompass office space, critical information
37 technology systems, generation facilities, and are the hub for field operations. Our fleet
38 infrastructure includes a wide range of light to heavy trucks specialized for electric and natural
39 gas operations,diverse and specialized equipment,all manner of tools, and extensive material
40 and supply storage areas. Though it is easy to take for granted, our office and operations
DiLuciano, Di 25
Avista Corporation

I facilities are at the heart of our ability to serve customers effectively and efficiently. In
2 addition to employees supporting our field operations, our facilities are required to support a
3 broad range of technical and administrative staff, including accountants, engineers, attorneys,
4 customer service representatives, and information technology experts. Besides the facilities
5 themselves, our operations depend on extensive information technology infrastructure,
6 diverse and stand-alone communication networks, and a myriad of other support systems
7 (including supporting all the Company's workers who are connecting remotely into the
8 Company's systems).
9 Q. Would you please summarize the capital investments in general plant,
10 fleet and facilities resources completed in 2024 and planned over the Two-Year Rate
11 Plan?
12 A. Yes,the completed and planned investments related to general plant, fleet, and
13 facilities resources, presented on a system basis, are shown in Table No. 5, and described
14 below. See also the detailed narrative for each electric transmission Business Case at Exhibit
15 No. 10, Schedule 3,pages 416 - 535.
16 Table No. 5—General Plant Capital Proiects (System)
17
18 General Plant&Fleet Investments Capital Projects(System)In$(000's)
Rate Year 1 Rate Year
19 Line July 2024- Sept 2025- Sept 2026-
20 # Business Case Name Investment Driver August 2025 Aug 2026 Aug 2027
21 1 Capital Equipment Program Asset Condition $ 2,486 $ 2,084 $ 2,090
22 2 Central24 HR Operations Facility Performance&Capacity - - 3,339
23 3 Fleet Services Capital Plan Asset Condition 9,259 5,257 5,695
24 4 Palouse Service Center Asset Condition 750 750 -
5 Right-of-Way Use Permits Mandatory&Compliance 337 243 243
25 6 Sandpoint Service Center Perforinance&Capacity 1,250 - -
26 7 Structures and Improvements/Furniture Asset Condition 7,197 5,494 5,670
27 8 Telematics 2025 Asset Condition 495 - -
28 Total Planned General Plant&Fleet Investment Capital Projects $ 21,774 $ 13,827 $ 17,037
29
30 Capital Equipment Program (July 2024-August 2025: $2,486,000, RY1: $2,084,000,
31 RY2: $2,090,000)
32 This program provides funding for the tools and equipment needed for Avista's employees to
DiLuciano, Di 26
Avista Corporation

I perform new construction, make repairs, complete essential maintenance, and ensure system
2 integrity. This equipment, which needs to be adequate and fully available for both planned
3 work and emergency response, has to meet the needs of our electric, natural gas,
4 communications, fleet, facilities and generation crews, and infrastructure.
5 Central 24 HR Operations Facility (July 2024-August 2025: $0, RY1: $0, RY2:
6 $3,339,000)
7 For decades, several of Avista's most critical operations have been located on the 4th floor of
8 Avista's General Office Building on the Mission Campus. This includes departments such as
9 Transmission System Operations, Supervisory Control and Data Acquisition, Distribution
10 Operations, Gas Control,Network Operations, Security Operations, and 24-Hour Call Center
11 Reps. Over time, as each of these departments experiences new growth due to ever-changing
12 utility requirements and/or initiatives, capacity has been reached in their available square
13 footage. Due to our current space constraints, we have handicapped our ability to manage
14 storm events, narrowly meeting government regulations, and created an inaccessible and
15 ergonomically unfriendly working environment.
16
17 Likewise, our Generation Control Center, which monitors the 5 dams along the Spokane
18 River, is in a leased space at the Seehorn Building in downtown Spokane. The urban setting
19 surrounding the control center has led to a heightened risk of criminality and unauthorized
20 access for our Seehorn Building operations and employees. Located on the second floor of the
21 commercial retail building, the control center only has one layer of defense in the form of a
22 controlled access man door. Moving the Generation Control Center to a safe and secure
23 Avista-owned space alongside the other critical operations group is imperative. The
24 recommended solution at this time is to build a new greenfield building. This will allow for a
25 purpose-built control center facility, with ample space for current needs and future growth,
26 upgrading our technology to meet industry standards, and reducing security risks.
27
28 Fleet Services Capital Plan (July 2024-August 2025: $9,259,000,RY1: $5,257,000, RY2:
29 $5,695,000)
30 Fleet vehicles and equipment simply do not age well, as they are subject to a duty cycle that
31 most vehicle owners would not experience in their personal car or truck. Avista's fleet of
32 vehicles operate in environments that are often at the extreme: the hottest or the coldest, the
33 dustiest,constant in and out,starting and stopping,high idle time and high loads. These factors
34 lead to substantial wear and tear on our vehicles, even under prudent and proper use. Over
35 time this leads to substantial maintenance and repair costs and reduced reliability/availability.
36 The Company's fleet replacement program optimizes the life of each vehicle allowing us to
37 extract the right amount of useful value from our vehicles before they experience an
38 accelerated rate of repair expenses. The investments made under this plan represent the annual
39 investments needed to replace a portion of our service fleet each year based on asset condition
40 (replacement at end-of-life). Avista's fleet group uses industry best practices, data, and a
41 proprietary, third-party asset management system" to identify when to replace equipment in
42 order to achieve the lowest total cost of ownership for our customers.
43
44 Palouse Service Center (July 2024-August 2025: $750,000, RY1: $750,000,RY2: $0)
"Avista uses the services of Utilimarc,a utility-focused data analytics Company that benchmarks and performs
similar analysis for over 50 investor-owned utility fleets nationwide. https://www.utilimarc.com/
DiLuciano, Di 27
Avista Corporation

I The Pullman building and the site have many critical systems that need replacement,including
2 electrical, HVAC, plumbing and roof systems. There are many worn assets in dire need of
3 replacement, as many of the capital projects have been put on hold until the future state of the
4 site is known. Due to budget constraints we are moving forward with targeted transfers to
5 plant for 2024 and 2025 to maintain the existing assets by addressing asset condition concerns
6 and operational needs. As funds become available in the future there will be a design
7 completed for the building of a New Pullman Service Center to transfer to plant in 2029-2030.
8
9 Right-of-Way Use Permits (July 2024-August 2025: $337,000, RYI: $243,000, RY2:
10 $243,000)
11 Avista owns and maintains electric transmission, distribution, and natural gas facilities which
12 cross public lands managed by a variety of state, federal and local agencies, as well as entities
13 who own extensive tracts, such as railroads. Traditionally, we have secured long-term right-
14 of-way permits for these facilities, but have been required to renew them through an annual
15 billing process. The cost of renewing these permits continues to increase each year, ranging
16 from 3% to 10% annually, depending on the agency/entity, thereby increasing annual O&M
17 expenses to the company and our customers. This business case proposal is to secure long-
18 term agreements with lump-sum payments to reduce overall labor expenses related to
19 tracking, researching, and processing these annual permits. In some cases, we have been able
20 to negotiate a lower annualized cost over the term of the permit by paying a lump sum up
21 front. In either case, we reduce costs to the company and our customers. Making long-term
22 lump sum payments allows us to capitalize these costs, as the permit is a long-term asset.
23
24 Sandpoint Service Center (July 2024-August 2025: $1,250,000, RY1: $0, RY2: $0)
25 The existing Sandpoint Service Center facility was acquired in 1995, but we believe the
26 original construction year to be 1957. There are many improvements needed at the current
27 facilities and the existing storage yard is becoming too small for ever-growing inventory,
28 which has almost tripled in the last 10 years. There is unique voltage in the Sandpoint area,
29 different than the rest of the company, so the local storekeeper must keep more material than
30 most yards of a similar size. The property is too small for our needs, and we are unable to
31 purchase any additional land adjacent to the existing property. While ultimately, we would
32 like to see the Sandpoint Service Center, including the office, line dock, pole yard, and
33 warehouse moved to a new parcel North of Sandpoint,this business case provides the funding
34 to make more immediate improvements to the current location. Those improvements include
35 new asphalt, storage areas and repairing building systems such as roofs, electrical, HVAC,
36 and another property to the North that will provide additional storage.
37
38 Structures and Improvements/Furniture (July 2024-August 2025: $7,197,000, RY1:
39 $5,494,000, RY2: $5,670,000)
40 These investments fund capital maintenance, site improvements, security, and other needs
41 related to the Company's 72 building facilities that provide office, operations, storage space
42 and other business functions. These capital maintenance projects can include roofing, siding,
43 asphalt, electrical and plumbing work, remodeling, furniture replacements and new furniture
44 for growth in operations. Approximately half the investments fund asset replacements based
45 on end-of-life conditions and the Company's facilities management group uses a specialized
46 application to help determine the optimum timing for these replacements.Approximately 30%
47 of the annual funding supports immediate needs identified by the Avista work groups with
DiLuciano, Di 28
Avista Corporation

I responsibility for each facility, and the remaining funds go to emergent needs that could not
2 be anticipated in the planning process. This business case results in direct O&M offsets due
3 to increased energy savings. The annual system estimated value of these Direct Offsets is
4 expected at$11,000 in 2024, $11,330 in 2025, $11,670 in 2026 and$12,020 in 2027. Idaho's
5 share is prorated over the Two-Year Rate Plan and included in the Company's revenue
6 requirement as a reduction in Idaho electric and natural gas expense within pro forma
7 Adjustments 3.10 (Rate Year 1) and 26.05 (Rate Year 2).
8
9 Telematics 2025 (July 2024-August 2025: $495,000,RY1: $0,RY2: $0)
10 Advances in technology, customer requirements and safety are driving the need to invest
11 capital in our connected vehicle systems. Implementing the next generation of telematics in
12 vehicles driving the roads in our communities on behalf of Avista have the opportunity to
13 satisfy our customers, reduce our liability exposure and improve operational safety.
14
15 Q. Referring to the individual Table Nos. 1 through 5 above, what is the
16 overall level of system capital additions for which you sponsor, and how does this capital
17 investment compare between the Pro Forma and RY1 and RY2 periods?
18 A. Illustration No. 1 below shows overall system capital additions (transfers to
19 plant) for transmission, distribution, and general plant for the Pro Forma, RY1 and RY2
20 periods, of$322.5 million, $258.5 million and$302.4 million, respectively. As also noted in
21 the illustration, the "Pro Forma" period represents 14 months (or July 1, 2024 —August 31,
22 2025). Finally, this illustration distinguishes between what are ongoing projects or programs
23 from the Pro Forma period ending August 2025,versus incremental projects that are estimated
24 to transfer-to-plant from September 2025 through August 2027, representing $1.2 million in
25 RY1 and$3.3 million in RY2.
DiLuciano, Di 29
Avista Corporation

I Illustration No. 1— Transmission, Distribution and General Plant Investment (System
2 Transfers to Plant)
3
4 Avista Transmission, Distribution, and General Plant Capital Additions
$'sin millions (System Transfers to Plant)
5 $350
$3.3
6 $300 $1.2
7 $250
8 $200 01
9 $150
10 $100
11
$50
12
13 Pro Forma RY1 RY2
Total $322.5(1) $258.5 $302.4
14 ■Continuation of Ongoing Business Cases QAdditionaI Business Cases Initiated in RYl-RY2
Ill Pro Forma period includes July 1,2024-August 31,2025 capital additions
15
16 Notably, as can be seen from this illustration, most of the capital investment (99.5% in RY1
17 and 98.9% in RY2) relates to ongoing, multi-year efforts that continue over time, at various
18 funding levels. The rationale and justification for these ongoing projects or programs,
19 however, does not change over time, only the fundinglevels.evels. The additional Business Case
20 of$1.2 million (system) in RY1 relates to the Ambient-Adjusted Transmission Line Ratings,
21 whereas the additional Business Case of$3.3 million in RY2 relates to the Central 24 HR
22 Operational Facility, that are both discussed earlier in my testimony.
23 Q. Does this conclude your direct testimony?
24 A. Yes.
DiLuciano, Di 30
Avista Corporation

DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
[e-mail]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-25-01
OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-G-25-01
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 10
AND NATURAL GAS CUSTOMERS IN THE ) OF
STATE OF IDAHO ) JOSHUA D. DILUCIANO
FOR AVISTA CORPORATION
(ELECTRIC AND NATURAL GAS)

s
Avista Utilities Asset Management
Protocol for Managing Select Aldyl A Pipe in Avista
Utilities' Natural Gas System
May 2013
,AIIw- —
www.avistautilities.com 'A�/r/ISTA
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J. DiLuciano,Avista
Schedule 1, Page 1 of 35

Protocol for Managing Select Aldyl A Pipe in Avista Utilities'
Natural Gas System
Executive Summary
Avista Utilities (Avista) protocol for managing select Aldyl A pipe proposes a twenty-
year program to systematically remove and replace select portions of the DuPont Aldyl A
medium density polyethylene pipe in its natural gas distribution system in the States of
Washington, Oregon and Idaho. None of the subject pipe is "high pressure main pipe,"
but rather, consists of distribution mains at maximum operating pressures of 60 psi and
pipe diameters ranging from 11/4 to 4 inches. Further, Avista notes that while there have
been concerns with the integrity of steel pipe in other parts of the country in recent years,
the steel pipe in its system, including steel service risers, is being managed to protect its
long-term reliability and performance and is outside the scope of this program.
In recent years, Avista experienced two incidents on its natural gas system that prompted
the Washington Utilities and Transportation Commission and the Company to better
understand the potential long-term reliability of Aldyl A pipe. Results of these
investigations, which were aided by new tools developed for Avista's Distribution
Integrity Management Plan, corroborated reports for similar Aldyl A piping around the
country as supporting the development of a protocol for the management of this gas
facility. The following report highlights the history of DuPont's Aldyl A natural gas pipe
and summarizes DuPont and Federal Agency communications that are relevant to this
proposed program. The report documents the Aldyl A pipe in Avista's natural gas
system and describes the analysis of the types of failures observed in this pipe, and the
evaluation of its expected long-term integrity. Finally, the report describes the results of
Avista's work to establish the framework for the proposed protocol for the management
of Aldyl A pipe in its natural gas system.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 2
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J.DiLuciano,Avista
Schedule 1,Page 2 of 35

Table of Contents
I. History of DuPont Aldyl A Piping Systems.......................................................................... 5
DuPont Introduces Natural Gas Polyethylene Pipe — 1965 .................................... 5
The Phenomenon of"Low Ductile Inner Wall"..................................................... 5
DuPont Communicates Potential Issues to Aldyl A Customers............................. 5
1982 Letter ...................................................................................................... 5
1986 Letter ...................................................................................................... 6
DuPont Substantially Improves Aldyl A Pipe........................................................ 6
Common Classifications of Aldyl A Pipe............................................................... 7
11. Federal Bulletins on Brittle-Like Cracking in Plastic Pipe................................................. 8
National Transportation Safety Board.................................................................... 8
Objectives of the Board's Investigation.......................................................... 8
Phenomenon of Premature Brittle-Like Cracking........................................... 9
Board Findings on the Three Identified Safety Issues .................................... 9
Pipeline and Hazardous Materials Safety Administration.................................... 12
1999 Bulletins................................................................................................ 12
2002 Bulletin................................................................................................. 12
2007 Bulletin................................................................................................. 12
111. 2009 Distribution Integrity Management Program........................................................... 12
Objectives and Approach...................................................................................... 12
IV. 2011 Call to Action—Transportation Secretary LaHood................................................. 13
V. Avista's Experience with DuPont Aldyl A Piping Systems............................................... 14
Spokane and Odessa Incidents.............................................................................. 14
Expert-Recommended Protocol for Managing Aldyl A Pipe in Relation to
Reported Soil Conditions .............................................................................. 15
Evaluation of Leak Survey Records.............................................................. 16
Pipe Replacement Projects in 2011 ............................................................... 16
Avista Distribution Integrity Management Program ............................................ 16
VI. Analyzing Modes of Failure in Avista's Aldyl A Pipe....................................................... 17
Towersand Caps ........................................................................................... 18
Rock Contact and Squeeze-Off..................................................................... 19
Services Tapped from Steel Mains................................................................ 20
Avista's Aldyl A Services............................................................................. 21
Understanding the Significance of Leaks in Aldyl A Pipe................................... 21
Frequency and Potential Consequence.......................................................... 21
The Complication of Brittle Cracking in Aldyl A Pipe................................. 22
VI I. Reliability Modeling of Avista's Aldyl A Piping................................................................22
Availability Workbench Software ........................................................................ 22
Reliability Forecasting.......................................................................................... 23
Forecasting the Reliability of Aldyl A Piping ...................................................... 23
ForecastingResults............................................................................................... 24
Forecast Piping Failures................................................................................ 24
Dependability of Forecasting Future Failures............................................... 24
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 3
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J. DiLuciano,Avista
Schedule 1, Page 3 of 35

Understanding the Significance of Cumulative Failure Curves.................... 25
Prudent Failure Management ........................................................................ 25
Priority Aldyl A Piping................................................................................. 26
VIII. Formulation of a Management Program for Priority Aldyl A Pipe.................................26
Priority Aldyl A Piping in Avista's System.......................................................... 27
IX. Other Aldyl A Pipe Replacement Programs.......................................................................28
Aldyl A Pipe in the Pacific Northwest.................................................................. 28
Established and Emerging Programs for Aldyl A Pipe Replacement................... 28
Developments of Interest...................................................................................... 29
X. Designing Avista's Replacement Protocol for its Priority Aldyl A Pipe..........................30
Systematic Replacement Program........................................................................ 30
TimeHorizon ................................................................................................ 30
Prudent Management of Potential Risk......................................................... 30
Prioritizing the Work..................................................................................... 31
Twenty-Year Proposal................................................................................... 31
Initial Optimization....................................................................................... 32
Responsive Replacement Program ....................................................................... 33
Dr. Palermo's Assessment of the Proposed Protocol for Managing..................... 33
Avista's Priority Aldyl A Piping........................................................................... 33
XI. Application of Avista's Washington State Study Results to Aldyl A Pipe in the States of
Oregonand Idaho.................................................................................................................34
XII. Resource Requirements and Expected Cost.......................................................................34
Staffing.................................................................................................................. 34
CapitalCosts......................................................................................................... 35
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 4
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J.DiLuciano,Avista
Schedule 1,Page 4 of 35

History of DuPont Aldyl A Piping Systems
Modern polyethylene pipe products are corrosion-free, lightweight, cost-effective,
highly-reliable, and can be installed quickly and efficiently. For these reasons, it has for
decades been the `standard for the industry' and is the predominant choice used in natural
gas distribution systems. As with any revolutionary product line, polyethylene piping
systems have undergone continuous and rigorous testing and product improvement. Such
is the case with DuPont's Aldyl A piping systems, as very briefly summarized below.
DuPont Introduces Natural Gas Polyethylene Pipe- 1965
Along with other manufacturers, DuPont began to use polyethylene resin to produce
plastic piping for a variety of purposes. The resin was produced from ethylene molecules
combined together in repeating patterns to form larger molecules called `polymers',
hence the name `polyethylene.' DuPont's product designed specifically for use in the
natural gas industry was marketed under the name "Aldyl A." The initial resin used in
production of Aldyl A pipe, Alathon 5040, was manufactured from 1965 to 1970.
DuPont changed the resin in 1970 to improve Aldyl A's resistance to rupture during
pressure testing. This improved formulation, known as Alathon 5043, was the primary
resin used in DuPont's Aldyl A pipe from 1970 until 1984.
The Phenomenon of"Low Ductile Inner Wall"
Shortly after changing its polyethylene resin in 1970, DuPont detected a manufacturing
issue highlighted during laboratory testing of Aldyl A pipe. DuPont learned that its
manufacturing process was resulting in some of the pipe having a property described as
"low ductile inner wall." "Ductility" is the ability of a material to withstand forces that
alter its shape without it losing strength or breaking. A `highly-ductile' material can be
bent, flexed, pressed or stretched without cracking or losing strength because, unlike
brittle materials, it can redistribute the forces of stress concentration. Low Ductile Inner
Wall, or as it often appears "LDIW," results when the inner surface of the Aldyl A pipe
becomes brittle, promoting the formation of cracks and premature failure. In early 1972,
DuPont changed its manufacturing process to eliminate this phenomenon, but estimated
that 30 - 40% of the pipe it produced in 1970, 1971 and early 1972 was affected,
primarily in pipe diameters from 11/4 inches to 4 inches.
DuPont Communicates Potential Issues to Aldyl A Customers
1982 Letter
In 1982, DuPont sent a letter to its natural gas customers, noting that two of its gas utility
customers had reported a low frequency of leaks in Aldyl A pipe manufactured prior to
1973. These leaks were reported as "slits" occurring where the pipe was in "point contact
with rocks." DuPont noted these two utilities had increased the frequency of leak surveys
where rock may have been part of the backfill around the pipe, and encouraged other
Aldyl A customers to consider the same. This letter was the genesis of what would
become a continuing focus on the pipe vintage known as "pre-1973 Aldyl A."
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 5
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J.DiLuciano,Avista
Schedule 1,Page 5 of 35

1986 Letter
DuPont's second letter to its Aldyl A pipe customers was sent in 1986, focusing again on
pre-1973 Aldyl A pipe. The letter focused on results of newly-developed (elevated
temperature) testing methods that allowed DuPont to more-accurately estimate the
longevity of this vintage pipe, in diameters of 11/4 inches and larger. Test results showed
that `Aldyl A pipe manufactured prior to 1973 had certain limitations that were not
previously-shown by then-available, state-of-the-art testing methods.' The limitations
were described as a reduction in pipe service life caused by: 1) "rock impingement" or
pressure from rock points directly on the pipe (as mentioned in their 1982 letter), and 2)
the use of squeeze-off practices. The term "squeeze-off' refers to the current and long-
standing construction practice of mechanically pressing in polyethylene pipe walls to
temporarily stop the flow of gas during work on a line that is in service. DuPont further
noted that average ground temperature surrounding the pipe, in the ranges of 60 to 70
degrees (F), had a major bearing on its ultimate expected service life. Finally, DuPont
recommended that operators should reinforce the pipe, using clamps that surround the
pipe at squeeze points, in order to extend the life of its Pre-1973 Aldyl A.
DuPont Substantially Improves Ald,, lope
DuPont made a significant change to its Aldyl A resin formulation in 1984. The
improved resin, known as Alathon 5046-C, was marketed as "Improved Aldyl A", and
significantly improved the performance of Aldyl A pipe in its resistance to `Slow Crack
Growth' and overall long-term integrity. Slow Crack Growth, or as it's often
abbreviated, SCG, describes the progression of a crack that begins with `crack initiation'
or the formation of a crack in the inner wall of the pipe. The crack then progresses
through the pipe wall, usually over period of many years, until it finally breaks through
the outer surface of the pipe, resulting in failure.
Again, in 1988, DuPont announced another advance in its Aldyl A pipe resin with the
introduction of Alathon 5046-U. This change in resin formulation increased the
resistance of the pipe to slow crack growth by another order of magnitude. In addition,
because of the high `molecular efficiency' of this new resin, its density was also reduced,
which allowed for much greater ductility in the pipe. This product, the last of the DuPont
Aldyl A materials that Avista would install, was also marketed as Improved Aldyl A. A
summary of DuPont Aldyl A pipe produced between 1966 and 1992 is presented below
in Table 1. Information includes the year of manufacture, resin formulation, relative
resistance to slow crack growth (stress rupture testing at 80' C / 120 psig for accelerated
life testing), and summary notes.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 6
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J.DiLuciano,Avista
Schedule 1,Page 6 of 35

Table 1. DuPontAldyl A Pipe 1965- 1992
Years of Rupture
Manufacture Resin Resistance* Notes
1965 - 1970 Alathon 5040 Initial Product Marketed as"Aldyl A"
1970- 1972 Alathon 5043 10 hours Resin Improvement and Low Ductile Inner Wall
1970- 1984 Alathon 5043 100 hours Resin Improvement
1984- 1988 Alathon 5046-C 1000 hours Resin Improvement-- Sold as"Improved Aldyl A"
1988 - 1992 Alathon 5046-U 10,000 hours Resin Improvement--"Improved Aldyl A"
*Illustrates the order of magnitude difference found from accelerated life testing of resins
Common Classifications of Aldyl A Pipe
Based on the characteristics of the different vintages of Aldyl A pipe, there would emerge
over time, (from DuPont's 1982 letter going forward), three age-groupings recognized by
the manufacturer, natural gas industry, and regulators as relevant in the reliability
management of this pipe.
Pre-1973 Aldyl A — Pipe manufactured through 1972, from the first two resin
formulations, and including pipe having low ductile inner wall.
Pre-1984 Aldyl A — Aldyl A pipe manufactured from Alathon 5043 resin, but only that
pipe manufactured after 1972 and through 1983.
1984 and Later Aldyl A — Pipe manufactured from the improved Alathon 5046-C and
5046-U resins.
Aldyl A Service Pipe - Small-diameter (less than 1'/a inches) Aldyl A service piping is
often treated or managed differently than larger-diameter Aldyl A pipe of the same
vintage. This is because the small-diameter pipe has been assessed by industry experts as
being more resistant to brittle-like cracking than larger-diameter pipe due to its greater
flexibility. Further, small-diameter Aldyl A pipe has been confirmed as being free of the
Low Ductile Inner Wall properties present in late 1970 through early 1972 vintage
piping.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 7
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J.DiLuciano,Avista
Schedule 1,Page 7 of 35

Federal Bulletins on Brittle-Like Cracking in Plastic Pipe
National Transportation Safety Board
In April 1998, twelve years after DuPont's second letter to customers, the National
Transportation Safety Board (Board) published a comprehensive safety bulletin
describing their investigation of natural gas pipeline accidents involving polyethylene
pipe that had cracked in a "brittle-like" manner. The bulletin focused primarily on
accidents related to an early plastic pipe manufactured by Century Utility Products
(Century), produced from Union Carbide resin. In its review, findings, and in its Safety
Recommendations, however, the Board concluded that in addition to the Century pipe,
much of the polyethylene pipe produced for gas service from the 1960s through the early
1980s may be susceptible to brittle cracking and premature failure, further noting that
vulnerability of this material to premature failure could represent a serious potential
hazard to public safety.
The Board's bulletin represented a seminal work on the vulnerability of early plastic pipe
to brittle-like cracking because it analyzed and integrated — for the first time — reports
from the technical literature, manufacturers' communications, industry expert opinions,
the experience of pipeline operators and regulators' accident reports. Because the
bulletin provided a clear understanding of the drivers of failure in older polyethylene
pipe, we have included a fairly detailed synopsis in this report.
Objectives of the Board's Investigation
Following the Board's investigation of over a dozen serious incidents, it undertook an
effort to evaluate whether the existing pipeline accident data was sufficient for assessing
the long-term performance of plastic piping. The office of Research and Special
Programs Administration of the National Transportation Safety Board compiled the
relevant accident data, but found it to be insufficient for this purpose. Lacking adequate
data for the larger assessment, the Board instead focused on estimating the likely
frequency of brittle-like cracking, focusing on published technical literature, industry
expertise, and work with several gas system operators. From this review, the Board
launched a special investigation with the objectives to address three safety issues related
to polyethylene gas service pipe:
1. Vulnerability of plastic piping to brittle-like cracking
2. Adequacy of available guidance to pipeline operators regarding installation
and protection of plastic pipe tapped to steel mains
3. Performance monitoring as a possible way to detect unacceptable performance
in piping systems
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 8
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J.DiLuciano,Avista
Schedule 1,Page 8 of 35

Phenomenon of Premature Brittle-Like Cracking
The Board's survey suggested that early plastic piping may be "susceptible to premature
brittle-like cracking under conditions of stress intensification." The term `stress
intensification' refers to localized pressure on the pipe wall created by such conditions as
rock contact or significant bending of the pipe. The phenomenon of brittle-like cracking
was characterized by the failure processes described above, beginning with the initiation
of cracks on the inner wall of the pipe at the pressure or stress point, followed by slow
crack growth that progressed under normal pipeline operating pressures (much lower than
the pressure required to rupture the pipe). The process culminated with the crack
reaching the outside wall of the pipe, showing up as a very tight, slit-like opening on the
surface, running generally parallel with the length of the pipe. Premature brittle-like
cracking was believed, at the time of the Board's safety bulletin, to require relatively high
and localized stress on the pipe resulting from sharp or excessive bending, soil settling,
rock"impingement" (point or contact pressure on the pipe) , improperly installed fittings,
and dents or gouges to the pipe surface. The term `brittle-like cracking' was used to
describe this failure process because the pipe showed no signs of being bulged or
deformed where the cracks occurred.
Board Findings on the Three Identified Safety Issues
Issue 1: Vulnerability of Plastic Piping to Brittle Cracking
Long-Term Strength of Early Pipe was Overrated - In the early 1960s the industry
had very little long-term experience with plastic pipe, and consequently, developed
laboratory testing procedures to forecast the expected service life of piping. Early testing
results suggested that polyethylene pipe would exhibit a relatively constant, or `straight
line' gradual decline in strength over time. These tests and underlying assumptions were
subsequently incorporated as standards for the industry and in related federal
requirements.
As the industry gained experience, however, the straight-line assumptions of these early
procedures began to be challenged through the development of new testing methods,
where pipe strength was assessed under conditions of elevated temperature (such as the
testing referenced in DuPont's 1986 letter to customers). Results of the elevated-
temperature testing showed that the decline in strength of early plastic pipe was not
gradual or linear as had been assumed, but instead, began to accelerate or drop below the
straight line, especially after twelve years. The Board concluded that the early testing
procedures may have overrated the strength and resistance to brittle-like cracking of the
polyethylene pipe manufactured for the gas industry from the 1960s through the early
1980s.
Long-Term Ductility was Overrated - Another important assumption about early
plastic pipe, based on short-term testing, was that it would retain its ductile properties
long term. The assumption of long-term ductility had important safety ramifications
since it allowed plastic pipe systems to be designed to withstand stresses generated
primarily by internal pressure and to give less consideration to the impacts of external
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 9
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J.DiLuciano,Avista
Schedule 1,Page 9 of 35

stresses such as bending. Unfortunately, the early testing methods did not properly
identify the evidence of the "ductile to brittle" transition that was occurring early in the
life of the pipe. Consequently, the tests did not distinguish pipe failures resulting from a
loss in ductility. The Board noted that this loss of ductility was also observed in the older
piping of several manufacturers, those other than Century Utility Products.
Pipeline Operators had Insufficient Notification - The Board noted that premature
brittle-like cracking was a complex phenomenon that had not been systematically
communicated to the industry, and hence, had not been fully-appreciated by pipeline
operators. The Board recognized pipe manufacturers as commonly offering technical and
safety assistance to operators, and occasionally, formal reports on their materials. But,
because the information on the potential weakness of their products was also mixed with
information publicizing its best performance characteristics, the message was not clear.
The Board also noted that the Federal Government had not provided relevant information
to gas system operators, and concluded that operators had insufficient notification that
much of their early polyethylene pipe may have been susceptible to premature brittle-like
cracking. Finally, the Board went on to recommend that the polyethylene pipe
manufacturers' organization, the Plastics Pipe Institute, advise its members to notify
pipeline operators if any of their materials indicate poor resistance to brittle-like failure.
Issue 2:Adequacy of Guidance for Connecting Plastic Pipe to Steel Mains
Critical Understanding of Stress on Pipe - The Board observed that the premature
transition of plastic piping from a ductile to a brittle state appeared to have little
observable adverse impact on the serviceability of plastic pipe, except where the pipe was
subjected to external stresses, such as excessive bending, earth settlement, dents or
gouges to the pipe surface, and improper installation of fittings, etc. Of those sources of
stress, a key factor identified in the Board's bulletin was earth settlement, but particularly
in cases where plastic piping was connected to more rigidly anchored fittings, such as
steel main pipe. Because the physical properties of plastic and steel respond differently
under the same conditions, such as to temperature change and ground settlement, the
slight movements of each type of pipe in the ground will be different. This difference in
movement can result in significant stress at the point of connection between the plastic
and steel piping.
Much of the Guidance to Operators was Insufficient or Ambiguous - In addition to
pipeline operators having insufficient guidance on the overall issue of the vulnerability of
plastic pipe to brittle cracking, as noted above, the Board also observed that much of the
available guidance to operators on how to limit stress on the pipe during installation was
inadequate or ambiguous. This was particularly the case with the stress associated with
the tapping of plastic service piping to steel mains, where the Board concluded that many
of those connections may have been installed without adequate protection from external
stress. The Board went on to identify several instances where safety requirements did not
fully incorporate safety recommendations, resulting in ambiguity for pipeline installers
and regulators. Other highlights of the Board's findings were the many cases where the
applicable regulations applying to pipeline installation lacked any performance
measurement criteria. Noting that the Office of Pipeline Safety considered many of its
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 10
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 10 of 35

safety regulations to be performance-oriented requirements, the Board rebutted this in
stating that "many are no more than general statements of required actions that do not
establish any criteria against which the adequacy of the actions taken can be evaluated."
A particular example was the regulation that "requires gas service lines to be installed so
as to minimize anticipated piping strain and external loading," and yet it contained no
performance measurement criteria for establishing compliance. Finally, the Board went
on to note cases where the inadequacy of pipe manufacturers' instructions also
contributed to the lack of a clear understanding of methods to limit stress on plastic pipe
during installation.
Issue 3:Monitoring of Plastic Pipe to Determine Unacceptable Performance
The Board's final objective was focused on performance monitoring of pipeline systems
as the key to effectively managing the vulnerable piping types identified in the bulletin.
In this discussion, the Board focused on the accident in Waterloo, Iowa in 19941, in
highlighting the very real challenges of designing effective pipeline monitoring
programs. The Board stated that before the accident, the pipeline operator had developed
a limited capability to monitor and analyze the condition of its system. It concluded
however, that the systems the operator had developed for tracking, identifying, and
statistically treating plastic piping failures did not permit an effective analysis of system
failures and leak history, noting that their methods of handling of pipe data masked the
high failure rates of the subject Century pipe. While the operator did re-evaluate its
monitoring data after the accident, and subsequently identified the high failure rates of
Century Pipe, the Board opined that the problem could have been detected earlier (before
the accident) if the data had been properly analyzed in the first place. Finally, the Board
concluded that an effective monitoring program would have allowed the operator to
implement a pipe replacement program that might have prevented the accident.
In the second case, the Board noted that while the operator had added capabilities to its
pipe-monitoring protocols, it had still not chosen parameters needed to provide adequate
analysis of its plastic piping system failures and leak history. The bulletin went on to
note examples of the many types of additional parameters needed to enable the effective
tracking, identifying, and properly describing system failures and leak history.
The Board concluded that in light of the key findings in its bulletin, that gas system
operators may need to be advised once again of the importance of complying with
Federal requirements for piping system surveillance and analyses. Regarding the
monitoring of older piping, the Board identified the necessity to analyze factors such as
piping manufacturer, installation date, pipe diameter, operating pressure, leak history,
geographical location, modes of failure, location of failure, etc. Finally, the Board noted
that an effective monitoring program would require the evaluation of pipe material and
installation practices to provide a basis for the planned and timely replacement of piping
that indicates unacceptable performance.
'In October, 1994,a natural gas leak and explosion at Midwest Gas Company in Waterloo,Iowa,resulted
in 6 fatalities and 7 injuries. The cause of the incident was identified as the failure of a'h inch diameter
service pipe cracking in a brittle-like manner at a connection to a steel main.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 11
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 11 of 35

Pipeline and Hazardous Materials Safety Administration
1999 Bulletins
The first two of several advisory bulletins related to the Board's 1998 Safety Bulletin
(above), were published by the Office of Pipeline Safety, now known as the Pipeline and
Hazardous Materials Safety Administration (Administration), in March 1999. The
bulletins, which were issued as advisories to pipeline owners and operators, provided an
abstract of the findings of the Board's 1998 investigation and advised that much of the
plastic pipe manufactured from the 1960s through the early 1980s may be susceptible to
brittle-like cracking. The advisories concluded with the recommendation to owners and
operators to identify all pre-1982 plastic pipe installations, analyze leak histories,
evaluate potential stresses to pipe, and to develop appropriate remedial actions, including
pipe replacement, to mitigate any risks to public safety.
2002 Bulletin
This bulletin, as with the prior advisories, reiterated to natural gas pipeline owners and
operators the susceptibility of older plastic pipe to premature brittle-like cracking. But,
for the first time, this advisory specifically named DuPont's pre-1973 Aldyl A pipe (low
ductile inner wall) as being susceptible to brittle cracking. The bulletin also depicted
several environmental and installation conditions that could lead to premature, brittle-like
cracking failure of the subject pipe, and described recommended practices to aid
operators in identifying and managing brittle-like cracking problems.
2007 Bulletin
This bulletin, again, served to review and recap the findings of the prior bulletins,
advising natural gas system operators to review the earlier statements. In addition, the
advisory recapped results of the ongoing effort of the American Gas Association to
identify trends in the performance of older plastic pipe. The advisory reported that the
data, at that point, could not assess failure rates of individual plastic pipe materials, but
did support what was historically known about the susceptibility of older plastic piping to
brittle-like failure, including the addition of specific materials to the list, such as Delrin
insert tap tees.
2009 Distribution Integrity Management Program
The Administration published the final rule establishing integrity management
requirements for gas distribution pipeline operators in December 2009. Though the
effective date of the rule was February 2010, operators were given until August 2011 to
write and implement their Distribution Integrity Management Plan (DIMP).
Objectives and Approach
Among other objectives, the program was intended to overcome two key weaknesses in
pipeline safety management that were identified in the National Transportation Safety
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 12
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 12 of 35

Board's 1998 bulletin (above): 1) correct weaknesses in federal regulations, particularly
in the Office of Pipeline Safety, by establishing true measurement criteria for establishing
safety compliance, and 2) establish systematic protocols for pipeline data collection,
analysis, and interpretation, that helps ensure accurate integrity assessment and
appropriate remediation.
The concept of"Integrity Management" grew out of a demonstration project of the Office
of Pipeline Safety designed to test whether allowing operators the flexibility to allocate
safety resources through risk management was effective in improving pipeline safety and
reliability. Integrity management requires operators, such as natural gas distribution
companies, to write and implement Integrity Management Programs (IMPS) to assess,
evaluate, repair and validate the integrity of pipeline segments. The program contains the
following elements:
• Knowledge
• Identify Threats
• Evaluate and Rank Risks
• Identify and Implement Measures to Address Risks
• Measure Performance, Monitor Results, and Evaluate Effectiveness
• Periodically Evaluate and Improve Program
• Report Results
The Integrity Management approach uses historical leak data and other facility
information, along with the input of subject-matter experts, to identify individual threats
to a gas system. These threats are then analyzed to predict the likelihood and
consequences of failure. Each threat is then ranked by priority, followed by the
development of a plan to reduce or remove those risks as deemed necessary.
2011 Call to Action - Transportation Secretary LaHood
Finally, in April 2011, U.S. Transportation Secretary LaHood issued a Call to Action to
all pipeline stakeholders in conjunction with the effective application of the Distribution
Integrity Management Program. The Call to Action was aimed at the more than 2.5
million miles of liquid and gas pipelines of both federal and state jurisdiction, including
transmission and distribution facilities, calling on owners and operators, the pipeline
industry, utility regulators and state and federal partners to:
• Evaluate risks on pipeline systems;
• Take appropriate actions to address those risks, and
• Requalify subject pipeline systems as being fit for service.
The centerpiece of the Call to Action is the "Action Plan" of the Department of
Transportation and the Pipeline and Hazardous Materials Safety Administration. The
focus of the Action Plan is to accelerate the rehabilitation, repair, and replacement of
high-risk pipeline infrastructure, calling on pipeline operators and owners to take
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 13
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 13 of 35

"aggressive efforts... to review their pipelines and quickly repair and replace sections in
poor condition." To buttress this Call to Action, Secretary LaHood has asked Congress
to increase maximum civil penalties for pipeline violations, to close regulatory loopholes,
strengthen risk-management requirements, add more inspectors, improve data reporting
and help identify potential pipeline safety risks early.
Avista's Experience with DuPont Aldyl A Piping Systems
Avista has approximately 12,500 miles of natural gas piping in its service territories in
the States of Washington, Oregon and Idaho. Like dozens of other gas utilities, Avista
adopted plastic pipe as an excellent alternative to steel, and consequently, the broad
majority of Avista's pipe is polyethylene (about 8,500 miles) of various types, ages and
brands, including DuPont's Aldyl A.
Avista began installing DuPont Aldyl A in 1968 and discontinued its use in 1990 when
DuPont sold their production to Uponor. Of the various vintages and formulations of
Aldyl A pipe in its system, Avista has estimated quantities in the following amounts, in
diameters of/2"to 4":
Pre-1973 Aldyl A (1965-1972 resins) 190 Miles
1973-1984 resins 960 Miles
1985-1990 resins 919 Miles
Avista noted the advisory bulletins of the Board and Administration in 1998, 1999 and
2002, but since it had no documented trends in the types of failures highlighted,
continued to manage its Aldyl A pipe according to established monitoring standards for
leak survey and sound operations practices.
Spokane and Odessa Incidents
In recent years, however, Avista experienced two natural gas incidents resulting in
injuries and property damage that signaled possible changes in leak patterns in its Aldyl
A piping. The first incident occurred in 2005 at a commercial site in Spokane. This
event involved the failure of 1976-vintage Aldyl A pipe caused by bending-stress
resulting from poor soil compaction around the pipe that was performed by a non-Avista
excavator in 1993. The post-incident investigation judged the resulting leak to be an
anomaly that could have been prevented with proper care by that 3rd party excavator.
The second incident, at a residence in the town of Odessa, Washington, in late 2008, was
determined to be the result of rock pressure on the 1981-vintage Aldyl A pipe that
occurred during the initial installation. Avista signed a settlement agreement with staff of
2 The Pipeline and Hazardous Materials Safety Administration defines a natural gas"incident"as a release
of gas that results in any of the following: a fatality or personal injury that requires in-patient
hospitalization;property damage of$50,000 or greater,or the loss of greater than 3 million cubic feet of
gas.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 14
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 14 of 35

the Washington Utilities and Transportation Commission as an outcome of the
investigation of this incident. Under terms of the agreement, which was subsequently
approved by the Commission, Avista increased the frequency of its residential leak
survey on pre-1984 resin (pre-1987 installed) Aldyl A natural gas mains in its
Washington jurisdiction, from once every five years to annually. In addition, whenever it
is excavating in the vicinity of Aldyl A natural gas mains in Washington, Avista will also
report on the soil conditions surrounding the pipe, and identify appropriate and
reasonable remedial measures, as necessary. Avista retained the consulting services of
Dr. Gene Palermo to help develop its approach for managing Aldyl A pipe, in relation to
the soil conditions reported.
Expert-Recommended Protocol for Managing Aldyl A Pipe in Relation to Reported
Soil Conditions
Dr. Palermo is a nationally-recognized expert on the plastic pipe used in natural gas
systems, and in particular, Aldyl A piping. He has worked in the plastic pipe industry for
over 35 years, which includes 19 years with the DuPont Corporation in its Aldyl A
natural gas pipe division.
Dr. Palermo also served as the Technical Director for the Plastics Pipe Institute from
1996 through 2003 and served on the Institute's Hydrostatic Stress Board for over 20
years. Dr. Palermo has served on a variety of gas industry committees, has trained gas
industry practitioners and regulators, and has received numerous awards of merit for his
outstanding individual contribution to the natural gas plastic-piping industry. He is the
only person to receive both the American Society of Testing and Materials - Award of
Merit, and the American Gas Association - Platinum Award of Merit. Dr. Palermo is
president of his consulting firm, Palermo Plastics Pipe Consulting.
Dr. Palermo reviewed the content of Avista's agreement with the Commission to become
familiar with its requirements, specifically with regard to managing Aldyl A piping found
in soils that would currently not meet standard criteria for bedding and backfill. Dr.
Palermo's review and expertise provided the basis for his recommended protocol for
management of Avista's Aldyl A piping found in rocky soils.
1. All Aldyl A pipe manufactured prior to 1984 should be evaluated for replacement
in the following manner:
a. If the pipe has Low Ductile Inner Wall properties, Avista should
immediately begin a prioritized pipe replacement program.
b. If the pipe is installed in soil with rocks larger than 3/4 inch, Avista should
immediately begin a prioritized pipe replacement program.
c. If the pipe is installed in sandy soil or in soil with rocks up to 3/4 inch in
size, the pipe should remain in service and normal leak surveys per DOT
Part 192 should be followed.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 15
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 15 of 35

2. All Aldyl A pipe manufactured during or after 1984 should also be evaluated.
a. If the pipe is installed in soil with rocks larger than 3/4 inch in size, Avista
should evaluate the pipe and consider replacing it if they begin to
experience rock impingement failures, and should conduct leak surveys
more frequently than required by DOT Part 192, until replacement.
b. If this pipe is installed in sandy soil or in soil with rocks up to 3/4" in size,
the pipe should remain in service and normal leak surveys should be
followed.
Evaluation of Leak Survey Records
Following the Odessa incident, Avista was also asked to review five years of leak survey
records in Washington State to look for possible emerging patterns in the health of its
Aldyl A piping system. Avista organized the leak survey information and then conducted
several evaluations, which were organized under three general objectives, listed below.
1. Analyze the modes or observed types of failures in Aldyl A pipe;
2. Forecast the expected long-term integrity of Aldyl A piping;
3. Identify potential patterns in the overall health of this piping to aid in the design
of a more-focused management protocol for Aldyl A pipe.
Avista used newly-available asset-management tools to conduct these assessments,
including its recently-implemented Distribution Integrity Management Program
(Integrity Management) approach for identifying and analyzing potential threats to its
natural gas system. This approach is suited for just such an analysis, having the
capability to determine potential patterns in the overall health of a piping system that
might not have been otherwise evident through conventional data review. The analysis
of the historic leak survey data, including the observation of several new Aldyl A
material failures and leaks, did point to the development of a possible trend.
Pipe Replacement Projects in 2011
Another outcome of this heightened focus on Aldyl A leaks was Avista's decision to
replace several thousand feet of its Aldyl A main in 2011. In Odessa, Avista increased
the frequency of leak surveys on its gas system to once per quarter and mobilized a pipe
replacement program that removed all of the pre-1984 Aldyl A main pipe from the gas
system in the town. During that project, which was conducted from June to December
2011, nearly 32,000 feet of Aldyl A main pipe were replaced. Other Aldyl A
replacement projects in 2011 removed an additional 7,000 feet of this priority pipe.
Together, these projects had a capital cost of approximately$2.7 million.
Avista Distribution Integrity Management Program
As described briefly above, the Integrity Management approach, now required by law,
begins with the aggregation of historical leak-survey data and other facility information
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 16
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 16 of 35

relevant to Avista's natural gas piping system. Then, in conjunction with the input of
subject matter experts, individual threats to Avista's gas system are identified. These
threats are analyzed to predict the likelihood and consequences of failure associated with
each threat, based on the specific operating environment, system makeup, and history of
Avista's natural gas system. Each threat is then ranked relative to all others to identify,
by priority, those with the greatest hazard potential. From that priority list, measures are
developed to reduce or remove those risks as deemed necessary. These mitigating
measures are often referred to as "accelerated actions" because they may be above and
beyond the minimum requirements of applicable federal and state codes. These
accelerated actions can range from increased frequency of maintenance and leak surveys
to full replacement programs for certain gas facilities. Finally, the mitigating measures
will be reviewed to evaluate their effectiveness in reducing threats to the gas system, and
the program will then be adjusted as necessary based on those outcomes.
Integrity Management requires the use of geographically-based analytical software to
complete many of the required program elements. Like many utilities, Avista is using the
Geographic Information System (GIS) platform developed and supported by
Environmental Systems Research, Inc. (ESRI), as the geographic and analytical engine
for conducting its gas system evaluations under the Integrity Management program.
ESRI is a pioneer and world leader in developing and supporting geographic software
products for a broad range of global business sectors, including utilities. Since Avista
had already created a comprehensive GIS layer, or database, for its gas facilities, it made
sense to add analytical capabilities to this platform in complying with the Integrity
Management program requirements.
Analyzing Modes of Failure in Avista's Aldyl A Pipe
In tackling the first objective of the assessment of its Aldyl A piping, Avista aggregated
the gas leaks resulting from Aldyl A material failures found in its gas system in
Washington State from late 2005 through March 2011. The sample included 113
material failures that were evaluated and summarized by component to offer an
understanding of the specific failure modes for Aldyl A pipe. The `modes' or types of
material failures categorized are shown below in Figure 1.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 17
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 17 of 35

Figure 1. Modes or types of material failures documented in a sample of 113 leaks in
Avista's Aldyl A piping in Washington State, December 2005 through March 2011.
Aldyl A Material Failures
113leak sample size,Washington State,Dec.2005-Mar.2011
Cracked Service
Pipe at Service Tee
2 31-
Towers&Caps
Settlement of� 49�<
Main
4%
f
Rock Impingement_
&Squeeze
Damage
24
Towers and Caps
The largest percentage of material failures in the sample occurred in Towers and Caps,
referring to failure of the service tapping tee itself, shown below in Figure 2. In these
cases, the pressure applied to the tee as the cap was tightened onto the body during initial
installation has resulted in slow crack growth and failure of the tower body, the cap, or
the Delrin® insert many years later. Additionally, the saddle fusion point of the tower to
the main pipe is another frequent point of failure in this assembly. The unavoidable
stresses created during standard installation (using factory recommended procedures)
have led to brittle cracking in these components many years later. This phenomenon
clearly demonstrates the susceptibility of certain resins of Aldyl A piping to tend to fail
by brittle cracking due to the slow crack growth initiated during installation.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 18
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-13-25-01
I DiLuciano,Avista
Schedule 1,Page 18 of 35

Figure 2. External features and internal components of atypical Aldyl A service tee, as
fused to Aldyl A main pipe.
Tower Cap Delrin insert
� J
Fusion point
Rock Contact and Squeeze-Off
The second-most common material failure observed in Avista's Aldyl A pipe was due to
localized, brittle cracking in Aldyl A mains that resulted from rock impingement — rock
pressure directly on the pipe, or places where `squeeze-off was applied over the pipe's
service life. These failures are very typical for certain resins of Aldyl A main pipe,
having been consistently reported by other utilities since before the time of DuPont's
1986 letter. As described earlier, when these external stresses (rock impingement or
squeeze-off) cause the pipe to fail, it always begins with crack initiation on the inside
surface of the pipe wall, eventually resulting in slow crack growth that propagates toward
the outer wall of the pipe, and finally, through-wall failure. These failures generally
appear as short, tight cracks in the outer wall of the pipe that run either parallel, or
slightly off-parallel with the length of the pipe. A typical failure in Aldyl A main pipe,
showing a crack through the pipe wall as it appears on both the inner and outer surfaces,
is shown below in Figure 3.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 19
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 19 of 35

Figure 3. Typical brittle-like crack through the wall ofAldyl A pipe, resulting from rock
contact directly on the pipe.
w
Although the duration of the stress caused by rock contact with the pipe is very different
from that associated with squeeze-off, they both result the same pattern of crack initiation
and slow crack growth leading to failure of the pipe. Other sources of external stress that
can result in brittle failure of Aldyl A pipe, as mentioned earlier in the report, include
bending of the pipe, soil settlement, dents or gouges to the pipe, and improper installation
of fittings.
Services Tapped from Steel Mains
The third most-common failure in Avista's sample occurred where small diameter Aldyl
A service pipe is tapped from steel main pipe. In this application, a steel service tee is
welded to the steel main pipe and the small-diameter Aldyl A service pipe is then
connected to a mechanical transition fitting on the tee, as pictured below in Figure 4.
Figure 4. Typical polyethylene service tapped from a steel main.
4
It is at this transition point, between the rigid steel fitting and the more-flexible Aldyl A
service pipe, that brittle-like cracking has been observed. This failure mode in older
plastic pipe is well understood, and was one of the three study objectives reported by the
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 20
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 20 of 35

National Transportation Safety Board in its 1998 bulletin, summarized earlier in this
report.
Avista's Aldyl A Services
Avista believes its Aldyl A service piping (apart from cracking at the connection with the
tee on steel main pipe) has no greater tendency to fail than its other polyethylene service
piping , and at this point in time, should not be managed differently than other plastic
service pipe (frequency of leak survey, etc.). Consequently, Avista is not planning to
systematically replace Aldyl A service pipe as it replaces main pipe and rehabilitates
service connections at steel tees. Avista is using the Integrity Management model,
however, to track and analyze service leaks going forward to determine if the reliability
of Aldyl A service piping changes in ways that warrant a different approach.
Understanding the Significance of Leaks in Aldyl A Pipe
Frequency and Potential Consequence
Analysis of the material failures of Aldyl A pipe provides the opportunity to put these
leaks into perspective with other types of leaks on Avista's natural gas system. As part of
the development of the Integrity Management Plan, five years of leak data were analyzed
for Avista's three-state service territory. The data included nearly 17,000 individual
leaks, which were categorized according to the underlying threats to the natural gas
system as required under Integrity Management. As a point of comparison of the
significance of leak types, the data included an excess of 2,000 leaks associated with the
failure of gas system equipment, such as valves, fittings and meters. But only 153 leaks
were identified as resulting from `material failures' of Aldyl A piping in the three states.
Looking simply at Aldyl A leaks as part of the aggregate of all system leaks, it could be
easy to conclude that Aldyl A pipe failures pose a limited potential for hazard relative to
the threat of other system leaks. In fact, while gas equipment leaks are more likely to
occur, their potential consequence is often minimal. A thorough understanding of this
difference is one of the most important requirements and outcomes of any effective
Integrity Management Plan analysis.
Review of the leak-history data shows the vast majority of equipment leaks as occurring
typically with shut-off valves and gas meters, located either above ground or in locations
that allow free-venting of gas to the atmosphere. Consequently, these types of leaks have
a low potential to result in an incident posing harm. Through public awareness programs,
people have become familiar with the odor of venting gas and tend to quickly call Avista
to make repairs; this is especially true if the venting gas can be associated with visible gas
valves or meters. By contrast, Aldyl A failures and the associated leaks occur almost
entirely underground, out of sight, often in populated areas, and occasionally in the
proximity of buildings that are not actually connected to the natural gas system. Without
visible facilities, natural gas may have an unexpected presence in the environment that
allows people to dismiss slight gas odors. This reduced awareness allows gas from these
undetected leaks to have the significant potential to migrate into buildings before it can
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 21
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 21 of 35

be identified and reported. This is especially true in winter when the ground is saturated,
frozen or snow covered, and in areas of full pavement and concrete finishes. Of the
roughly 2,000 equipment leaks reported in the five years of data reviewed, none resulted
in gas incidents. By comparison, two of the relatively-small number of Aldyl A material
failures resulted in gas migrating into buildings undetected, and upon accidental ignition,
resulted in harmful incidents.
The Complication of Brittle Cracking in Aldyl A Pipe
The common mode of failure for Aldyl A materials, brittle-like cracking, can also present
special problems compared with leaks in other gas piping, such as corrosion in steel gas
pipe. Corrosion leaks tend to begin with the failure of a very minute area in the pipe
wall, which then begins to release a very minute amount of natural gas. These leaks then
tend to progress very slowly and in a stable and somewhat predicable way over time.
These types of leaks, while never positive, are more likely to be detected by modern gas-
detection equipment when they are at a stage where the release of gas is relatively minor.
By contrast, leaks in Aldyl A piping tend to first appear as substantial (high gas volume)
leaks that appear in a very short time period. This is due to the nature of brittle cracking,
where the crack can progress very slowly from the inner wall of the pipe toward the outer
wall without any release of gas, until the pipe finally splits open, resulting in a substantial
failure. Additionally, unlike the prevention or even suspension of corrosion problems in
steel pipe through effective protection methods, there is no way to halt undetected
progress of slow crack growth in brittle Aldyl A pipe.
Reliability Modeling of Avista's Aldyl A Piping
Avista's Asset Management Group performed reliability modeling for several classes of
its natural gas pipe in order to assess the long-term performance of its Aldyl A piping,
compared with steel pipe and newer-vintage plastic pipe. Reliability analysis comes from
the discipline of`reliability engineering' and is a foundational asset management tool that
provides a forecast or prediction of the future performance of a piece of equipment (pipe,
in this instance). The predicted asset performance then provides the basis for the
application of other asset management tools, allowing the development of the ultimate
maintenance or replacement strategies that optimize asset cost with any number of other
factors, such as availability for service or risk avoidance.
Availability Workbench Software
Avista developed reliability forecasts for its Aldyl A and other piping using Availability
WorkbenchTM software. This `off the shelf software' was introduced by Isograph, Ltd.,
the world's leader in reliability analysis software. Availability Workbench was first
introduced in 1988, and is used to support asset decision making in over 7,000 sites
around the world and across a range of industries, including Aerospace, Automotive,
Chemical, Defense, Electronics, Manufacturing, Mining, Oil and Gas, Power Generation,
Railways, and Utilities. Avista's version of the model was released in 2009.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 22
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 22 of 35

Reliability Forecasting
Availability Workbench has four modules, one of which, the Weibull module, is used to
create reliability forecasts (curves) for an asset. Reliability curves for gas piping are
generated from input data that include pipe inventory (type, brand, footage, location, soil
conditions, etc.), current age of piping, historic and current failure information and repair
data. Avista uses predominantly its own historical data for these inputs, but when they
must be estimated, they are vetted by subject matter experts within the company. The
model integrates pipe age and failure and repair data, and then by applying a
conventional Weibull-curve mathematical model, it produces probability curves that
represent the expected failure rates over time for each failure mode, such as the brittle-
like cracking associated with Aldyl A services tapped to steel mains. The reliability
curves represent how quickly the rest of the pipe is at risk of failing, shown as the
percentage of failures expected each year over time.
Forecasting the Reliabili y of Ald, limping
The objective of Avista's reliability modeling was to forecast expected failures for
elements of Avista's Aldyl A piping system, compared with that of steel and latest-
generation polyethylene pipe. The observed Aldyl A failure modes, discussed above,
including leak data for other types of gas pipe in Avista's system, provided high-quality
leak and age information for the reliability modeling. Forecasting was performed for the
following pipe `classes' in Avista's system.
a. Aldyl A Main pipe of Pre-1984 manufacture (Alathon 5040 and 5043 resins,
including low ductile inner wall pipe)
b. Aldyl A Main pipe manufactured during 1984 and after (Alathon 5046-C and
5046-U resins)
c. Aldyl A Services Tapped to Steel Main (Bending Stress Services)
d. Steel Main pipe
e. Newer Polyethylene Main pipe (1990 and later)
To perform the modeling, the data for these pipe classes must be input as discrete
elements, which are described as follows:
Main Pipe -Analyzed using 50-foot segments as discrete modeling elements.
Services Tapped from Steel Mains - Avista identified 16,000 such services in its
system, also referred to as `bending stress tees.' For the reliability modeling, the
individual service is the discrete element.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 23
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 23 of 35

Forecasting Results
Forecast Piping Failures
Results of the forecast modeling, for the pipe classes evaluated, are represented as
`curves' showing the percentage of the amount of each pipe class that is projected to fail
in each year of the forecast time period. The resulting reliability curves are shown in the
graph below in Figure 5.
Figure S. The expected failure rates for several classes of pipe in Avista's system, as
forecast by Availability Workbench Modeling. The "Steel"curve is obscured by the
"Newer Polyethylene"curve, both of which are essentially flat lines.
Forecast Failure Rates for Natural Gas Piping
25%
M
LL
20% ------ —
N
w
U
G1
w 15% — -- Pre-1984AIdylA
a Bending Stress Services
0 10% — —1984 and IaterAldyl A
00
(D Steel
im
° Newer Polyethylene
5/o
L00
d
a
0%
O O O O O O O O O O N W A N W v W (O O
O O O O O O O O O O O
Years
The failure curves show dramatic differences in the expected life for the pipe classes
evaluated. The difference in expected life between the Aldyl A products as a group,
compared with that of steel and newer-generation plastic pipe, is particularly evident.
Striking also, are the expected performance differences among the classes of Aldyl A
pipe evaluated, providing some clear trends useful in designing remediation strategies.
Dependability of Forecasting Future Failures
The reliability forecast is essentially a mathematical calculation of the `chance' of future
failure and decisions of significant risk and financial magnitude are based, at least in part,
on that result. Importantly though, the forecast has a `real numbers' foundation in the
actual leak data, records of material failure and repair, and the relationship of those
events with time. For Aldyl A pipe, the model is using observed endpoints in the life of
the pipe resulting from a loss in ductility and slow crack growth, for example, and
integrating that with other data to forecast future expected failures. Comparatively, the
relatively rare observed failures in steel pipe and newer-generation plastic pipe are
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 24
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 24 of 35

reflected in their nearly-flat cumulative failure curves. The value of using proven
reliability forecasting approaches and widely-adopted software is derived from their
ubiquitous application across reliability-critical industries, and their continuous testing,
evaluation, and support. Finally, as Avista adds new data in coming years for pipe
failures of all material classes, including Aldyl A, it serves to increase the statistical
power of the forecast results.
Understanding the Significance of Cumulative Failure Curves
Although the failure curves for the different classes of pipe differ significantly over the
long term, as mentioned, the failure rates also appear to be very close to zero for the first
40 years for Aldyl A services tapped to steel main, and for 75 years for Pre-1984 Aldyl A
main pipe. Since the weighted average age for Aldyl A pipe in Avista's system is 32
years, it would appear that we might have ample time before the failure rate would start
to rise substantially for Pre-1984 Aldyl A main pipe. The failure curve estimates that
when the Pre-1984 Aldyl A main pipe is 80 years old that approximately three percent of
it will fail in that single year. Given that Avista has 335 miles of this vintage pipe in
Washington, that mileage equals about 35,000 discrete elements (50-ft sections) in the
forecast model. The three percent failure, then, translates to 1,050 leaks in that 80th year.
To put that failure rate into perspective, consider that Avista documented just 113 leaks
over the past five years in Washington state, two of which resulted in injury and property
incidents, and dozens more that were categorized as hazardous leaks3, timely repaired.
Since it is expected that the number of hazardous leaks and incidents would increase
proportionally with the increase in total leaks, then it's easy to imagine just how
unacceptable the pipe performance would be at an annual failure rate of three percent.
Prudent Failure Management
To carry this point further, if we "zoom-in" on the curves we can gauge the significance
of the change in failure rate that is expected ten years from today. At that point the
weighted average age of Aldyl A pipe in Avista's system will be 42 years, and the
expected failure rate for that year is just over one-tenth of one percent (0.12%), or 42
leaks in that year. The failure rate in that year, then, will have nearly doubled over the
average annual rate for the past five years (22.6). The critical point in this analysis is the
understanding that failures in buried natural gas piping can be prudently managed only
when they are occurring at very low rates. Otherwise new leaks in the system occur too
frequently to be detected by even annual leak surveys of the entire system, resulting in an
increase in the likelihood of hazardous leaks and the potential for harmful incidents.
3 The Pipeline and Hazardous Materials Safety Administration defines a"hazardous leak"as an
unintentional release of gas that represents an existing or probable hazard to persons or property and
requires immediate repair or continuous action until the conditions are no longer hazardous.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 25
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 25 of 35

Priority Aldyl A Piping
Every pipeline operator strives to install and maintain a safe, reliable and cost-effective
system. While the goal is complete system integrity, it is impossible to avoid having any
leaks, especially on large systems such as Avista's with over 12,000 miles of mains and
several hundred thousand services. Regulators and the industry acknowledge this reality
through the adoption of standardized leak-survey methodologies, and recognized pipe
remediation practices.
But, while leaks are inherent on a system, there are circumstances where the expected
reliability of a particular pipe begins to rise compared with that of other piping and
industry norms. We have demonstrated that such is the case for portions of the Aldyl A
pipe in Avista's system, and accordingly, we have determined these classes to be at-risk
of quickly approaching a level of reliability that is unacceptable and in need of proactive
remediation. It's for this reason that Avista refers to these pipe classes as "Priority Aldyl
A piping."
Formulation of a Management Program for Priority Aldyl A Pipe
The timely application of Avista's Distribution Integrity Management approach to its
recent and ongoing leak analysis and its reliability modeling results, including Dr.
Palermo's review, and the experience gained in three priority pipe-replacement projects
in 2011, has prompted Avista to formulate a protocol for systematically managing its
Aldyl A pipe. The following categories are useful classifications for Avista's definition
of"priority Aldyl A pipe"4:
1. Aldyl A gas services tapped to steel main pipe
2. Pre-1973 Aldyl Amain pipe
3. Pre-1984 Aldyl Amain pipe
Avista has determined these classes of pipe are at risk of approaching unacceptable levels
of reliability without prompt attention. Accordingly, Avista believes the decision to
formulate a management program for its priority Aldyl A pipe is both timely and prudent,
and is consistent with results of our leak investigations, Integrity Management principles
and the recent Call to Action of Secretary LaHood. The decision is also consistent with
the prior federal bulletins on this subject and with the decisions of other similarly-situated
utilities that have implemented similar pipe-replacement programs. Finally, given the
significant amounts of priority Aldyl A pipe on Avista's system, commencing a protocol
now provides us greater opportunity to manage this facility in a prudent and cost-
effective manner.
4 Each class noted above is subject to material failures due to concentrated stresses such as rock
impingement,bending stresses,squeeze off,and failures of service towers and caps.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 26
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 26 of 35

Priority Aldyl A Piping in Avista's System
Main Pipe - Avista has approximately 12,500 miles of natural gas main pipe in its
service territories in the States of Washington, Oregon and Idaho. Approximately
seventeen percent of this total, or 2,000 miles, is Aldyl A pipe of all classes and sizes.
Proportions of various classes of piping in Avista's system, including priority Aldyl A
pipe (pre-1973 and pre-1984 mains) is shown below in Figure 6.
Figure 6. Avista's priority Aldyl A pipe,shown as a proportion of the different pipe
classes in Avista's natural gas system (items 2 and 3 from the list above).
Miles of Pipe Materials in Avista Natural Gas System
Other Aldyl A
1/2"-4"
1355 Mies
Priority Aldyl A,Pre-
1984 main,11/4"-4"
Steel
714 Miles
1/2"-20"
4065 Miles
Other Polyethylene
1/2"-6"
6350 Miles
Gas Services - Avista has approximately 314,000 natural gas services, of which
approximately 16,000, or five percent, are Aldyl service pipe tapped to steel main pipe,
shown below in Figure 7 as priority Aldyl A services.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 27
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J.DiLuciano,Avista
Schedule 1,Page 27 of 35

Figure 7. Avista's priority Aldyl Agas services(tapped from steel mains),shown as a
proportion ofAvista's total gas services.
Services in Avista Natural Gas System
Aldyl A Services from
Steel Main
16.000 (5'6j
Other Gas Services
298.000 (95'.40
Other Aldyl A Pipe Replacement Programs
Ald,, lope in the Pacific Northwest
Through general conversation with our colleagues in western gas utilities, Avista believes
it has a substantially greater proportion of Aldyl A pipe in its system than do our
neighboring Pacific Northwest gas utilities. The proportions of Aldyl A in Avista's
system (or of any other brand of early polyethylene pipe), however, is not a reflection of
the unique purchasing practices of Avista, since plastic pipe quickly became the standard
of the industry and the predominant pipe installed by utilities across the county. But, the
proportions of early plastic pipe in a system do tend to track with the amount of system
growth that gas utilities experienced during the 1970s and early 1980s. For Avista, this
was a time of particularly rapid expansion of its natural gas system (from the Spokane
metro area to outlying communities in its Washington and Idaho service territories), and
consequently, the proportion of early Aldyl A pipe in our system reflects this period of
expansion.
Established and Emerging Programs for Aldyl A Pipe Replacement
Two western utilities, Southwest Gas and Pacific Gas & Electric, have significant Aldyl
A pipe management programs either well underway or anticipated, which are very briefly
summarized below.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 28
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J.DiLuciano,Avista
Schedule 1,Page 28 of 35

Southwest Gas — Responding to a fatality incident in the early 1990s, Southwest Gas
entered into a settlement agreement with the Corporation Commission of Arizona to
conduct additional leak monitoring and pipeline remediation. By the late 1990s,
Southwest Gas had replaced 74 miles of Aldyl HD (high density) main pipe covered by
the agreement, and had replaced another 648 miles of Aldyl A pipe based on its leak
survey monitoring results. In 2005, Southwest Gas had another injury and property
incident on their system involving Aldyl A pipe, and implemented an additional pipe
replacement program in the vicinity of the incident. Southwest Gas has also worked
closely with staff of the Public Utilities Commission of Nevada in the monitoring and
replacement of what the Commission refers to as "aging" and "high risk" natural gas
pipe, including Aldyl A pipe.
Pacific Gas & Electric - After some very high-profile natural gas incidents in 2011 that
involved Aldyl A piping, Pacific Gas & Electric has announced plans to replace all the
Pre-1973 Aldyl A pipe in its system. The utility reportedly has 7,907 miles of Aldyl A
pipe of all classes in its system, which is about 19 percent of its gas system inventory. By
comparison, Avista's Aldyl A pipe stock is about 16 percent of its system. Pacific Gas &
Electric's planned replacement of its Pre-1973 Aldyl A pipe represents a massive effort
because the utility plans to remove and replace the 1,231 miles of pipe in a proposed
timeframe reported as in the range of three years, and at a cost said to exceed $1 billion,
but that has not yet been formalized. There is some question regarding the selection of
only pre-1973 Aldyl A for replacement in PG&E's system, since at least one recent high-
profile incident was reported on newer vintage (still pre-1984)Aldyl A.
Developments of Interest
US Congresswoman Jackie Speier of California has been raising the awareness of
Congress and Transportation Secretary, LaHood, in two separate actions. First, in May
2011, Speier sponsored House Resolution 22 entitled the "Pipeline Safety and
Community Empowerment Act of 201 L" The legislation provided for citizens being
able to easily access pipeline maps and safety-related information from pipeline owners,
prescribed certain changes in pipeline monitoring requirements, and called for the
addition of physical safety devices to existing pipelines. The bill is currently under
consideration by the House Committees on Transportation and Infrastructure, and Energy
and Commerce.
In October 2011, Speier wrote to Secretary LaHood calling on him to direct the Pipeline
and Hazardous Materials Safety Administration to "take immediate action to address the
long-known safety risks associated with pre-1973 Aldyl-A plastic pipe manufactured by
DuPont." She went on to advocate for the removal of this pipe from use in the U.S., and
to commend Pacific Gas & Electric for its planned removal of all of its pre-1973 Aldyl A
pipe. Citing the DuPont letters to customers, federal safety bulletins, and the Waterloo
incident, she chided Congress for not taking action, and urged the Secretary to
immediately do so.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 29
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 29 of 35

Designing Avista's Replacement Protocol for its Priority Aldyl A
Pipe
Avista modeled two different approaches to the replacement program, one that was
systematic, based on an established timeframe and one that was responsive to problem
areas as they were identified.
Systematic Replacement Program
Time Horizon
Determining the appropriate length of time over which to replace the Priority Aldyl A
pipe involves the optimization of several factors, including: 1) the overall urgency from
a reliability and safety perspective, both present and forecast; 2) potential consequences;
3)the impact of more intensive leak survey methods to better identify priority facilities in
need of replacement and in helping reduce the potential for harmful incidents; 4) the
ability to effectively prioritize specific projects to better ensure facilities in greatest need
are addressed earliest; 5) the availability of equipment and labor resources needed to
conduct the work, and the ability to coordinate the work with Avista's ongoing
construction programs; 6) program efficiency, and 7) the degree of rate pressure placed
on customers, both in absolute terms and in relation to other reliability and safety
investments required across the natural gas and electric business. Ultimately, Avista
must ensure that management and removal of its Aldyl A pipe is conducted in a way that
shields our customers from imprudent risk, while at the same protecting them from the
burden of unnecessary costs.
Prudent Management of Potential Risk
Avista believes it is important to establish for our customers and other stakeholders that
while there can never be `zero risk' associated with the program, the potential risk can be
prudently managed. On one hand, a replacement program carried out over a very short
timeframe cannot prevent the occurrence of all leaks forecast to occur over the course of
the program. But at the other extreme, it's clear that setting a replacement timeline that's
too lengthy would likely result in safety, reliability and financial consequences for our
customers and our business that could be regarded as imprudent. Avista believes the
timeline for the replacement program should optimize the factors mentioned above in a
way that reduces the risk associated with Aldyl A pipe to the range of `prudent risks'
associated with the myriad other electric and gas facilities and practices that are used to
serve the energy needs of utility customers. Said differently, there is no possible way to
eliminate the risks associated with energy infrastructure, but there is a range of limited
risk that's deemed prudent in the conduct of our business. Avista's treatment of its Aldyl
A pipe will be managed to comport with these sound business practices.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 30
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 30 of 35

Prioritizing the Work
As important as the replacement timeline in prudently managing the reliability of
Avista's Aldyl A piping, is the ability of the Asset Management and Distribution
Integrity Management staff to partner in effectively prioritizing the pipe-replacement
activities in a way that minimizes the potential for hazardous leaks. Results of the
Availability Workbench modeling provide some support in prioritization but do not take
into account factors such as soil conditions or the proximity to buildings or people.
Obviously, a leak occurring in a vacant field will have little, if any, consequence and will
likely be detected and repaired during the next leak survey. By contrast, the potential
hazard of a leak increases with its proximity to people and structures, so replacing pipe
that has a high probability of leaking and is located in populated areas is first priority.
Avista's Integrity Management approach provides the analytical tools that integrate key
knowledge and information needed to effectively prioritize replacement activities based
on the potential hazard. In the prioritization process, each segment of Aldyl A pipe in
Avista's system is assigned a relative risk ranking, based on its age, material, soil
conditions, construction methods, and its maintenance and leak history. This information
is then loaded into Avista's GIS database containing the gas system maps. These maps
contain a "layer" of grid squares (50 feet per side) that correspond with sections of the
Aldyl A pipe. Each square is known as a "raster" and each raster contains all of the risk-
related information that was loaded into the GIS system, as associated with the Aldyl A
pipe, at that precise geographic location.
Next, the software integrates the historic leak information for Aldyl A pipe on Avista's
system with the risk data associated with each of the Aldyl A pipe segments, and predicts
the geographic areas (via the risk rasters) where Aldyl A pipe failures are expected to be
greatest. In the last step, the software integrates the results for expected failures with
information for each risk raster that identifies the potential consequence of a leak on that
segment (i.e. the proximity of that raster to buildings and people, and the population
density/sensitivity of those structures). The end result is a color-coding of the rasters that
provides a visual picture of where on the gas system that both the potential likelihood of a
leak, and the potential consequence of a leak, are greatest. This approach provides Avista
with a comprehensive and objective means of identifying Aldyl A pipe that has the
highest priority for replacement.
Twenty-Year Proposal
Avista modeled various time horizons for the replacement program,up to a timeline of 30
years, and determined a replacement horizon in the range of twenty years to represent an
optimum timeframe for removing and replacing its priority Aldyl A pipe. Shortening
the timeline was found to have increasing cost impacts to customers but with little
improvement in the numbers of expected facility failures. Lengthening the timeline past
twenty years, however, was found to result in a substantial increase in the number of
material failures expected. A replacement timeline of 25 years, for example, resulted in
more than a doubling of the number of leaks expected when compared with the twenty
year horizon. Under the twenty year replacement program, the number of material
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 31
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 31 of 35

failures each year is expected to increase slightly until 2017, at which time the
cumulative effect of priority piping replaced since 2012 begins to check the failure count
and then drive it toward zero over the remaining course of the program(Figure 8).
Figure 8. Expected numbers of material failures in Avista's priority Aldyl A piping in
two cases:Replacement Case -piping replaced over a twentyyear horizon in the
manner proposed by Avista in this report, and Base Case- assumed that priority
piping was not remediated under any program.
-Base Case -Replacement Case
N 600
Y
fC
v 500
J
C 400
L
Q�
E 300
3
Z 200
N
fC
v 100
L
LL 0
2010 2015 2020 2025 2030 2035
Year
Importantly, Avista is not saying that experiencing an increase in leaks on our system is
"acceptable" per se, in particular, after having had two harmful incidents in the past few
years. What we are saying, however, is that by using the Integrity Management model to
prioritize work activities in the manner described above, Avista believes it can manage
the forecast Aldyl A leaks in a way that significantly reduces their potential occurrence in
areas that could result in harm. Under this approach, Avista believes it can prudently
manage the replacement of priority Aldyl A pipe with the goal to avoid harmful incidents
altogether, and at a reasonable rate impact for our customers.
Initial Optimization
Importantly, Avista's proposal for a 20-year replacement program represents an
optimization based on the information we have available today. Any number of factors
could change as the work proceeds over the first few years that could result in a `new'
optimum time horizon. Avista will be collecting new leak survey and other information
each year, and will continue to use its Asset Management models to further refine
expected trends and potential consequences, making program adjustments as appropriate.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 32
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J.DiLuciano,Avista
Schedule 1,Page 32 of 35

Responsive Replacement Program
Avista also modeled a very-different pipe replacement strategy to provide a further
measure of the efficacy of the systematic replacement program. This scenario, referred to
as the Responsive Case, was essentially a reactive approach where pipe remediation and
replacement activities would be driven by leak survey results and the magnitude of leak
consequences. Under this case, it's expected that pipe replacement activity would
commence at a lower level than in the systematic case, but would also vary significantly
from year to year, depending on patterns of detected leaks and their consequences.
Ultimately, however, the expected activity and spending levels would far exceed both the
annual and cumulative costs of the systematic approach. This is because pipe segments
are not replaced ahead of actual material failure (as happens in the structured case) and so
the resulting work activity more-generally follows the geometrically-increasing numbers
of material failures expected over time. This scenario was easily judged as failing to
provide an appropriate measure of prudence, including system safety, reliability, cost-
efficiency, or business risk. Without a prioritized replacement protocol in place Avista
would be resigned to replacing pipe in response to serious leaks and potential incidents,
after-the-fact, rather than with foresight. Such was the case with the Aldyl A
replacements Avista completed in 2011.
From a practical standpoint, Avista believes that by managing the replacement of its
priority Aldyl A pipe in a systematic way it can prudently manage potential risks and
impacts to its customers and other stakeholders, plan for and use construction resources
most efficiently, and plan more effectively for the capital and expense requirements
necessary for the effort. This is clearly the case when compared with a responsive
approach.
Dr. Palermo's Assessment of the Proposed Protocol for Managing Avista's
Priority Aldyl A Piping
Following Avista's Integrity Management evaluations of failure trends in its Aldyl A
piping, and the development of its proposed protocol, we invited Dr. Palermo to review
the completed protocol and to judge, from his expert perspective, the overall
effectiveness and adequacy of the program. Dr. Palermo completed his review in
February 2012, and judged Avista's protocol to be highly responsive and appropriate to
the management needs of the priority Aldyl A pipe in Avista's system. In particular, he
noted his support for Avista's priority focus on pre-1973 Aldyl A pipe, and on the plan to
remove and replace its pre-1984 Aldyl A mains. He further noted his agreement with
Avista's priority for remediating Aldyl A services tapped to steel main pipe, and to the
protocol of"managing in place" existing Aldyl A service piping between the mains and
meters. Finally, Dr. Palermo agreed with the proposed twenty-year replacement time
horizon for Avista's priority Aldyl A pipe, noting the reliability modeling results, and the
effectiveness of Avista's increased leak survey and application of Integrity Management
information, tools and analysis in prioritizing pipe replacement activities. Dr. Palermo
reviewed and approved this affirmation prior to the finalization of this report.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 33
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 33 of 35

Application of Avista's Washington State Study Results to Aldyl A
Pipe in the States of Oregon and Idaho
Forty-six percent of Avista's Aldyl A main pipe is currently in service in the State of
Washington, and coincidentally, so are 46% of Avista's Aldyl A services tapped to steel
mains. Since Avista's leak survey study and subsequent modeling results are based on
Washington State data, then it follows that the expected results are most applicable to this
jurisdiction. The degree to which the reliability modeling results are applicable to
Avista's Aldyl A pipe in the States of Oregon and Idaho depend on factors such as the
age of the at-risk pipe and on the known similarity of conditions under which the pipe
was installed, including method(trenching or plowing), backfill material, compaction and
squeeze-off practices, soil conditions and ambient soil temperature, etc. Avista is aware
of at least some general differences among state jurisdictions, including more favorable
soil conditions in Oregon, newer pipe materials, and construction techniques potentially
more favorable to low-ductility pipe. A contributing complication, too, is the relatively
large amount of pipe of unknown age and material in services in Oregon. This territory
was acquired by Avista from a utility that did not have a consistent practice of mapping
services, and some existing maps were lost before the purchase. As a result, Avista is
conservatively managing this `unknown' pipe as if it was priority Aldyl A pipe, until the
time that these segments are verified by records review and possible field verification.
Most important to this discussion, however, is the fact that Avista is using its Integrity
Management model to integrate leak survey and other data to develop the priority pipe
replacement activities for each year of the program. Since comparable leak survey data
from priority Aldyl A pipe in Idaho and Oregon will be included in the prioritization
analysis, then regardless of any differences that do affect the expected reliability of the
Aldyl A pipe, that inherent reliability will be automatically integrated into the modeling,
ensuring that Avista is systematically replacing the pipe at greatest risk, regardless of the
jurisdiction. Finally, since the Medford and Grants Pass, Oregon, service territory offers
a 12-month construction season, Avista will be able to continuously mitigate priority
Aldyl A piping within that area when northern territories are effectively unable to
continue working.
Resource Requirements and Expected Cost
Staffing
Avista's proposed Aldyl A pipe replacement project represents a major undertaking, even
when spread over a twenty-year horizon. In addition to the scope of the effort, there's
added complexity in efficiently managing the project, since Avista's territory extends
from Bonners Ferry, Idaho to Ashland, Oregon, a distance of over 650 miles. Each year,
the deployment of equipment and inspection and construction personnel will have to be
adjusted across this service area in response to the sites identified for highest-priority
pipe replacement in any given year. Avista is planning to coordinate with contractors to
manage much of this construction, and since this project represents a long-term
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 34
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 34 of 35

construction commitment, it is expected that the pool of contractors bidding for this work
will be substantial, resulting in advantageous pricing and flexibility of field labor.
Though much of the physical construction will be accomplished through the use of
contractors, there will still be a need to increase Avista's internal staffing to manage the
flow of information, quality assurance, mapping, and related project documentation.
Quality assurance is a critical project element that Avista will rigorously control.
Effective remediation of Avista's priority Aldyl A pipe is a critically-important corporate
objective, and we must continually ensure that sound inspection, training and auditing
delivers the results we expect. Finally, the pipe replacement activities themselves will
often have disruptive effects on our customers and others. Avista will carefully
coordinate customer and community communications and notifications in an effort to
minimize the effects of any disruptions.
Capital Costs
Avista's analysis and planning effort is projecting capital costs just over $10 million
annually from the year 2013 — 2032. Actual costs will vary somewhat depending on the
prioritization of piping to be replaced each year, among other factors, and the calculated
amounts will also be subject to an estimated 2.3% annual inflation. Avista is planning to
spend approximately $5 million in capital on this program in 2012, allowing for effective
planning with contractors, hiring Avista staff, and developing a solid project management
foundation for years 2013 and beyond.
Protocol for Managing Aldyl A Natural Gas Pipe-Avista Utilities Asset Management May 2013 35
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
I DiLuciano,Avista
Schedule 1,Page 35 of 35

Avista Utilities
Study of Aldyl-A Pipe Leaks 2022 Update
i
I
Asset Management
9/15/2022
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J.DiLuciano,Avista
Schedule 2,Page 1 of 11

Executive Summary
Avista began a program to replace all its Aldyl-A pipe in 2011 in Washington, Oregon,
and Idaho. A regulatory mandate to replace the pipe in 20 years is in place for
Washington State (2031 deadline). While not mandated to do so, Avista enabled similar
replacement timelines for Idaho and Oregon. The purpose of this report is to provide a
regulatory update on progress made. Avista provided similar updates in 2013 and 2018.
While not limited to the following, the update's primary intent is to show the amount of
pipe removed (to date), the pipe removal costs, and the impact to safety from the
remaining Aldyl-A pipe in the ground.
Washington and Idaho, despite rising costs, are on track to have all Aldyl-A pipe
replaced by 2031. It is likely the Oregon replacement will not be complete until 2037.
Several slowdowns have occurred in Oregon due to COVID-19 impacts, contractor
strikes, 3rd party contractor staffing issues, wildfires, and municipal permitting
turnaround times. Part of this study/update will target specifically the risk impact of
extending the Oregon program out additional years. While all risk cannot be eliminated,
the question to be answered is whether the Oregon extension adds substantial risk to
Avista's customers living within these service territories.'
Scope
The scope is limited to Asset Management providing a review and update on Avista's
Aldyl-A pipe replacement program. A key factor in this update is testing whether the
remaining ("in use") pipe carries an unacceptable level of catastrophic failure risk that
justifies amending the program's existing timeline 2. Based on risk levels, can the
program be extended, in Oregon, to 2037, given the delays noted above? The update
will also provide detail on the amount of pipe that has been replaced, the amount of pipe
still in active use, and the costs associated with pipe replacement. Benefit/Cost for the
program will be discussed and it is noted the primary driver for removing the pipe is the
catastrophic risk associated with the Aldyl-A pipe and not whether the program cost
justifies itself. Consideration is being given to two failure type modes: service tees and
slow crack growth. It is recognized that other failure modes exist, but these two failure
modes are unique to the Aldyl-A pipe.3
Similar safety criticality test and results will be discussed for WA, ID and OR. However, OR will be
looked at separate due to the likely extended timeline (completion by 2037).
2 Refer to Key Assumptions/Constraints. Availability Work Bench (`AWB')software was utilized to run
Safety Criticality tests for the remaining pipe still in use.
3 Remaining failure modes, considered for the Aldyl-A pipe, would not be all that dissimilar to the
replacement pipe being installed.
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J. DiLuciano,Avista
Schedule 2, Page 2 of 11

Regulatory Requirements
As of August 2011, the US Department of Transportation Pipeline and Hazardous
Materials Safety Administration (PHMSA) mandates gas distribution pipeline operators to
implement Integrity Management Plans, or in Avista's case, a Distribution Integrity
Management Plan (DIMP) in which pipeline operators are required to identify and mitigate
the highest risks within their system. For Avista, aside from third party excavation
damage, the highest risks within our natural gas distribution system is AIdyI-A Main Pipe
(Manuf. 1964-1984), and the bending stress that occurs on AIdyI-A service pipe where it
is connected to steel main pipe.
More specifically, and as related to the risks identified above, in February 2012 Avista's
Asset Management Group released findings in the "Avista's Proposed Protocol for
Managing Select Aldyl-A Pipe in Avista Utility's Natural Gas System" report. The report
documents specific AIdyI-A pipe in Avista's natural gas pipe system, describes the
analysis of the types of failures observed, and the evaluation of its expected long-term
integrity. The report proposed the undertaking of a 20-year program to systematically
replace select portions of AIdyI-A medium density pipe within its natural gas distribution
system in the states of Idaho, Oregon, and Washington.
Subsequently, the Gas Facility Replacement Program's (GFRP) was formed as the
operational entity committed to structuring and implementing a systematic approach to
mitigating the AIdyI-A pipe risks as identified in aforementioned report.
On December 31, 2012, the Washington Utilities and Transportation Commission
(WUTC) issued its policy statement on Accelerated Replacement of Pipeline Facilities
with Elevated Risks which requires gas utility companies to file a plan every two years for
replacing pipe that represents an elevated risk of failure. The requirement to file a Pipe
Replacement Plan (PRP) commenced on June 1, 2013. In response to this order, Avista's
first 2-year PRP for 2014-2015 was submitted and approved in 2013 per Docket PG-
131837, Order 01. Avista's second two-year PRP for 2016-2017 was submitted in 2015
and approved in 2016 per WUTC Docket PG-160292, Order 01. Avista submitted a PRP
in June 2017, and 2019. In Avista's filings, the 'Avista's Proposed Protocol for Managing
Select Aldyl-A Pipe in Avista Utility's Natural Gas System" report serves as the pipe
replacement "Master Plan", and two-year pipe replacement goals which includes specific
project locations, and the anticipated pipe replacement quantities.
On March 6, 2017, the Public Utility Commission of Oregon ("OPUC") issued Order
17-084 (Docket UM 1722, Investigation into Recovery of Safety Costs by Natural Gas
Utilities), which in part required each of the natural gas distribution companies serving
customers in Oregon to file with the OPUC by September 30th each year an annual
"Safety Project Plan" (or Plan). The purpose of the Plan is to increase transparency into
the investments made by each utility that are based predominantly on the need to achieve
important safety objectives. More specifically, the Plan is intended to achieve the following
objectives:
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J. DiLuciano,Avista
Schedule 2, Page 3 of 11

• Explain capital and expenses needed to mitigate safety issues identified by risk
analysis or new federal and state rules.
• Demonstrate the utility's safety commitment and priority to its customers.
• Provide a non-technical explanation of primary safety reports each utility is
required to file with the OPUC's pipeline safety staff; and
• Identify major regulatory changes that impact the utility's safety investments.
The Idaho Public Utilities Commission (IPUC) has not required gas utility companies
to submit an action plan, Avista has submitted the "Avista's Proposed Protocol for
Managing Select Aldyl-A Pipe in Avista Utility's Natural Gas System" report for review
and communicates annual pipe replacement goals which includes specific project
locations, and the anticipated pipe replacement quantities.
Key Objectives/Assumptions/Constraints
Key Objective:
Utilizing a Safety Criticality test, demonstrate whether an unacceptable risk of
catastrophic failure exists on the remaining Aldyl-A pipe. Assuming a test failure,
alternative approaches would be considered, including moving up, rather than extending
timelines. Through this same test, confirm whether a timeline extension in Oregon is
appropriate given the risk parameters set around this program. In addition, provide an
update on progress made (to date) and discuss the costs involved with this program.
Key Assumptions/Constraints:
Weibull Curve
• Utilizing data from prior updates, existing leak data, and input from Subject
Matter Experts, the Weibull curve parameters were established. Existing pipe
data was incomplete for building out the model due to the fact it has yet to
complete a full life cycle. Therefore, the existing data set required certain
assumptions to be made to build out the model.
o ETA, 80 years.4
o Beta, 4.5
• Unit quantity based on size of Phase replacement. Oregon = 1,025 feet (Phase).
Washington/Idaho = 2,000 feet (Phase).6
4 Assumes 63.2% of all pipe sections will have experienced a failure within 80 years of installation.
5 Beta < 1, Infant Mortality, Beta = 1, Random Failure, Beta > 1, Long Term Failure. In line with 2018
study that used a 3.95 Beta for Rocky Soil and 4.02 for Sand.
6 A 10,000-foot stretch of pipe would equate to 5 units for WA/ID and 10 units (rounded)for OR.
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J. DiLuciano,Avista
Schedule 2, Page 4 of 11

Failure Mode(s)/Consequences
• Failure modes utilized in this update:
o Slow crack growth
o Service Tees.
• Leak data is from 2011 (program start date) to 2021 and was provided by
Avista's Manager, Natural Gas Pipeline Integrity.
• Effects (consequence of failure), for modeling purposes, were limited to
catastrophic failure. Failures, both catastrophic and non-catastrophic, would
require immediate replacement. However, the costs to repair a non-catastrophic
failure are immaterial to the overall results, do not impact the Safety Criticality
test, and do not provide cost justification for the overall program.
o Catastrophic Failure cost, $20,000,000.
o Catastrophic Event occurrence, 1 every 40 years.
■ Redundancy Factor, 0.00125, based on an assumed 20
leaks/year.'
• Inspections are successful in detecting leaks but not necessarily preventing
future leaks. Therefore, the Potential Failure/Functional Failure (P-F) Interval on
leak detection = 0.8
Safety Criticality Test
• Safety Criticality Test models the likelihood of a catastrophic failure over a certain
time period.
• Test parameter, 1 failure in 40 years.9
• Lifetime model simulation, 10 years. Assumes all or most of the remaining pipe
will be replaced in the next 10 years; Oregon is likely to be complete in 15 years.
• Test simulation run for each year of the 10-year period. When the next year is
modeled, the pipe is aged 8,760 hours (1 year) and the amount of expected pipe
to be removed (prior year) is subtracted from the total.
• Oregon replacement assumed to be 15 years. Therefore, residual safety risk
exists, for Oregon, after the 10-year run period. Approximately 56 miles of pipe,
to be replaced, will remain in Oregon after 10 years.
• Safety Criticality results >_ 1 = failure.
• Safety Criticality test run separately for Idaho & Washington and Oregon, given
the expected different timeline to completion for Oregon.
28 leaks were detected in 2020 (WA/ID/OR)while 18 were detected in 2021. 20 leak assumption is
conservative based on pipe replacement program which reduces mileage annually. Less pipe in the
ground assumes fewer leaks.
8 Assumes a pipe section passes a leak test but could fail as soon as the next day. Inspection does not
create safe period for risk avoidance. Test is limited to determining whether an existing leak exists.
9 For clarification, 1 or greater failures over a 40-year period would indicate a test failure.
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J. DiLuciano,Avista
Schedule 2, Page 5 of 11

Linear Regression Assumptions
• Linear Regression analysis based on the leak data from 2011-2021.
• All slow crack growth and service tee leaks are included. Additional leaks, not
specific to Aldyl-A, are removed from consideration as those leak types would
occur with non Aldyl-A pipe.10
• Leaks per mile are determined by comparing total leaks to in use pipe remaining
(end of year).
Results/Findings
Safety Criticality threshold not exceeded: (Test Passed)
Safety Criticality Test was built in Availability Workbench (refer to Key Assumptions,
above). As already noted, the Safety Criticality Test was built around the probability of
a catastrophic event occurring in the next 10 years. Based on the replacement
schedule, the test is passed in all instances for Idaho/Washington and Oregon.
Therefore, a critical failure is highly unlikely throughout the remainder of this program
(refer to chart below).
Safety Criticality Test, Aldyl-A Replacement
(Safety Criticality> 1 = Failure)
1.2
1
0.8
v
0.6
0.4
0.2
0
2020 2022 2024 2026 2028 2030 2032
Critcality Projection,by Year
OR -WA/ID -Threshold/Limit
• Safety criticality test success does not eliminate all risk. Rather, the likelihood of
a catastrophic failure is unlikely."
10 Purpose of the study is to isolate those leaks (failures)specific to Aldyl-A.
" Safety Criticality Test factors in number of prior leaks, age of pipe and the planned replacement
schedule.
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J. DiLuciano,Avista
Schedule 2, Page 6 of 11

• Declining trend supported by pipe replacement. The pipe that is replaced is
removed from future test consideration. Example: 300 miles of in use pipe
remains. 40 miles is removed in year 1. Year 2 calculation would be based on
260 miles of in use pipe (300-40=260 miles).
• Residual risk remains for OR after 2031 because the OR portion is not expected
to be completed until 2037. WA/ID assumes all pipe is removed by 2031.
Linear Regression Analysis shows stable trend and overall risk reduction:
The Linear Regression Model (below) measures the number of hazardous and non-
hazardous leaks since 2011.12 The leak rate per mile can be determined through linear
regression. As shown, there has been a slight uptick in the number of leaks per mile
but the overall the trend is relatively flat and stable.
Leaks Per Mile (Historical), Linear Regression Model y=0.0011x-2.0989
RZ=0.036
0.12
0
z 0.1 -
0
0.08
0.06 _
0.04
0.02
x
0
2010 2012 2014 2016 2018 2020 2022
Historical Year
• Low R2 suggests randomness in the data set but is consistent with the age of the
pipe (yet to experience long-term wear out, therefore subject primarily to random
failures and infant mortality).
• Trend line is relatively flat and while ticking up, it does not suggest a near-term
material concern that supports changing the project's timeline.
12 Linear Regression includes slow crack growth leaks and service tee problems experienced since 2011
for OR, ID and WA (combined). Hazardous and Non-hazardous leaks relate to the immediacy for a
response. A hazardous leak does not mean a catastrophic failure has occurred.
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J. DiLuciano,Avista
Schedule 2, Page 7 of 11

Utilizing the linear regression equation (chart, above, top-right), the expected number of
leaks can be plotted against anticipated remaining pipeline in the ground at end of year.
Projected Leaks, Linear Regression Model
30
y
0
0
25
ea
N
z 20
c
0
y 15
0
0
10
N
fC
y
x
a
a 0
w
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032
Year
The Projected Leaks, Linear Regression Model (above) demonstrates continued risk
reduction through pipe replacement and covers the combined service territory (WA, ID,
and OR). The modeling does not indicate a need for any material adverse changes in
the program's timeline and supports extending Oregon an additional five years (due to
already mentioned delays in Oregon). Risk for a catastrophic failure remains but the
chances of such an event occurring are remote. In addition, the leak survey program
serves as an additional mitigant as many of the past leaks have been detected, through
the program, and remedied.
Program is on schedule to be completed in time in WA and ID. Additional time is
needed in OR (2037):
Completion in WA and ID is expected by 2031; the project remains on schedule for both
states. Oregon is expected to be completed by 2037. As noted in the Executive
Summary, delays have occurred in Oregon due to COVID-19 impacts, municipal
permitting delays, wildfire, and 3rd party contractor strikes, to name a few.
The chart below measures mileage completed (to date) and mileage planned against
budget costs. 13
13 Source: GFRP Historic Program Analysis Asset Management V.2
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J. DiLuciano,Avista
Schedule 2, Page 8 of 11

PROGRAM PLANNED BUDGET VS ACTUAL SPEND AND MILES COMPLETED
S40A00.000 SOlp
43.98
4s
S35.000.000
4a4B
S30A00.000
.99 L64 33.40 31.94 35.00
43
S25.000.000
3000
25
S20,",00u 2232 23.23 25.00
19A6
Sss,aa0,0go zo.ao
12. MW
$10,000,000
g.50 g.50 8.50 8.50 8.50
93 10.00
S5A00,000
SAO
S wgD
2011 MU MH 2014 2015 2016 2012 NU W19 2020 2021 2022 2023 2024 2025 2026 2022 2M 20M MW W31 2032 2033 2034 2035 M36 2032
—P NEDBUDQ A UA COST —MANNM NNIS —GRPTOTXWMP EDMM
The table below shows progress in aggregate terms by listing out the amount of pipe in
the ground at the end of 2011 versus 2021. It highlights the slower progress being
made in Oregon but overall demonstrates the program is on track for completion. It
should be noted, however, budgets are tentative and subject to revision, based on14:
• Schedules and miles completed (prior year)
• Distribution Integrity Management Plan (DIMP) Analysis
• Budget Constraints
Any material changes in dollar amounts made available to the program could limit its
progress going forward.
State Pipe Remaining Pipe Remaining Percent Complete15
(EOY 2011, Miles) (EOY 2021, Miles)
Washington 353 208 41%
Oregon 253 178 30%
Idaho 131 77 41%
Total 737 463 37%
Opportunity Work 385 48%
• Note. As of January 2022, an additional 78 miles of pipe replacement has been
completed, outside of the program, through opportunity work done by local
14 Budget and actual costs incorporate all planned work within the program: major main work, minor
opportunity work, STTR work, priority services, and Aldyl-A replacement(cross bore).
15 Includes `Good' miles. `Good' pipe is pipe that was manufactured and installed in 1985 and 1986 and
does not need to be replaced. It is found during the year through potholing and map editing. This
amount is combined with the construction completed amount to arrive at the annual total.
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J. DiLuciano,Avista
Schedule 2, Page 9 of 11

districts, pipe verification and map editing. Therefore, the overall project is closer
to being 50% complete.
The program is getting more expensive as the cost per foot (CPF) has increased:
Replacing natural gas facilities decades after the initial installation, and after the
subsequent development of the service areas is challenging. Replacement pipe must be
installed in fully developed and occupied areas that consist of numerous below ground
facilities, paved streets, sidewalks, arterials, landscaped residential neighborhoods, and
hard-surfaced commercial developments teeming with daily traffic and other activity.
New main pipe is most often installed by either "horizontal drilling" or open trenching.
While horizontal drilling is far less invasive, both methods require cutting into existing
pavement or other hard surfaces. Care must be taken to plan and locate the existing
underground facilities to avoid damaging them, new service lines must be ditched into
landscaped yards, etc., and all these features must be restored to unblemished service
once the installation is complete.
During the first two years of the program Avista reported average per foot replacement
costs ranging from $69 to $83 per foot. These costs included pipe replacement in hard-
surfaced areas as well as areas of exposed soil, such as the shoulder of semi-rural
roadways with limited adjacent facilities and road restoration. More recently, Aldyl-A
pipe replacement project locations have been primarily located in suburban
developments in which the right-of-way is fully built-out with paved roads and sidewalks
and has required increased permitting stipulations. As a result of these conditions, pipe
replacement costs have increased. In 2021, the average cost of main pipe replacement
was $122/LF (per linear foot), with a low of$ $90/LF in Klamath Falls and a high of
$155/LF in the City of Medford.
Avista continued to report its experience with replacement construction costs, in
particular, as we experienced a trend on the part of municipalities toward more
restrictive and expensive roadway restoration and traffic control requirements. Over the
past several years these traffic control, pavement cutting, and remediation policies of
local jurisdictions have had a significant impact on the scheduling, logistics, operational
methods, extent of the area to be repaved, and the ultimate cost of pipe replacement. In
Avista's experience, this continuing trend to enforce more restrictive moratoria on
cutting in newer arterials and streets, to require more stringent requirements for backfill
and compaction, for patching or repaving of streets cut for pipe replacement, and traffic
control requirements have had a substantial impact on installation costs.
The chart below shows the average cost per foot from 2011-2021 for all three states.
The actual pipe replacement costs are higher in Oregon. The major element of the total
cost disparity is related to road restoration requirements in Oregon jurisdictions. These
higher construction costs are a direct result of municipally driven traffic control permit
requirements (e.g. plate locks), material handling requirements that include 100%
export and import of trench backfill materials (e.g. slurry backfill), significant soil
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J. DiLuciano,Avista
Schedule 2,Page 10 of 11

compaction the width of pavement restoration, which averages 4 feet and can range
from 2 feet up to 8 feet for segments of a project all which are beyond Avista's direct
control.
PROGRAM PLANNED BUDGET VS ACTUAL SPEND AND MILES COMPLETED
S40,000,000 5160
514]
$35,OOOA00 $134 $]3J
Sla0
$122 $122
530,000A00 $116 SOO
51
525.000,000 Sim
6
520.000.000 $70 $76 6 S.
515.000AOo SW
S101o00,000 540
$S,000Afp ■ , " " " �0
20D 2012 A13 MM MB M16 AR7 2= 20" WM A21 2022 2023 2020 2026 2026 2027 MM MA MW 2031 2032 2033 MM NBS MM M37
—FIANNEDBUD6 —ACFUMCOA —OWRA AWE EUF
• CPF has increased steadily since the program's inception.
• The program does not cost justify itself in that the actual and planned spends far
exceed the dollar costs associated with a catastrophic failure.16
Summary of program changes for Oregon
While taking into consideration the extension of Oregon's Aldyl-A pipe replacement to
2037, there has been extensive analysis and research completed to ensure risk does
not increase. As previously stated, various slowdowns have occurred which have
impacted program timelines relating to work in Oregon. Impacts such as COVID-19,
contractor strikes, contractor staffing issues, wildfires, municipal restrictions and
municipal permitting delays have all created significant effects on operations and made
replacement efforts much more challenging. Extending Avista's Aldyl-A replacement
work in Oregon to 2037 will allow us the opportunity to balance affordability and overall
impact to our customers. The data in this report supports that risk is continuing to be
mitigated and that extending work in Oregon will not increase the risk of catastrophic
failure.
16 Cost associated with a catastrophic failure is $20,000,000 and is based on the following risk formula to
determine its annual value: Pf*Pc *c, where Pf=Annual probability of failure, Pc =Annual
probability of consequence, and c = consequence cost($20 million). This annual amount can then
be measured against the annual spend.
Exhibit No. 10
Case No.AVU-E-25-01 &AVU-G-25-01
J. DiLuciano,Avista
Schedule 2, Page 11 of 11

Exhibit No. 10, Schedule 3
Capital Investment Business Case Justification Narratives Index
Business Case Name Page Number
Electric Distribution Capital Proiects
Distribution Grid Modernization 3
Distribution Minor Rebuild 15
Distribution System Enhancements 25
East CDA Lake Reinforcement Program 40
Elec Relocation and Replacement Program 56
Electric Storm 65
Joint Use 73
Meter Minor Blanket 84
Metro 115kV Substation 92
New Revenue - Growth 114
Substation-Asset Condition 121
Substation- Performance and Capacity 134
Substation Failed Plant 150
Wood Pole Management 157
Electric Transmission Capital Proiects
Ambient-Adjusted Transmission Line Ratings 171
Colstrip Transmission 180
Electric Storm 187
SCADA - SOO and BuCC 195
Substation-West Plains System Reinforcement Project 208
Transmission - Minor Rebuild 221
Transmission Construction- Compliance 228
Transmission Critical Crossing Reinforcement 237
Transmission Major Rebuild- Asset Condition 249
Transmission NERC Low-Risk Priority Lines Mitigation 260
Westside 230/115kV Station Brownfield Rebuild Project 266
Natural Gas Distribution Capital Proiects
Gas Above Grade Pipe Remediation Program 273
Gas Cathodic Protection Program 284
Gas Facility Replacement Program (GFRP) AIdyl A Pipe Replacement 293
Gas Isolated Steel Replacement Program 307
Gas Non-Revenue Program 322
Gas PMC Program 336
Gas Regulator Station Replacement Program 346
Gas Reinforcement Program 359
Gas Replacement Street and Highway Program 371
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J.DiLuciano,Avista
Schedule 3,Page 1 of 535

Gas Telemetry Program 379
Gas Transient Voltage Mitigation Program 390
Jackson Prairie Natural Gas Storage Facility 401
New Revenue - Growth 409
General Plant& Fleet Investments Capital Proiects
Capital Equipment Program 416
Central 24 HR Operations Facility 428
Fleet Services Capital Plan 447
Palouse Service Center 462
Right-of-Way Use Permits 479
Sandpoint Service Center 486
Structures and Improvements/Furniture 504
Telematics 2025 523
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J.DiLuciano,Avista
Schedule 3,Page 2 of 535

DocuSign Envelope ID: CEF1520C-4F79-4BlA-A653-5lD5D4E2CEFO
Distribution Grid Modernization
EXECUTIVE SUMMARY
Avista's distribution system has numerous facilities at, or near,the end of their useful life. Over decades, many
of these were built to different construction standards using a wide variety of materials. These factors contribute
to energy losses due to inefficiencies due to age and vintage of materials and technology, and increased outages
that take longer to restore and fall short of modern expectations that utilities face.
The Grid Modernization Program(GMP) is a capital program that was established in 2013 to holistically
evaluate and address the improvement of Avista's approximately 11,300 circuit miles of overhead and
underground primary electric distribution infrastructure. The goals of the program address service reliability and
cost avoidance.
Service Reliability
Increase system and service reliability through targeted replacement of aging and failed infrastructure, removal
of low reliability equipment and construction practices, relocation or reconfiguration of high-risk outage
locations, and the addition of devices and equipment that improve service continuity.
Avoided Costs
Increase energy efficiency efforts through the replacement of equipment and materials that have increased
energy losses, improvement of line losses through voltage and VAR optimization, load balancing, and the
addition of devices and equipment that improve circuit efficiency.
The program was updated and re-approved in 2020 with a recommended solution based on an updated average
cost per mile requiring a $28.88M annual investment to achieve a 60-year cycle. $77M in funding was
requested over a 5-year duration as a ramp up to recommended funding levels. Since approval,priority and
resources have been re-allocated to mitigate wildfire risk which includes approval and execution of Grid
Hardening projects under the Wildfire Resiliency Program. The Grid Modernization program schedule was
updated in 2022 to account for reduced budget allocation by extending project design and construction duration.
Upon the completion of GMP projects which are defined per distribution feeder, Washington and Idaho
customers benefit from improved system reliability, safety, and performance. These can be measured by a
reduction in outage frequencies and durations in addition to power quality metrics. Delaying the business case
increases the likelihood and severity of various risks including equipment failure, wildfire, and energy losses. A
delay would also impact the cycle time of Avista's Wood Pole Management Program(WPM). Not approving
the business case places the responsibility of rebuilding the system on the individual offices throughout the
company which are responsible for daily maintenance and operations as well as new revenue projects.
Additionally, it jeopardizes the ability to holistically address system wide performance.
VERSION HISTORY
Version Author Description Date
1.0 Robb Ra mond BCJN Final Draft 5/3/2024
BCRT BCRT Member-Katie Snyder Has been reviewed by BCRT and meets necessary 0510812024
requirements
Grid Modernization Business Case Justification Narrative Template Version:February2023 Page 1 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J.DiLuciano,Avista
Schedule 3,Page 3 of 535

DocuSign Envelope ID: CEF1520C-4F79-4B1A-A653-51D5D4E2CEF0
Distribution Grid Modernization
GENERAL INFORMATION
PLANNED SPEND AMOUNT($) PLANNED TRANSFER TO PLANT($)
2025 $1,022,000 $1,096,660
2026 $803,400 $805,096
2027 $852,600 $776,244
2028 $957,000 $957,000
2029 $0 $0
Project Life Span 1 year, 5 years, 10 years, etc.
Requesting Organization/Department Asset Maintenance
Business Case Owner I Sponsor Robb Raymond I Paul Good
Sponsor Organization/Department Asset Maintenance
Phase Execution
Category Program
Driver Customer Service Quality& Reliability
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information conveying the benefit to
the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
The Grid Modernization Business Case (GMP) was developed to address the aging and failing
infrastructure found throughout the electric distribution system. Other issues that are addressed include
sub-optimal system performance and inaccessible facilities that drive increased routine maintenance costs.
Outage durations and frequencies and power quality problems are also targeted for improvement through
the installation of automated devices. Safety is also a key benefit of the Program as Grid Modernization
projects bring facilities up to current NES and Avista construction standards, fulfill the efforts of Wildfire
Resiliency, and address structures located within the control zone of roadways subject to Washington
State's Department of Transportation Target Zero requirements.
1.2 Discuss the major drivers of the business case.
The GMP business case is driven by asset condition, performance and capacity. Customers benefit from
improvements in electric distribution infrastructure in the following ways:
Grid Reliability
Proactively replacing aging and failed infrastructure that has high likelihood of creating customer outages
reduces higher cost unplanned callouts which are ultimately passed on to the customer. Without programs
like Grid Modernization and Wood Pole Management,there would be an average of 40 pole failure events
per year affecting an average of 80 customers for 4.8 hours per event. The total customer impact value of
Grid Modernization Business Case Justification Narrative Template Version:February 2023 Page 2 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 4 of 535

DocuSign Envelope ID:CEF1520C-4F79-4131A-A653-51D5D4E2CEF0
Distribution Grid Modernization
these events is approximately $24,000 per event totaling $960,000 per year. (2017 Wood Pole
Management Program Review and Recommendations, Rodney Pickett).
Energy Efficiency
Replacing equipment such as old or undersized conductors and transformers that have high energy losses
with new equipment that is more energy efficient and with better performance.
Operational Ability
Replacement of conductor and equipment that hinders outage detection and install automation devices
that enable isolation of outages.
a. This leads to shorter duration of outages for customers because areas that have failed can be
more quickly identified and there is a potential to reroute power automatically.
b. Installation of automated line devices on a feeder of 1,600 customers reduces an average outage
duration from 3 hours to 5 minutes for 1,200 of those customers.
c. Potential reduction in hotline holds.
Safety
Focus on public and employee safety through smart design and work practices.
a. Replacing aging and failed infrastructure puts employees and customers at risk.
b. Infrastructure is brought up to current National Electric Safety Code
c. Eliminating PCB risk to the public and environment by eliminating transformers with known
PCBs.
d. Lowers risk of high severity safety(S4) events, defined below as follows:
• Having potential for multiple serious injuries or loss of an individual life, major damage
to property or business, and a public health infrastructure impact up to 72 hours.
• Base case (do nothing) has the risk of 10 S4 events every 50 years with a total cost of
$52.3 million. Grid modernization brings this risk down to 2 events in 50 years with a
total cost of$10.4 million (2017 Wood Pole Management Program Review and
Recommendations, Rodney Pickett.)
e. Address Washington State's Department of Transportation(WSDOT) Target Zero requirements,
which states that utilities move all non-breakaway structures such as power poles and pad mount
transformers out of highway clear zones as defined in the 10/2005 AASHTO "A guide for
Accommodating Utilities Within Highway Right-of-Way". Washington law requires that this
task is completed by 2030. Additional control zone justifications are included in following
Washington Administrative Codes (WAC) and Revised Codes of Washington(RCW):
• WAC 468-34-350- Control Zone Guidelines
• WAC 468-34-300- Overhead Lines Location
• RCW 47.32.130 Dangerous Objects and Structures as Nuisances
• RCW 47.44.010 Wire and Pipeline and Tram and Railway Franchises- Application-
Rules on Hearing and Notice
• RCW 47.44.020 Grant of Franchise- Condition- Hearing
Grid Modernization Business Case Justification Narrative Template Version:February2023 Page 3 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J.DiLuciano,Avista
Schedule 3,Page 5 of 535

DocuSign Envelope ID:CEF1520C-4F79-4l31A-A653-51D5D4E2CEF0
Distribution Grid Modernization
1.3 Identify why this work is needed now and what risks there are if not approved or if
deferred or risks being mitigated by the request.
Delaying the work performed by the GMP would result in an increased risk of equipment failure,
continued energy losses over time, expanded system maintenance costs, and unplanned outages. There
would also be a lost opportunity to apply holistic and sustainable solutions following an in-depth
engineering analysis to locations that experience recurring unplanned outages.
1.4 Discuss how the proposed investment, whether project or program, aligns with the
strategic vision, goals, objectives and mission statement of the organization. See link.
Avista Strategic Goals
Improvements to Avista's electric distribution system through the Grid Modernization program are an
example of proactive efforts that focus on the customer's best interests serving them now by improving
reliability as well as preparing for the future addressing capacity. Avista also must be responsible for
mitigating risks that increase over time as infrastructure ages which impact customer and employee safety.
1.5 Supplemental Information — please describe and summarize the key findings from any
relevant studies, analyses, documentation, photographic evidence, or other materials
that explain the problem this business case will resolve.'
In an increasingly digitized world, power quality now plays a major role; even small transients or
fluctuations can be more disruptive than full power loss. The value of lost service is growing each year as
people depend more and more on what they consider essential services. Thus, Avista will continue to
explore how resiliency fits into our overall reliability strategy. In addition, given the very long life of our
electric transmission and distribution assets as well as the size of the investments and timeframe required
to significantly change their overall performance, frequently revisiting our reliability and resiliency
objectives will help us make targeted and timely adjustments to our strategy in ways that meet customer
expectations and deliver the greatest optimized value.
Indicators of GMPs impact on feeder reliability are discussed below. The following graph as reported on
page 69 of Avista's Electric Distribution Infrastructure Plan illustrates the positive correlation of the
number of system wide outages relative to the number of outages on feeders treated by the Feeder Upgrade
and Grid Modernization programs.
Please do not attach any requested items to the business case, rather be sure to have ready access to such
information upon request.
Grid Modernization Business Case Justification Narrative Template Version:February2023 Page 4 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J.DiLuciano,Avista
Schedule 3,Page 6 of 535

DocuSign Envelope ID: CEF1520C-4F79-4BlA-A653-5lD5D4E2CEFO
Distribution Grid Modernization
Sustained Outages Compared with Grid Modemization Feeder
2500 120
v 100
2000
Feeder Upgrade Program Begins in 2009 �o
$ 80 O
11 1500 Grid Modernization Program v
y (Current Scope)Begins in
3 2013 60 LL
E
1000
s 40
500
z 20
0 0
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
®System Wide Feeders —Grid Mod Feeders
Secondly, A study was conducted by Asset Maintenance to measure the effectiveness and efficiency of
holistically executing the planning and construction of multiple asset maintenance programs at once on a
single feeder. The programs that were included in this model were Grid Modernization, Wood Pole
Management and Transformer Change Out. Customer Internal Rate of Return (CIRR)was utilized to
compare different program refresh models and integrating the three provided the highest value to the
customer. Avista provided results of such a financial analysis in response to PC-DR-221, Attachment A,
which is the Company's 2017 Wood Pole Management Program Review and Recommendations (see
Exh. JD/LL-2, pages 2-94).
The lifecycle cost analyses reported were based on the output of 172 different Availability Workbench
models integrated together to provide optimized solutions for individual assets and programs including
the transformer changeout work as part of the Wood Pole Management and Grid Modernization
programs, which is identical to its application in Distribution Minor Rebuild. Including transformer
changeouts with the program reduced the total lifecycle cost to customers by $18.3 million in direct
costs and by $46.9 million in risk costs, for a combined reduction in lifecycle costs to customers of
$65.2 million, compared with the "Run-to-Fail" alternative of allowing the transformers and attached
equipment, including the cutout to fail in service and returning to the feeder later to replace them one at
a time. (See Exh. JD/LL-2,pages 52-54).
Grid Modernization Business Case Justification Narrative Template Version:February2023 Page 5 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J.DiLuciano,Avista
Schedule 3,Page 7 of 535

DocuSign Envelope ID: CEF1520C-4F79-4131A-A653-51D5D4E2CEF0
Distribution Grid Modernization
1 Illustration No.8—Lifeewle Cost Analvsis of Av ista's Grid Modernization Program as
Optimized with Wood Pole Management and Transformer Replacements9l
3
Lifecycle Cost Analyses for Grid Modernization,Wood Pole
Management and Transformer Replacements
5 9.0
7.94
810 7.1
6 7.0
5.85
6.0 5.15
7
SA 4.35
N
£ 4.0
8 0
N 3.0
9 u 2.0
1.0
10 0.0
Grid Mod Alone Grid Mod Alone Grid Mod Alone+ Wood Pole Wood Pole+
11 60 Year Cycle 20 Year Cycle Transformers Alone+ Grid Mod+
20 Year Cycle Transformers Transformers'
12 20 Year Cycle
13
2. PROPOSAL AND RECOMMENDED SOLUTION - DESCRIBE THE
PROPOSED SOLUTION TO THE BUSINESS PROBLEM IDENTIFIED ABOVE
AND WHY THIS IS THE BEST AND/OR LEAST COST ALTERNATIVE (E.G.,
COST BENEFIT ANALYSIS).
2.1 Please summarize the proposed solution and how it helps to solve the business
problem identified above.
Follow the approach as stated in Avista's Electric Distribution Infrastructure Plan where the holistic scope
of this program addresses reliability efficiency and effectively as part of the larger objective, Grid
Resiliency. CPG funding has been re-directed through 2029 to mitigate wildfire risk, continue Grid
Modernization efforts in parallel at reduced pace.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other information that was
considered when preparing this business case (i.e., samples of savings, benefits or risk
avoidance estimates; description of how benefits to customers are being measured;
metrics such as comparison of cost ($) to benefit (value), or evidence of spend amount
to anticipated return).2
Reliability improvements have been quantified that are a direct benefit to the customers in feeders that
GMP has addressed. The analysis was performed by comparing reliability metrics in years before and
after the GMP for all feeders completed through 2018. Figures 1-4 show these reliability metrics, and
the raw data and analysis is located in the workpaper "Grid Mod Reliability Data Analysis Before and
After.xlxs"
2 Please do not attach any requested items to the business case, rather be sure to have ready access to such
information upon request.
Grid Modernization Business Case Justification Narrative Template Version:February 2023 Page 6 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 8 of 535

DocuSign Envelope ID: CEF1520C-4F79-4B1A-A653-51D5D4E2CEF0
Distribution Grid Modernization
CEM13 is the percentage of customers experiencing SAiFi is the Sustained Average interruption
3 or more interruptions per year. The data shows Frequency index. The data shows that customers on
that customers on feeders that have been addressed feeders addressed by the GMP experience a 51%
by the Grid Modernization Program experience a reduction (with MED) and a 64% reduction in the
61% reduction when major event day (MED) are duration of power interruptions.
not included and a 54% reduction when MED are
included. SAI FI Before and After GM
1.8
1.6
Average CEM13 Before and After GM 1 a
12.0% 1.2
1.0 ■curriwaivea age before G red
10.0% Mod
0.8
■ - ■cumulative aerage pos Grid
84% 0.6 R Motl
■cumutacrve average before 0.4
6.0% Gritl Mod
0.2
■cumulative arer epo4 Grid -
4:0% Mod 0.0
w/oMED w/MED 'Errorlbrs-1.Ai
2.D%
0.0% lo MED w/MED 'Error hors-]5D Figure 1.2B: SAIFI before and after Grid
v�
Modernization on feeders completed through the
end of 2018.
Figure 1.2A: Average CEM13 on feeders that have
been fully addressed by GMP. This includes all the
feeders completed through the end of 2018.
SAiDi is the total duration of interruptions CAiDi is the Customer Average Duration index, which
experienced by customers (in this case, the indicates the amount of time it takes to restore service.
customers on one feeder). Customers on feeders Customers experience an 11% reduction (without MED)
addressed by the GMP experience a 64%reduction and an 18%reduction with MED after GMP.
(without MED) and a 73% reduction with MED
CAI DI Before and After GM
included. This means that the outages customers
184.4
experience are shorter in duration. 1600
SAI DI Before and After GM 140.0
300.0 120.0
100.0 ■cum ula[.ive a erege b lw e Grid
Mod
250.0
B0.0 ■cum ulaCrve aerage po5 Grid
200.D 60.0 Mod
■tumuierrve—g-l Ef— 409
1500 Gritl Mod
20.0
■cumularive arerage pos Gritl
100.0 Mod 0.0
w/o MED w/MED 'Ermr burs-ISD
50.0 ,
flfl Figure 1.2D: CAIDI before and after being addressed
w/oMm wr MED 'Errrxmrs-I� by the Grid Modernization Program.
Figure 1.2C: SAiDi before and after GMP for feeders
completely addressed by the end of 2018
Looking forward, the Company will be evaluating options for establishing what we refer to as
"actionable"goals and targets for reliability that will complement lagging outage frequency and duration
metrics.
■ That are within the control of the Company.
■ That have a demonstrable impact on the reliability of our system.
■ That are needed to support our overall reliability objectives.
Grid Modernization Business Case Justification Narrative Template Version:February 2023 Page 7 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 9 of 535

DocuSign Envelope ID:CEF1520C-4F79-4B1A-A653-51D5D4E2CEF0
Distribution Grid Modernization
■ That are cost-effective and make sense for our customers.
The objective of the program is realizing the most value gained by addressing service reliability, cost
avoidance, and operational efficiencies by holistically treating a feeder with a comprehensive scope
derived from the following asset maintenance programs '.
■ Wood Pole Management Program
■ PCB Transformer Change Out Program
■ Vegetation Management
■ Segment Reconductor and Feeder Tie programs
■ Distribution Device Management program
2.3 Summarize in the table, and describe below the DIRECT offsets3 or savings (Capital
and O&M) that result by undertaking this investment.
Feeder health addresses how asset condition affects reliability where there are direct O&M savings due to
a reduction in the average number of equipment outage events incurred per year based on asset condition.
Capital offset figures are estimated by feeder based on feeder analysis information provided to the
Commission in PC-DR-110 (referenced in WUTC Rebuttal 200900-901-AVA-Exh-JD-LL 1-
T_05_26_2021) Docket No. UE-200900, UG-200901, UE-200894).
Offsets Offset Description 2025 2026 2027 2028 2029
Capital n/a n/a n/a n/a n/a n/a
O&M Reduction in Service Calls $101,839 $161,456 $198,726 $208,412 $208,412
Basis of estimation4:
■ The capital offset figure was captured from the respective feeder status report.
■ Figures were calculated by Asset Maintenance via the EVENTS Access Database
■ Looks at only number of O&M equipment outage events per year.
■ The following O&M Outage sub-reason events were used to model direct cost savings:
1. Conductor—Primary 6.Lightning 10.Undetermined
2. Conductor—Secondary 7.Pole Fire 11.Weather
3. Connector—Primary 8.Regulator 12.Wildlife Guard
4. Connector—Secondary 9. Snow/Ice 13.Wind
5.Elbow
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work under this business
case. Such savings could include reductions in labor, reduced maintenance due to new equipment, or other.
4 Capital offsets were calculated in the workpaper "Grid Mod Cost and Schedule Management Baseline.xlsx"
Grid Modernization Business Case Justification Narrative Template Version:February2023 Page 8 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J.DiLuciano,Avista
Schedule 3,Page 10 of 535

DocuSign Envelope ID:CEF1520C-4F79-4131A-A653-51D5D4E2CEF0
Distribution Grid Modernization
2.4 Summarize in the table, and describe below the INDIRECT offsets5 (Capital and O&M)
that result by undertaking this investment.
The capital offsets below represent the deferred amount of work that the Grid Modernization completed
that satisfies Wood Pole Management program scope. The values are based on the average cost ($47,900)
to complete one mile of work under WPM scope. This value was calculated using YE 2022 data by our
WPM Program Manager.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital Wood Pole Management Deferral $244,815 $192,594 $204,571 $124,563 $0
O&M None identified $0 $0 $0 $0 $0
A second indirect capital offset attributable to Grid Modernization is the replacement of equipment such as
old conductor and transformers that have high energy losses with new equipment that is more energy
efficient and improve the overall feeder energy performance. This creates the need for less power
generation or acquisition and equates to lower rates for customers.
The table below shows the estimated kWh energy savings6,7,8 expected after completion of each project.
These calculations are conservative in that not every energy efficiency improvement made during design
and construction can be anticipated in the initial assessment. These estimates are derived from the initial
assessments noted in the feeder baseline reports found in PC-DR-110 Attachment A-O. The primary
reconductor savings are for trunk reconductor work only.
Estimated Avoided
Estimated Total
Annual Annual Estimated %of Feeder cost(per Annual
Pri. MWh)for Capital
Feeder State Transformer Annual to be
Reconduct energy Offset
Loss MWh MWh Constructed
or MWh conservation Estimate
Savings Savings Savings investments
OR01282 Grid Mod ID 0.0 103.0 103.0 100% $105 $10,815
ROS12F4 Grid Mod WA 2.6 64.1 66.7 100% $105 $7,004
SIP12F4 Grid Mod PH2 WA 10.5 272.8 283.3 34% $105 $5,652
5 Indirect offsets are those items that do not directly reduce the current costs of the Company, but may serve to
reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows current employees to focus on
higher priority work.
6 Additional MWh savings estimated through Distribution Automation enabled improvements are not included in these figures.
Additional MWh savings estimated through the removal of Open Wire Secondary districts are not included in these figures
s Additional MWh savings estimated through power factor correction initiatives with capacitors,IVVC,or CVR are not included
in these figures.
Grid Modernization Business Case Justification Narrative Template Version:February2023 Page 9 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J.DiLuciano,Avista
Schedule 3,Page 11 of 535

DocuSign Envelope ID: CEF1520C-4F79-4BlA-A653-5lD5D4E2CEFO
Distribution Grid Modernization
2.5 Describe in detail the alternatives, including proposed cost for each alternative, that
were considered, and why those alternatives did not provide the same benefit as the
chosen solution. Include those additional risks to Avista that may occur if an
alternative is selected.
[Recommended Solution]
Follow feeder modernization scope and timeline as stated in this Business Case Justification Narrative
(BCJN)which is constrained by Capital Planning Group (CPG)annual budget allocation. Priority and
resources have been re-allocated to mitigate wildfire risk which includes approval and execution of
Grid Hardening projects under the Wildfire Resiliency Program.
Revise funding request down to $5M over 5 years to reflect change in capital prioritization.
Feeder Miles to
Modernize
OR01282 Grid Mod 7.3
ROS12F4 Grid Mod 6.1
SIP12F4 Grid ModPH2 1.5
Total 14.9
Alternative 1:
Follow scope as stated in the Business case and follow the budget and timeline request stated in the
2020 BON as the recommended solution. The 2020 BON recommended solution was based on an
average cost per mile requiring a$28.88M annual investment to achieve a 60-year cycle.
Alternative 2:
Address issues through the different specific company initiatives, such as WPM, TCOP, URD,
Segment Reconductor, etc.
This means that a crew would potentially go out to the same area multiple times. This costs more for
set up, travel time, flagging, etc. which means higher rates for customers. It also means the customer
could have multiple planned outages and be impacted by multiple street closures for crews to address
needed work at separate times. The risk reduction is also cut in half compared to the comprehensive
work completed by GMP.
2.6 Identify any metrics that can be used to monitor or demonstrate how the investment
delivered on remedying the identified problem (i.e., how will success be measured).
Measuring these goals is defined through the following key attributes organized into three categories.
■ Performance: Thermal utilization, efficiency, voltage regulation, reliability performance (CAIDI,
power factor, FDR imbalance.
■ Health: Age, OH/1JG ratio,pole rejection rate, reliability health(CEMI3, SAIFI).
Grid Modernization Business Case Justification Narrative Template Version:February2023 Pa ye 10 of 12
Exhibit No. 0
Case Nos.AVU-E-25-01/AVU-G-25-01
J.DiLuciano,Avista
Schedule 3,Page 12 of 535

DocuSign Envelope ID: CEF1520C-4F79-4BlA-A653-5lD5D4E2CEFO
Distribution Grid Modernization
It should be noted that reliability indices are a lagging indicator against established baselines to measure
performance and should be considered a barometer due to the complexity and variability of the metrics
that make up these indexes such as seasonal conditions affecting average and peak loadings and extreme
weather events.
2.7 Please provide the timeline of when this work is schedule to commence and complete,
if known.
The 2025 through 2029 plan addresses —14.9 circuit miles on the following feeders that have been
designed. Transfer to Plant will occur on a monthly basis as each feeder initiates the construction phase
of the project. At this time, there are no projects scheduled for 2029.
Apr'25 lul'25 Od'25 I Jan'26 JAPr'26 11.1'26 Od'26 Jan'27 Apr'27 lul'27 Od'27 lan'28 Apr'2a Jul'28
Start Finish
1/125 10/128
Grid Modemization Summary Timeline
2.8 Please identify and describe the Steering Committee/governance team that are
responsible for the initial and ongoing approval and oversight of the business case, and
how such oversight will occur.
The steering committee is comprised of the Asset Maintenance Manager, Director of Operations,
Operations Engineering, and the Program Manager. This group meets as needed,usually quarterly, for an
update on the program or when key program decisions or changes in scope need to be discussed. The
members of this group are called out in the Grid Modernization Communication Management Plan. The
annual spend is also reviewed every three weeks by the Operation Round Table (ORT) that is comprised
of the Director of Operations, various operations managers, and business case owners.
Grid Modernization Business Case Justification Narrative Template Version:February2023 Pa ye 11 of 12
Exhibit No. 0
Case Nos.AVu-E-25-01/AW-G-25-01
J.DiLuciano,Avista
Schedule 3,Page 13 of 535

DocuSign Envelope ID: CEF1520C-4F79-4131A-A653-51D5D4E2CEF0
Distribution Grid Modernization
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the <Project Name> and agree with the approach it presents.
Significant changes to this will be coordinated with and approved by the undersigned or their designated
representatives.
DocuSigned by:
Signature: P` `� Date: May-15-2024 1:25 PM PDT
Print Name: Heat er we sfer
Title: Manager, Asset Maintenance
Role: Business Case Owner
DocuSigned by:
Signature: �°Q wtbVJ Date: May-15-2024 11:26 AM PDT
Print Name: Ro bt F Raymon
Title: Program Manager
Role: Business Case Owner
gnetl by: Date:
DocuSi
Signature: C� Gaol May-15-2024 4:12 PM PDT
Print Name: Pau°�Z"c�ooc?g
Title: Director of Electric operations
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
'Refer to page 64 of Avista Utilities Electric Distribution Infrastructure Plan
Grid Modernization Business Case Justification Narrative Template Version:February 2023 Pagge 12 of 12
Exhibit No. i0
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 14 of 535

Distribution Minor Rebuild
EXECUTIVE SUMMARY
Distribution Minor Rebuild is an ongoing program that focuses on keeping the distribution system in a
reliable and safe condition for customers and employees. It ensures responsiveness to unplanned damages
on distribution assets not related to weather events, as well as small customer driven rebuilds. Throughout
the entire distribution system minor rebuilds or replacements of asset units are needed to maintain system
reliability and safety. This work impacts customers in both Washington and Idaho. If not funded, the it will
impact various types of work that will need to be absorbed into other funding due to the necessity of the
work (i.e., the replacement of a car-hit pole in the alley, a broken cross-arm, a burned-up transformer, and
a myriad of other safety related projects.)Also, if not funded, the business will affect the ability to respond
to customers' needs for modifications to their electrical service.
The historical 3-year average spend for minor rebuild work is $14M per year. Based on recent analysis we
anticipate the work demand to continue for the next 5 years. Minor Rebuild spends approximately $1.1M
per month; as of March 2024 the spend on Minor Rebuild related work is $3M and we project the spend for
this year to exceed $14M.
Minor Rebuild 3-Year Spend
2021-2023
$18,000,000
$16,069,678
$16,000,000
$14,092,710 $13,328,749
$14,000,000
$12,000,000
$12,879,702
$10,000,000 A
$8,000,000
$6,000,000
$4,000,000
$2,000,000
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2021 2022 2023 Average
We have one upcoming change to this business case starting 2025. Beginning next year we will also be
completing the LED Change outs under the Minor Rebuild business case. Currently, LED is it's own
program, but since the program has primariliy ended and we are only changing the lights on a burnout
basis, we will be absorbing that work under the minor rebuild business case. We have added what was
approved for the LED Change Out program, which was $200,000, to our requested budget through 2029.
VERSION HISTORY
Version Author Description Date
1.0 Katie Snyder Annual Business Case Narrative Update 411612024
Business Case Justification Narrative Template Version: February 2023 Page 1 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 15 of 535

Distribution Minor Rebuild
BCRT Team
BCRT Member—Steve Has been reviewed by BCRT and meets necessary requirements 411812024
Corrozzo
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2024 $14,000,000 $14,000,000
2025 $14,620,000 $14,620,000
2026 $15,050,000 $15,050,000
2027 $15,500,000 $15,500,000
2028 $16,000,000 $16,000,000
2029 $16,474,000 $16,474,000
Project Life Span Ongoing
Requesting Organization/Department Electric Operations
Business Case Owner I Sponsor Katie Snyder I Paul Good
Sponsor Organization/Department Operations
Phase Execution
Category Program
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
Distribution Minor Rebuild is an ongoing program that focuses on keeping the distribution system in
a safe and reliable condition for customers, ensuring responsiveness to unplanned damages on
distribution assets such as car hit pole, broken crossarm, burned up transformer, etc. that are not
related to weather events, as well as small customer driven rebuilds. Throughout the entire
distribution system, minor rebuilds or replacement of asset units are required to be completed to
maintain system reliability and safety.
The work includes failed asset replacements, small mandatory or compliance driven work, smaller
performance and capacity improvements, or unplanned customer requests. Occasionally, larger
projects with an identified need and short timeframe for implementation are constructed under the
Distribution Minor Rebuild business case. Even though the work is unplanned, Minor Rebuild work
occurs regularly due to the nature of the utility business and numerous assets in the field spread
Business Case Justification Narrative Template Version: February 2023 Page 2 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 16 of 535

Distribution Minor Rebuild
over a wide geographical area. An adverse accumulation of unrepaired assets would greatly put line
workers and the public at risk as minor asset failures begin to deteriorate pockets of the distribution
system as well as decreasing the reliability of the distribution system
1.2 Discuss the major drivers of the business case.
The primary drivers for the work are Asset Condition, safety, and reliability. This work focuses
on keeping the distribution system in a safe and reliable condition for customers, ensures
responsiveness to unplanned damages on distribution assets not related to weather events, as
well as small customer driven rebuilds.Throughout the entire distribution system, minor rebuilds
or replacements of asset units need to be completed to maintain system reliability and safety,
which are a benefit to customers.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
Distribution Minor Rebuild is an ongoing program that focuses on keeping the distribution system
in a safe and reliable condition for customers, ensuring responsiveness to unplanned damages
on distribution assets not related to weather events, as well as small customer driven rebuilds.
Throughout the entire distribution system, minor rebuilds or replacement of asset units need to
be completed real time to maintain system reliability and safety.
If it does not continue to be funded so we can do the work as it comes it could impact the overall
reliability of the distribution system as well as responsiveness to customer requested service
demands and system safety. The minor rebuild business case provides the funding for work
such as replacement of a car-hit pole in the alley, a broken cross-arm, a burned-up transformer,
and a myriad of other safety related projects. If unfunded, this will impact our ability to respond
to customers' needs for modifications to their electrical service.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
Our oganization's main focus areas are our customers, our people, performance, and invention.
Distribution Minor Rebuild aligns with the strategic vision, goals, objectives, and mission
statement of the organization because it's focus is to maintain and improve the safety and
reliability of our distribution system for our customers and to improve performance by expanding
our distribution system through small customer requests to meet more customer's needs. We
are putting the customer at the center of all the work we complete.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 17 of 535

Distribution Minor Rebuild
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
Distribution Minor Rebuild is an ongoing program that focuses on maintaining safety and
reliability for our customers and workers. When unplanned repairs, customer requests, or
compliance related modifications present themselves they must be addressed in order to
preserve the safety and reliability of our distribution system. Funding this business case allows
us to make repairs or upgrades that allow us to maintain a safe and reliable distribution system.
In order to identify the problem(s) this business case will solve we look at historical data that
shows the instances where minor rebuild repairs needed to be made and use it to establish a
minimum funding level baseline, identify trends, forecast if the problem will continue and what
resources we will need to remedy those situations as they come.
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Distribution Minor Rebuild is an ongoing program that focuses on keeping the distribution system
in a safe and reliable condition for customers ensuring responsiveness to unplanned damages
on distribution assets not related to weather events, as well as small customer driven rebuilds.
It also enables Avista to better be able to respond to unanticipated weather events. Throughout
the entire distribution system, minor rebuilds or replacement of asset units need to be completed
to maintain system reliability and safety. Our proposed solution is to continue funding this
business case at the level which provides us with the resources needed to make repairs and
maintain our standard for safe and reliable service.
' Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 18 of 535

Distribution Minor Rebuild
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
Historical spend was used to determine the requested amount. A steady increase in costs for
unplanned minor rebuild work has occurred for several reasons. Many assets on the distribution
system are past their end-of-life cycle and contributing to this increase. The 3-year average
actual spend for minor rebuild work is $14M. This level of work demand is expected to continue
for the next 5 years due to age of plant and anticipated inflation.
In 2023, 2,300 work orders were created with the average cost equaling $4,035, which
demonstrates the work is made up of thousands of small dollar critical non-discretionary jobs.
Occasionally larger rebuild projects, such as a small reconductor project, are undertaken as
Distribution Minor Blanket projects if prioritized by the Area Ops Engineers. Only 61 (3%)of the
2,300 work orders created in 2023 were over$25,000.Those 61 work orders averaged$56,291.
This analysis shows that under this business case we are effectively addressing a large number
of minor rebuild situations that occur each year. Without it, all these little occurrences would
compound into a less safe and less reliable distribution system to deliver service to our customer
with.
Figure 3 displays a breakdown of the different types of charges that occur in the Minor Rebuild.
The majority of charges are from specific work orders created to design the minor rebuild work
needed on our distribution system. Distribution Minor Rebuild work also consists of isolated
replacement of failed asset(s) that do not lend themselves to a specific project (i.e. trouble
related work), which are charges falling under craft and non-craft expenditures.
Electric Distribution Minor Rebuild
Spend 2023
$9,281,081.48
$3,740,233.11
$305,966.72
0
Craft Related Expenditures Non-Craft Realted Expenditures Specific Work Order Charges
Figure 3: Types of Charges to Minor Rebuild
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 19 of 535

Distribution Minor Rebuild
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
There are no direct offsets related to this business case.
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
00 $ $ $ $ $
The Distribution Minor Rebuild Business Case is for unplanned repairs, replacement of failing
equipment and/or small required upgrades on our system. These are jobs that are required to
occur for safety, reliability, and compliance. One indirect offset for this business case would be
avoidance of outages. By replacing failing equipment, we could potentially be avoiding an
outage. As calculated by the ICE (Interruption Cost Estimate), our current outage cost per
customer per hour is $116.15.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 20 of 535

Distribution Minor Rebuild
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternative 1: The work could be rolled up into another business case such as Storm or New
Revenue/Growth. However, if we were to do that the expected spend for the work included in
Minor Rebuild would be the same and would exceed the current budgets for those programs by
almost double, requiring budget increases for those programs.
MINOR REBUILD 5-YEAR HISTORICAL
SPEND
$18,000,000
$16,000,000
$14,000,000
$12,000,000
$10,000,000
$8,000,000
$6,000,000
$4,000,000
$2,000,000
2019 2020 2021 2022 2023
Spend $13,411,478 513,080,967 512,879,702 $16,069,678 13,328,749
Alternative 2: Another alternative would be to not fund the program. If the program was not
funded the ability to focus on keeping the distribution system in reliable condition for customers,
maintain safe conditions for the workers, provide responsiveness to unplanned damages to
distribution assets not related to weather events,as well as small customer driven rebuilds would
be severally diminished. This would add unnecessary risk to our customers, employees, and
the general public.
Alternative 3: There are no other known alternatives.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 21 of 535

Distribution Minor Rebuild
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
In 2023 the Minor Rebuild spend was $13.3M. This spend allowed us to deliver/maintain a more
reliable, compliant, and safe distribution system.We were able to focus on main categories below.
• Customer Requested Rebuilds—Work is initiated by an existing customer or property
owner. The costs associated with the work are typically reimbursed by the requesting
party. Examples include, but are not limited to: Customer requested reroute, overhead
to underground line conversion, or customer load increase.
• Trouble Related Rebuilds — Emergency work required to repair damaged facilities
caused by non-storm and non-fire related outages. Activities include a car hit pole, car-
hit Padmount enclosure, copper theft, or unforeseen failed equipment that needs
immediate response.
• NESC / Operating Standard Violations — Activities include, but are not limited to,
NESC violations (not related to Joint Use clearances), secondary/service-related
voltage mitigation, fusing protection mitigation, aerial trespass, and undersized
equipment(transformers, regulators, etc.).
• Asset Condition— Activities include, but are not limited to, deteriorated wood poles,
leaking transformers, condition related replacement(not outage related) of line devices
and equipment.
• Facility Upgrades/Efficiency Improvements — Activities include, but are not limited
to, small scale reconductors, small scale feeder ties, installation of new switches or
sectionalizing devices, feeder balancing, installation of new regulators, reclosers, or
capacitor banks, and removal of open wire secondary.
• Facility Route / Location Modifications — Activities include, but are not limited to,
overhead to underground conversions, facility re-route, or relocation of midline devices
to facilitate future maintenance and optimize section aIization.
2023 Distribution Minor Rebuild Activity
Split by Category
Trouble Related
28%
Asset Condition
31%
Facility Upgrades&Efficiency
Improvements
6%
Customer Requested/Caused
8%
Facility Route and Location
Modifications DX Facility Route&Location
22% Modifications
5%
Business Case Justification Narrative Template Version: February 2023 Page 8 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 22 of 535

Distribution Minor Rebuild
Figure 1 shows the allocation of the spend from 2023 for the six general categories above.
We continue to monitor the spend and allocation of the funds for Distribution Minor Rebuild to
track our progress and ensure our customers are benefitting from this business case.
We use these metrics to understand the drivers of the business case and ensure we request
sufficient resources to continue maintaining and improving our distribution system to provide safe
and reliable service to our customers.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Distribution Minor Rebuild is an ongoing program and has no anticipated end date. Any upgrades
or repairs made under this program are used and useful right away and transfers to plant on a
monthly basis.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
This business case is written by the business case owner, reviewed by the business case sponsor,
and then reviewed by the business case review team. It's then submitted to the Financial Planning
and Analysis (FP&A)team for final approvals. This business case and it's spend are continuously
monitored by the Operations Round Table which is comprised of Business Case owners,
department managers and the department Sponsor, who meet once a month, and then finally the
FP&A who also meet monthly.
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Electric Distribution Minor Rebuild and agree
with the approach it presents. Significant changes to this will be coordinated with and approved by
the undersigned or their designated representatives.
Signature: xa�&� �'� Date: 5/10/2024
Print Name: Katie Snyde
Title: Business Analyst III
Role: Business Case Owner
Signature: TA(d 60d Date:
5/15/2024
Print Name: Paul Good
Title: Director Electric Operations
Business Case Justification Narrative Template Version: February 2023 Page 9 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
i ype text nere J. DiLuciano,Avista
Schedule 3, Page 23 of 535

Distribution Minor Rebuild
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 10 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 24 of 535

DocuSign Envelope ID:94B3E083-EF10-4288-8074-73EEF96FAEC8
Distribution System Reinforcements
EXECUTIVE SUMMARY
Avista's electric distribution system is the largest part of the company's infrastructure. It consists of poles,
wires, underground cable, transformers, and a variety of other equipment. In addition, Avista's electric
distribution system has the largest footprint of any other infrastructure within the company's service territory.
This creates a unique challenge for the company. The distribution system is the largest contributor to a
customer's reliability and the overall safety of the public, mostly from the sheer volume of exposure it
establishes. Most of our customer outages result from incidents that occur on our electric distribution system
and this business case is one of several such as, Minor Rebuilds, Wood Pole Management, Grid Hardening,
etc., that creates a direct customer benefit by completing projects that improve the electric distribution
system's safety, performance, and reliability.Avista is required by the Washington Utilities and Transportation
Commission (WUTC) to provide an annual reliability report that includes several industry standard reliability
metrics. This business case along with others mentioned above are needed to keep our electric system's
reliability and subsequent metrics within acceptable parameters. Not funding this business case or failing to
fund it at an adequate level will limit our ability to proactively work on system issues resulting in a decline in
our electric system's reliability. Such a decline in our electric system's reliability would undoubtably trigger
substantial questioning from the WUTC. The current funds request for this business case is for$14 million
on an ongoing basis. The projects for this business case are identified by Avista's Operations Engineers for
their regional areas within Washington, Idaho, and Montana and they are prioritized against other regional
projects with input from the Distribution Planning Engineers.
Most of the funds provided by this business case are used to complete projects that solve performance and
capacity issues driven by system wide electric load growth. Other projects address power quality mitigation,
reliability improvements, operational flexibility, system protection improvements, and safety reinforcements.
As mentioned above, the risk in not funding this business case is the inevitable decline in the overall health
and operation of Avista's electric distribution system, e.g., overloading conductor to the point of failure. This
business case was used to address many electric distribution capacity constraints experienced during the
heat event of June 2021. Additionally, we have completed projects and continue to complete work with this
business case that mitigates system issues that are tied to Commission complaints from customers. The
most recent have been voltage issues (service voltage below the 114-volt threshold) experienced by our
customers after the cold snap in December 2022. The ongoing nature of issues that arise within the electric
distribution system coupled with the large amount of work drives the need for this business case to be funded
on a yearly basis.
Business Case Justification Narrative Template Version: February 2023 Page 1 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 25 of 535

DocuSign Envelope ID:94B3E083-EF10-4288-8074-73EEF96FAEC8
Distribution System Reinforcements
VERSION HISTORY
Version Author Description Date
1.0 David James Initial draft of original business case 04/07/2017
1.1 Cesar Godinez Updated to include voltage/transformer mitigation work. 07/03/2019
2.0 Cesar Godinez Updated narrative and business case template. 0710112020
2.1 Cesar Godinez Minor updates. 01/04/2022
3.0 Cesar Godinez Updated narrative. 08/31/2022
4.0 Cesar Godinez Updated narrative and changed business case name. 03/01/2023
5.0 Cesar Godinez Updated 5-Year Budget Request 0411112024
BCRT Team 412612024
BCRT Member Has been reviewed by BCRT and meets necessary requirements Steve
Carrozzo
Business Case Justification Narrative Template Version: February 2023 Page 2 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 26 of 535

DocuSign Envelope ID:94B3E083-EF10-4288-8074-73EEF96FAEC8
Distribution System Reinforcements
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2024 9,946,000 9,946,000
2025 14,000,000 14,000,000
2026 14,000,000 14,000,000
2027 14,000,000 14,000,000
2028 14,000,000 14,000,000
2029 14,000,000 14,000,000
Project Life Span Continuous Program
Requesting Organization/Department C51/Electric Distribution Design
Business Case Owner I Sponsor Cesar Godinez I Vern Malensky
Sponsor Organization/Department T08/Electrical Engineering
Phase Monitor/Control
Category Program
Driver Performance& Capacity
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
Avista's electric distribution system consists of three hundred and seventy (370) discrete primary
electric circuits (feeders) encompassing over 19,300 circuit miles of overhead conductors and
underground cables, along with all the other equipment needed to operate an electric distribution
system. Our electric distribution system is the largest asset the company owns, and it has a book cost
of about$2.1 billion. It represents the largest dollar value of any aggregated company owned system,
including the sum of all our generation facilities. Load Demands on the grid are dynamic with load
patterns changing because of many factors including weather, temperature, economic conditions,
conservation efforts, and seasonal variations. The distribution grid is managed by division or
`Operations Engineers' and centralized Distribution Planning.The performance and capacity needs of
this system are constantly changing, and this business case is the main tool available to our
Operations Engineers so that they can keep up with these system demands. Most of the work
completed with this business case addresses capacity constraints driven by load growth throughout
the system. In addition to capacity constraint work this business case also addresses other electric
distribution system performance work that is identified by engineering analysis and observed system
performance issues. In 2021, 2022, and 2023 we experienced major weather events that exposed
some system performance issues, some of these system performance issues resulted in Commission
Business Case Justification Narrative Template Version: February 2023 Page 3 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 27 of 535

DocuSign Envelope ID:94B3E083-EF10-4288-8074-73EEF96FAEC8
Distribution System Reinforcements
complaints from customers who experienced low service voltage, below 114 volts.This business case
was used in both cases of Commission complaints to fund mitigation work to fix the low voltage issues
our customers were experiencing. In addition, our load growth has also been increasing when
compared to historical growth rates. In our 2020 IRP we forecasted our system wide load growth as
0.3%with a peak load forecast of 0.3%in winter and 0.4%in summer.The current load growth forecast
is projecting system wide load growth of 0.9% with peak load forecast of 1.2%. Additionally, the load
forecast scenarios that consider electrification are showing system wide load growth of 1.9%with peak
load growth of 3.2% in winter and 1.9% in summer. Figures 1 & 2 below help illustrate this trend,
graphs provided by System Planning. Our Planning department has also completed some forecasting
work that is showing pockets of growth in excess of 5%.
Summer Balancing Area Forecast
3600
Actual Summer
3400 2021 Forecast -
2022 Forecast
3200
.�2023(precast
30M
3 2800
2600
24M — - -
2000
1800
2008 2013 2018 2023 2028 2033 2038
Figure 1:Summer Load Growth Forecast
Winter Balancing Area Forecast
3600
Actual Winter 11-10
'�� ...•2021 Foremost
——2022 Foremost
3200 —2023 Foremost
3000
2800
2400 ...• ...•.....•...... .......•.....
2200
2000
1800
20M 2013 2018 2023 2028 20M 2038
Figure 2: Winter Load Growth Forecast
Avista operates a radial distribution system using a trunk and lateral configuration (industry standard).
Though many circuits are monitored at the source substation (SCADA), downstream trunk and lateral
Business Case Justification Narrative Template Version: February 2023 Page 4 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 28 of 535

DocuSign Envelope ID:94B3E083-EF10-4288-8074-73EEF96FAEC8
Distribution System Reinforcements
branch circuits loading are analyzed via computer simulation. At Avista, distribution analysis is
performed with the Synergi load flow program. AMI data is also used to analyze service voltages and
transformer loading. AMI data has shown system issues in the form of service voltage problems and
transformer overloading. Our System Planning group is also starting to export AMI load data into
Synergi to use it in the computer simulation.
1.2 Discuss the major drivers of the business case.
The main driver for this business case is load growth on our electric distribution system. Outside of
our New Revenue business case, this is the only other business case that is primarily focused on
ensuring that our electric distribution system is adequate to accommodate our load growth. One big
difference between this business case and the New Revenue business case is that in this business
case our engineers are looking at the system as a whole within their areas and identifying needed
projects that will keep the system operating within acceptable parameters.The New Revenue business
case primarily deals with new line extension and rarely focuses on the existing system that often gets
loaded to capacity because of these new line extensions. Other drivers of this business case include
power quality investigations and subsequent mitigation projects which are initiated by customer
inquiries or engineering analysis work. Work is also driven by reliability and safety concerns that are
identified by our engineers and/or operation personnel. Power quality, reliability and safety driven
projects completed through this business case are meant to mitigate code violations and observed
system issues that will help maintain adequate levels of service in these areas for our customers.
Operational flexibility can also drive the need to upgrade electric circuits, install switching equipment,
and other infrastructure as needed.
In a manner like substation rebuilds, expansions, and additions that are planned for and scheduled
years in advance, the distribution system also requires rebuilds, expansions, and additions. The
Distribution System Reinforcements business case allows for a methodical and planned out approach
to needed feeder reinforcements. Secured funding for future years allows for planning large projects
in a multi-year approach,with completion of a portion of the overall project happening over a series of
years.
Avista's electric distribution system analysis and mitigation strategies are informed by several internal
documents and data repositories. These are listed below for reference:
1. Distribution Planning Standard "DP-SPP-02 Distribution System Performance"— internal
document that defines the performance criteria and limits for our distribution system. This
document is maintained by System Planning (John Gross).
2. FDR Status Report—Distribution Engineering publishes an annual report indicating peak
circuit demand by season, reliability outage statistics, circuit health check, and other
logistic information.
3. Distribution Standards — Distribution Engineering maintains construction standards for
both overhead and underground primary circuits. It also maintains standards for all
electrical material and apparatus.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 29 of 535

DocuSign Envelope ID:94B3E083-EF10-4288-8074-73EEF96FAEC8
Distribution System Reinforcements
4. PI Database—operating data retrieved by either the SCADA or DMS system is stored in
the PI historian. This allows direct access by engineers and planners to help inform both
operating and design strategies. (Distribution Operations)
5. Feeder Automation Strategy— a design guide to assist the CPC/Engineer when making
decisions involving automated devices (Distribution Engineering).
6. Synergi Computer Program — the load flow program derives topology information from
Avista's GIS system. Updates to the Synergi database are performed by Distribution
Planning.
7. SCADA Variable Limit(SVL)—Avista uses temperature compensated program to monitor
conductors, cables, and series connected major equipment (e.g. transformers, breakers,
switches, regulators, and etc.). This system is deployed on Avista's EMS/SCADA system.
The program is SME supported by Substation Engineering and Distribution Engineering.
8. AMI Data—AMI service voltage data is used to identify services that are out of compliance
with the ANSI C84.1 standard of +/- 5% of 120 volts. AMI service load data is used to
identify transformers that are overloaded according to the standards set by Distribution
Engineering.
A typical distribution circuit is illustrated on the next page. Like municipal water systems, grid capacity
decreases with distance away from the source substation. This leads to system `constraints' as loads
are added to the system through direct customer action or load shifting between circuits (Avista).
�.d Dmand
,►
SOOA 200 A 100 A
Sub r
Illustration of Distribution Grid Capacity Constraint
Avista's Distribution System contains over 75 different wires and cables
Business Case Justification Narrative Template Version: February 2023 Page 6 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 30 of 535

DocuSign Envelope ID:94B3E083-EF10-4288-8074-73EEF96FAEC8
Distribution System Reinforcements
2020 Avista Standard OH Primary Conductors
556 All-Aluminum (AAC)—601 Amps (main trunk, urban)
336 All-Aluminum (AAC)—442 Amps (main trunk, rural)
2/0 Aluminum Conductor, Steel Reinforced(ACSR) —238 Amps (gen purposes, rural)
#4 Aluminum Conductor, Steel Reinforced(ACSR)— 119 Amps (lateral circuit)
Legacy Conductors
2/0-3/0 Copper—319-369 Amps (main trunk)
#2 Copper— 197 Amps (main trunk)
#6 Copper - 110 Amps (lateral circuit)
Avista's distribution grid contains over 1,000 miles of conductor equivalent or smaller than
#6 Copper.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The main benefit to our customers in continuing with this business case, as stated in the Executive
Summary, comes from this business case's overall contribution to maintaining a healthy and
operational electric distribution system. In absence of this business case, critical issues would be
resolved in a reactionary and haphazard fashion, funded through the Minor Blanket, and completed
outside the confines of a"big picture" plan and approach to feeder management. This reactionary and
haphazard approach would increase the public's and the company's overall risk significantly. Without
this business case our Operations Engineers would not have a funding mechanism to complete
projects they have on their five-year plan. These projects target both current system issues and
forecasted system constraints and they help ensure that our equipment does not fail under the ever-
changing service load demands. Completing this work in a reactionary manner would mean that most
of the time our efforts to correct a system issue will be after the fact once something has failed. The
risk of allowing our equipment to fail can be immensely impactful to our customers and communities.
In addition, overloading our equipment has the potential of creating several code violations as
conductor starts to sag below allowable clearance parameters.
Another risk that this business case helps mitigate are the unforeseen weather events that have been
occurring more regularly. As mentioned previously, in 2021, 2022, and 2023 our electric distribution
system experienced extreme weather events that stressed the system so much so that we struggled
to keep the power on for some of our customers. Not funding this business case now will perpetuate
our system's inability to withstand these unforeseen weather events. The best way to ensure that our
electric distribution system can withstand unforeseen weather events is take a big picture planned
approach to system reinforcements, completing projects that help keep everything running within our
system performance criteria. As previously stated, without this business case we're left completing
Business Case Justification Narrative Template Version: February 2023 Page 7 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 31 of 535

DocuSign Envelope ID:94B3E083-EF10-4288-8074-73EEF96FAEC8
Distribution System Reinforcements
work in a reactive manner never really getting in front of system issues and always fixing problems
after the fact.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
This business case and the proposed investment lies at the heart of way we're a company and it is in
full alignment with our vision, goals, objectives, and mission. Our electric distribution system is the
threshold between Avista and most of our customers and to accomplish all the items listed above we
must be able to maintain a healthy and operational system. There is no other business case that gives
Avista such a proactive approach in creating and maintaining a healthy and operational electric
distribution system.
In June of 2021 we experienced a heat event that stressed our system so much that we had to
proactively shut power off to some customers to avoid larger more catastrophic failures. In December
of 2022 and in the Winter of 2023, we experienced cold snap events that stressed our system such
that we struggled to keep the lights on for some customers and others experienced service voltages
below acceptable limits. Our vision as a company is"better energy for life"but it's impossible to deliver
better energy for life when you can't keep the lights on.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
The projects completed via this business case are typically first proposed with a Project Requirements
Diagram (PRD). These PRDs outline the high-level scope of a project, and they are complimented by
documented analyses that shows why the need for the project exists. The Distribution Planning group
also develops distribution system assessments that provide additional documented analyses in
support of projects completed through this business case.
Section 1.2 lists eight internal documents and data repositories that are used in the evaluation and
analysis of our electric distribution system to develop our planned projects. These documents and
sources of data are the main tools available to our engineers and they're used on a yearly basis to
keep ahead of potential system issues.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 8 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 32 of 535

DocuSign Envelope ID:94B3E083-EF10-4288-8074-73EEF96FAEC8
Distribution System Reinforcements
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
There are three main elements to the proposed solution: Load Shifting, Capacity Increases, and
System Reinforcements. Load Shifting requires that new feeder ties be created. This action is
represented in the Distribution System Reinforcements program. By extending lines to adjacent
circuits, load can be shifted to underutilized circuits and mitigate overloads.This action requires capital
investment. Capacity Increases require power line reconductoring. Reconductor overloaded
`segments' to increase line capacity, mitigate identified low voltage issues, and correct system
protection issues. Install voltage regulators to mitigate feeder level low voltage issues. Replace
Transformers (or install additional transformers) to mitigate overloaded transformers and service
voltage issues. All electric components are thermally limited. Reconductoring is the most direct
approach to mitigating overloaded circuits and low voltage issues. Lastly, System Reinforcements help
solve all the other problems identified. It's used to mitigate power quality issues, as well as reliability
and safety issues. It helps us add operational flexibility to the electric distribution system and expand
distribution automation by adding targeted "smart" devices. Accomplishing this type of work ensures
that our electric distribution system is operated efficiently, reliably, and safe.
This proposed solution helps solve the business problem identified above by giving our Operations
Engineers a funding mechanism to complete the work they've identified as needed. It also allows them
to address system performance issues that come up unexpectedly.
2.2 Describe and provide reference to CIRRARR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
One of the planning objectives is to levelize the resource demands and avoid significant upswings or
downturns in crew resource forecasting. Distribution Engineering works closely with the Operating
Divisions and Asset Maintenance to develop a resource balanced work plan and maximize the
effectiveness of Avista craft resources. In addition, reductions in funding of this business case typically
result in increase spend in our Minor Blanket business case. There are also significant capital
investment offsets created by the work this business case accomplishes.
Distribution assets are fixed resources and therefore, project alternatives are generally dominated by
supply side solutions. Operating limitations are codified in Avista internal standards (as listed) but
derived through industry and regulatory policies including: Washington Administrative Code (WAC),
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 9 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 33 of 535

DocuSign Envelope ID:94B3E083-EF10-4288-8074-73EEF96FAEC8
Distribution System Reinforcements
National Electric Safety Code (NESC), National Electric Code (NEC), and IEEE/ANSI standards &
manufacturer recommendations specific to equipment ratings and operating limits. This creates a
challenge to provide a typical cost to benefit analysis. When a piece of equipment has reached its
capacity threshold and is at risk of overloading there are few options available to address this risk. We
are starting to look into non-wired alternatives but so far, the preliminary evidence is showing that
these options are not cost effective or timely when compared to our traditional solutions (replacing
wire/equipment). The best evidence of the benefit these projects create for customers is when nothing
happens on the electric distribution system. Unfortunately, this can be difficult for others to accept as
its abstract and not as tangible as IRR analyses. However, it's worth pointing out that during the 2021
heat event we proactively shut the power off to some customers to avoid catastrophic overloads of our
equipment. This is exactly the type of risk we are mitigating with this business case and the benefit
this business case provides our customers comes from giving us a tool to avoid these situations in the
future.
2.3 Summarize in the table and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
The direct capital offset shown in the table below was calculated using the 2020 cost value for our
Wood Pole Management (WPM) program to complete 1 mile worth of work ($39,570/mile). This cost
value was calculated in 2021 by our WPM program manager. Next, our average miles of reconductor
performed through this business case (12.76 miles)were calculated. This value was calculated using
actual miles of reconductor completed through this business case every year from 2018 to 2022.These
two values multiplied together produced an average WPM offset value, $504,913. The other direct
saving comes from our avoided cost in outage labor/work. The calculated number for avoided cost for
outage work ($1,108/mile) comes from our Asset Management Business Analyst and was calculated
in 2021. Using this avoided cost number produces an average outage cost offset value of$14,143. To
produce the new offset values for future years the average yearly actual spend ($5,957,897) was
calculated for the same timeframe (2018 to 2022). This allowed us to calculate a percent
increase/decrease from the average spend and apply that percentage to the average offset values for
future expected spends. The details of how the offset values were originally calculated can be found
in our 2021 document "Capital Investment Offsets Form — Distribution System Enhancements" and
the calculation for future years being used here can be found in our excel spreadsheet"Average Offset
Calculation."A $14,000,000 budget represents a 135% increase from the average yearly spend. This
percent increase applied to the average offset values resulted in a WPM direct offset of$1,186,456
and an outage cost direct offset of$33,233.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital WPM & outage cost $1,219,689 $1,219,689 $1,219,689 $1,219,689 $1,219,689
Offset
0&M $ $ $ $ $
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2023 Page 10 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 34 of 535

DocuSign Envelope ID:94B3E083-EF10-4288-8074-73EEF96FAEC8
Distribution System Reinforcements
2.4 Summarize in the table and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
The indirect offset shown in the table below was calculated by our Asset Management group in
2021. This calculated value assumes that every year we have at least one reconductor/feeder tie job
that differs the need for substation capacity.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital Substation Deferment $28,683 $28,683 $28,683 $28,683 $28,683
0&M $ $ $ $ $
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternative 1: Estimated cost unknown as work done as needed.
Reactionary Approach
Reacting only when an issue occurs to mitigate thermal overloads, power quality issues, reliability,
and safety issues.
Conductor will 'sag' down beyond design limits and contact joint-use telecom circuits or violate
NESC prescribed limits. In extreme situations, conductor failure will occur. Service quality will
degrade below acceptable levels and customer outages will increase. System reinforcements (if
they occur at all) will be done in a"scattered" approach and not guided by engineered plans and
solutions.
Reactionary Approach is unacceptable. Violates NESC/WAC regulations and industry standards.
It also represents an unacceptable level of risk to public safety and infrastructure. Knowingly
avoiding upgrades until there is an actual observed violation might open the company up to more
liability in the form of negligence. This can be financially devastating for the company, and it is
difficult to estimate how much this added liability might cost.
This approach removes this business case entirely and all reactionary work would be completed
via the Minor Rebuilds business case. Initially we would see cost savings ($14 million requested
budget) because this business case would no longer be funded. However, there would be an
inevitable cost increase in the Minor Rebuilds business case. Additionally, the increased cost
associated with the added liability would more than offset any cost savings.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 11 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 35 of 535

DocuSign Envelope ID:94B3E083-EF10-4288-8074-73EEF96FAEC8
Distribution System Reinforcements
Alternative 2: Estimated cost$5 million.
Load Shifting and Capacity Increases Only
Focus our efforts on Capacity Increases and Load Shifting projects only while not funding any
work for System Reinforcements.
Attempting to only focus on either Load Shifting or Capacity Increases alone would miss many
other projects that target reliability, service quality, operational flexibility, and distribution
automation. Additionally, this approach would not allow for projects to be completed under this
business case to address safety issues increasing the public's and the company's overall risk
exposure. These projects would have to be addressed through other funding mechanisms and
would likely be more reactionary efforts. This alternative would likely still require at least a $5
million investment on a yearly basis.
Alternative 3: Estimated cost $14 million each year for the next 5 years then back down to
original request of$7.5 million.
Accelerate Funding in Distribution System Reinforcements
Increase the funding amount to nearly double of the previously requested amount, i.e., increase
the funding to$14 million per year for the next 5 years.
Increasing the funding to$14 million would allow us to work through the stockpile of projects that
we have in our 5-year plan. All the projects in our 5-year plan are needed but because of our
limited budget we're prioritizing them accordingly. However, as we've experienced recently in the
last few years unforeseen weather events can accelerate the need immediately leaving our
system ill-equipped to handle the service load. Predicting which areas will have these issues has
proven challenging at best and most of the time we've exhausted the quick fixes leaving us with
only the longer term more complex and costly fix as a viable solution. Many of these longer-term
fixes require multiyear projects but accelerating our funding would allow us to complete this work
quicker to get ahead of the next weather event that might stress our system beyond what it's
currently capable of handling.
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
The main metric to use to measure this business case's success is our electric distribution system
performance. This business case provides a mechanism for our Operations Engineers to address the
most critical system issues which in turn improves system performance. Our ability to mitigate system
performance issues and how many we address every year is the best metric to measure success. In
general, our intent is to keep our feeders and other equipment below 80% of their capacity ratings.
This 80% threshold comes from our System Planning group and their system planning standard "DP-
SPP-02 Distribution System Performance." Keeping our infrastructure below the 80%threshold helps
our system handle unforeseen weather events that often are accompanied by extra ordinary service
loads. As previously stated, most of the work in this business case addresses system capacity
constraints but all the work is tied to a system issue or forecasted issue being corrected. We keep
Business Case Justification Narrative Template Version: February 2023 Page 12 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 36 of 535

DocuSign Envelope ID:94B3E083-EF10-4288-8074-73EEF96FAEC8
Distribution System Reinforcements
track of what issue each project is mitigating so that it can be easily reported out in the following format
(example only): 10 capacity constraint jobs, 3 reliability jobs, 5 voltage issue mitigation (power quality)
jobs, and 2 safety mitigation jobs. We also keep track of miles of reconduct and/or overhead to
underground conversions.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
This business case is an ongoing effort that must be funded on a yearly basis. As such, next year's
projects are identified in Q3 of the current year and work is started as soon as possible. Additionally,
there are numerous projects every year in this business case that span Avista's entire 19,300+ circuit
miles of electric distribution. The work is typically done consistently throughout the year monthly and
is coordinated with each Operations Office. This work gets incorporated into every Operations Office's
workplan schedule and is subject to changes depending on how each workplan fluctuates. The peak
months typically follow our services territories construction season, Spring to Fall, as often we have
limited access to areas during the Winter months. Most of the time when a project is complete it will
be transferred to plant immediately.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
Steering Committee or Advisory Group Information
Distribution Area/Operations Engineers and Distribution System Planning:
Tim Figart&Caitlin Greeney—Spokane and Deer Park
Marshall Law&Marc Lippincott—East Region (CDA, Kellogg, St. Maries, Sandpoint)
Dan Knutson—Othello&Davenport(Big Bend)
Tyler Dornquast—Colville
Chris Dux&Knute Rognaldson—South Region (Pullman, Clarkston, Grangeville)
John Gross,Amber Blackstock, Erick Lee, Kyle Hausam, &Damon Fisher—Distribution System Planning
Cesar Godinez—Distribution Engineering Manager
The Operations Engineers meet monthly to review projects and construction processes and discuss
near term operating conditions. The entire team also meets annually to focus attention and resources
on the system planning needs for grid capacity, service revisions, and substation capacity.
Decision Making Process
The decision model is represented by individual 'proposals' coupled with joint review and acceptance
by distribution engineering and distribution system planning. The project 'proposals' typically consist
of a Project Requirement Diagram (PRD)that outlines the scope of the project and includes supporting
Business Case Justification Narrative Template Version: February 2023 Page 13 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 37 of 535

DocuSign Envelope • 1' 1 :1
Distribution Reinforcements
calculationsI documentation. I •I business case is modified annually to
work plan. Capital • Group then reviews all the submitted business cases and
prioritizes and allocates res• • organization. 1 • not part of
"EngineeringRoundtable" except • distribution su1 . • and other larger distribution projects on
The DistributionReinforcements business case decision •I' 'I below.
Authorized • by CPG
Proposal AcceptanceApproval
Requested Resources
Distribution • •
(Area/Operations Enginee
Business Case
Problem Area Identified by Operations
Engineer(South,East,Big Bend,Colville,
and Spokane)Region Proposals to
principally:
1) Reconductor line"segment"to (Distribution Team) (Capital Planning)
mitigate thermal overload or low All project proposals reviewe Business Case review generally
voltage issues. results in partial funding of the
2) Construct Tie-Line connection to by Distribution Engineering a work plan. The Distribution
Planning to provide peer
shift demand to an adjacent Team(OEs,Mgr,Planning)
circuit. review. Initially screening t eassembles to prioritize,rank,
3) Install/replace transformers to determine priority ranking a and schedule projects to align
immediacy. Business Case
mitigate voltage issues or Revised annually to represent 5 with authorized budgets.
overloaded transformers.
4) Install voltage regulator,capacitor Year planning horizon.
bank,or other equipment to Submitted to CPG
mitigate power quality issues.
5) Install recloser,protection
devices,or other switching
equipment(including"Smart"
devices)to mitigate
reliability/safety issues and/or add
n»Pratinnal flPxihility
Justification - • •n: February 2023 .•- of
bit No. 10
Case • 1 1
J. •
Schedule .•- 38 of

DocuSign Envelope ID:94B3E083-EF10-4288-8074-73EEF96FAEC8
Distribution System Reinforcements
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Distribution System Reinforcements and
agree with the approach it presents. Significant changes to this will be coordinated with and approved
by the undersigned or their designated representatives.
DocuSigned by:
Signature: (LSW GbiM,�) Date: May-02-2024 1 2:48 PM PDT
Print Name: Cesar Godinez
Title: Distribution Engineering Manager
Role: Business Case Owner
IL
igned by:
Signature: AULU&SL� Date: May-02-2024 1 2:52 PM PDT
Print Name: Vern Malensky
Title: Director of Electrical Engineering
Role: Business Case Sponsor
Business Case Justification Narrative Template Version: February 2023 Page 15 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 39 of 535

DocuSign Envelope ID:84EBA5D1-6965-4B89-B843-63629E39BC76
East Coeur d'Alene Lake System Reinforcement
EXECUTIVE SUMMARY
Growth on the east side of Lake Coeur D'Alene is impacting the ability of the existing distribution system to
reliably serve customer load. During winter peak loading conditions, the feeder cable that crosses Lake
CDA is reaching the cable's rating limits. Exceeding equipment ratings will require either pre-emptive load
shed to reduce loading or risk permanently damaging the equipment due to the overload which would result
in a longer duration outage. Operations are also experiencing protection concerns which will only be
exacerbated in the near term. The protection concern is the ability to properly size fault detection devices,
fuses and reclosers, to adequately detect faults while not tripping the circuit due to heavy load. Long rural
feeders such as BLU321 have very low fault current which makes it difficult to distinguish fault current from
load current. The consequence of the protection concerns is primarily fuses melting due to load causing
customer outages and the ability to restore service to the customers is constrained by the additional loading
from cold load pickup therefore requiring staged restorations. Low voltage issues are also evident on
several portions of BLU321. The consequence of low voltage is potentially damaging customer's end use
equipment and not meeting required performance criteria enforced by the state commission. The need for
a plan to mitigate these concerns has been evident for years, and property was purchased in 2011 on Elk
Road near Carlin Bay to be utilized for a future substation. The project was formally brought to the
Engineering Round Table (ERT) in January 2017 for review and prioritization. Upon its approval and
subsequent scoring, it was budgeted under the Substation Asset Business Case (O'Gara), Substation
Performance&Capacity Business Case(Carlin Bay),and Transmission Performance&Capacity Business
Case (115kV Transmission Line) respectively. Due to the complexity, dependencies, and cost of these
system reinforcement projects it was deemed prudent to move it to its own business case. The identified
operational challenges have become more severe with load growth around 5% per year, leading to the
need for the Carlin Bay Substation project. The complete scope will be executed in a phased approach so
equipment loading and protection coordination issues are mitigated and operational while the remainder of
the scope can be completed. The complete scope includes the following:
• Phase 1 includes construction of the Carlin Bay Substation and construction of a 115kV
transmission line tap from the Benewah — Pine Creek 115kV line near O'Gara to the new Carlin
Bay Substation. The initial phase will relieve adjacent Blue Creek and O'Gara distribution feeders
in the near term.
0 115kV Transmission Line Cost: $14,500,000
o Carlin Bay Substation Cost: $13,100,000
• Phase 2 includes a rebuild of the O'Gara Substation. The rebuild will address aging infrastructure,
capacity needs, and increase reliability for area customers and Kootenai Electric who has a feeder
out of the existing substation.
o O'Gara Substation Cost: $17,100,000
It is important to note the dependencies amongst the three projects. Due to the lack of transmission in this
area the transmission line will need to be constructed first in order to energize the new Carlin Bay substation
upon its completion. From there Phase 2 will commence with the construction of the rebuild of the existing
O'Gara Substation. Property for the new O'Gara substation was purchased in 2023. The transmission line
project commenced with the line siting process in 2023. This portion involved hiring a consultant to identify
the best route possible while limiting environmental, property, and cost impacts.
Technical analysis completed by System Planning has been performed to confirm the project as proposed
provides acceptable system performance and mitigates the critical issues which exist on the distribution
feeders, impacting customers on the east side of Lake Coeur D'Alene.
VERSION HISTORY
Version Author Description Date
Katie Prugh/
1.0 Karen Kusel/ Initial draft of original business case May 2024
John Gross
BCRT BCRT Team Has been reviewed by BCRT and meets necessary requirements Es
C
Member
Business Case Justification Narrative Template Version: February 2023 Page 1 of 16
Exhibit No. 10
Case Nos.AVU-E-25-01iAVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 40 of 535

DocuSign Envelope ID:84EBA5D1-6965-4B89-B843-63629E39BC76
East Coeur d'Alene Lake System Reinforcement
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT($)
2024 $525,000
2025 $3,995,000
2026 $8,850,000
$27,600,000 (TRANSMISSION
2027 $19,400,000 LINE, CARLIN BAY
SUBSTATION)
2028 $10,530,000 $17,100,000 (OGARA
SUBSTATION)
2029 $610,000
Project Life Span 10 Years
Requesting Organization/Department Substation Project Delivery
Business Case Owner Sponsor Brian Vandenburg Vern Malensky
Sponsor Organization/Department P03
Phase Initiation
Category Project
Driver Performance & Capacity
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
The population and load demand growth on the east side of Lake Coeur D'Alene has resulted in
rising concerns for Avista to reliably support new customers at the far-reaching end of two distribution
feeders. Currently, two distribution feeders serve the east shore of Lake Coeur D'Alene, one
originating from the Blue Creek Substation and the other originates from the existing O'Gara
Substation. The associated feeders cannot support additional growth in the area and have reached
their capacity.A 13.2kV distribution system is constrained in serving long distances due to protection
coordination issues distinguishing fault current from load current. The consequence of protection
coordination issues is customers will experience outages due to fault detection devices, fuses and
reclosers, tripping under heavy load conditions. Equipment capacity issues have emerged, including
overloaded feeder cable, voltage drop, voltage imbalance, reduced fault current, overloaded fusing
and feeder protection, and cold load pickup, all of which, contribute to system protection challenges.
To prevent overloading equipment, Avista will disrupt service to customers to reduce loading or risk
the equipment becoming damaged which would result in a longer outage duration to customers.
Forecasted load in the area will further stress the existing infrastructure. Much of the new and
forecasted load is concentrated at the far reaches for each distribution feeder. Additionally, several
Business Case Justification Narrative Template Version: February 2023 Page 2 of 16
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 41 of 535

DocuSign Envelope ID:84EBA5D1-6965-4B89-B843-63629E39BC76
East Coeur d'Alene Lake System Reinforcement
large developments, similar to the Gozzer Ranch development have either been proposed or are
under development. The following table is a list of known developments under various stages of
construction or planned for the near future. Some customer projects are waiting for Avista to
mitigate the above listed performance issues prior to them starting construction.
Powderhorn Ranch [25%conf] up to 1300 residences 2023 OGA611
Patriot Homes [100%conf]-40 units 2023 BLU321
Fish Inn Campground [100%conf]Campground w/cabins& 2023 BLU321
RV spots
Burma Rd [100%conf]old mill needs cleanup 2024 BLU321
Gotham Bay [100%conf]-50 premium lots 2024 BLU321
[100% conf]3000 sq ft houses-
Stonegate Development Harrison has building moratorium b/c of 2024 BLU321
sewer issues-3ph PM for water
Carlin Bay Lodge Replacement [75%conf] 2024 OGA611
Table 1 provides the expected feeder and transformer loading over the next 10 years. Avista has
established performance criteria in the planning horizon to mitigate equipment loaded about 80% of
its applicable facility rating. When equipment approaches 100% of its facility ratings in real time
operations, customers power will be turned off to prevent damaging equipment. In the East Lake
Coeur d'Alene area, customer outages can have long restoration times due to cold load pickup
causing fuses and/or reclosers to trip.
Feeder - 2025 2026 2027 2028 2029 2030
BLU Xfmr1 55 58 61 64 67 71 75 79 83 88 93
BLU321 75 80 84 90 95 100 107 113 120 127 135
BLU322 24 24 24 25 25 25 26 26 26 27 27
OGA Xfmr 1 90 90 94 96 98 100 102 104 106 106 106
OGA611 94 94 102 105 109 113 116 120 124 124 124
OGA612 KEC1 121 121 121 121 121 121 121 121 121 121 121
Table 1: Blue Creek and O'Gara Forecasted Peak Loading (%)
Several enhancements have been implemented to the distribution system to delay the need for a
new substation and all feasible alternatives have been exhausted.
• Reconductor four miles of the BLU321 feeder
• Adjust locations of protective devices and their settings as well as fuse sizes to best
accommodate load.
• Balance feeders and laterals
Despite system enhancements, the near-term planning horizon reveals existing infrastructure will
be unable to reliably accommodate anticipated customer service requests and load growth in the
area.
1.2 Discuss the major drivers of the business case.
Gozzer Ranch and other housing developments on the east side of Lake CDA continue to drive up
loading levels on BLU321 and OGA611 and has pushed our existing system to its capacity. A
substation near Carlin Bay will be needed to serve the load as it continues to increase. The
' Loading constraints on the OGA612 feeder are being addressed outside of the scope of this business case.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 16
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 42 of 535

DocuSign Envelope ID:84EBA5D1-6965-4B89-B843-63629E39BC76
East Coeur d'Alene Lake System Reinforcement
transmission tap to feed Carlin Bay will come from O'Gara, which will need 115kV breakers
installed when the new tap is added, becoming a switching station. Additionally, BLU321 is
experiencing loading and protection coordination challenges and Avista is running out of switching
options for this area. To accommodate the new Carlin Bay Tap, and to improve reliability to O'Gara
and St. Maries, a switching station at O'Gara needs to be installed with four transmission line
breaker positions and a new distribution transformer with two 13kV feeders. Today BLU321
supports 1,847 customers and that number is expected to continue to grow. Once Carlin Bay is in
service, approximately 500 of our existing Blue Creek customers will be transferred to one of the
new Carlin Bay feeders.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The impact of not performing this work is Avista would not be able to reliably serve an area that is
experiencing significant growth. Customers will experience outages during peak winter conditions
when building electric heating demand is high.The outages may occur due to overloaded equipment
tripping or failing, or Avista intentionally reducing load to prevent equipment damage. The outages
could impact several hundred customers for multiple hours and may occur daily until peak winter
loading weather conditions pass. Further customer growth in the area will increase the number of
impacted customers.
Phase 2 of the project is the rebuild of O'Gara Station to provide circuit breaker protected
transmission line positions for the existing Benewah — Pine Creek 115kV Transmission Line, radial
transmission line tap to Saint Maries Station, and new radial transmission line tap to Carlin Bay
Station. Deferral of Phase 2 will result in the customers served by the Carlin Bay, O'Gara, and Saint
Maries stations to be exposed to 15 miles of additional transmission line. The rebuild of O'Gara
Station will result in only the customers served by Carlin Bay Station to be exposed to the additional
15 miles of transmission line. Fifteen miles of transmission line exposure through forested areas may
expect to have 1-2 unplanned outages per year. Restoration to the 5000+Avista customer and KEC
customers served by O'Gara and Saint Maries stations will take approximately 2-4 hours.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
The East Lake Coeur d'Alene System Reinforcement project provides additional capacity to the
system which is"critical to serving our customers and unlocking pathways to growth"as stated in our
Perform Focus Area. The Perform Focus Area of Avista's focus goals is the primary alignment with
the requested project but there are elements to the project which are aligned with the theme of our
Vision, Mission, and Focus Areas.
Our Customers:
Existing and future customers on the East side of Lake Coeur d'Alene expect to have reliable
electrical service. Avista needs to deliver a system which can serve the customer demands and
continue to meet the company's defined reliability objectives.
Our People:
The portion of our company who will support the implementation of the project represents a core
electric utility collection of our employees. These employees will take pride in the efforts of such a
transformative project which will impact the community in a positive way.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 16
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 43 of 535

DocuSign Envelope ID:84EBA5D1-6965-4B89-B843-63629E39BC76
East Coeur d'Alene Lake System Reinforcement
Perform:
With completion of the project, Avista will be unlocking growth potential in this area by providing an
electric system with capacity to meet the energy demands of new customers.
Invent:
Constructing transmission lines and substations are traditional project alternatives but Avista has the
opportunity to improve the construction and delivery process as part of such a large-scale project.
Vision; Better energy for life:
Investment in the transmission system represents a long term invest of infrastructure which will be
in place to serve our customers for several generations.
Mission: We improve our customers'lives through innovative energy solutions:
The Carlin Bay Substation and associated projects have been identified as the most prudent energy
solution to deliver the high-level capacity needed to serve the area.The additional capacity is needed
to meet our customer's need for power.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
System Planning has completed a thorough system study for this project. Many of the details have
been added to this business case document, a detailed engineering analysis is included in the
System Planning Study Report. Additionally, the electric system is analyzed bi-annually through the
System Assessment process performed by the System Planning team. The most recent System
Assessment is the 2023-2024 System Assessment Version 0 (2023-2024 Avista System
Assessment-VO.pdf). An example of study results are shown in the table provided in section 1.2.
During the January 13th, 2024 peak winter conditions, operational issues as previously described
impacted customers. The picture provided below is an example of an 80T fuse which melted due too
much load.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 16
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 44 of 535

DocuSign Envelope ID:84EBA5D1-6965-4B89-B843-63629E39BC76
East Coeur d'Alene Lake System Reinforcement
Low voltage issues were also experienced during the same peak winter conditions. The first diagram
below represents the voltage measured by the ZC952V midline regulator on BLU321. Low voltage
on the feeder results in voltage at customer service points not meeting state requirements and can
result in damage to customer end use equipment. Low voltage issues were also present on the
OGA611 feeder which is represent by the second diagram below for the ZC620V midline regulator.
7.W
s
„ev as
120V base
Business Case Justification Narrative Template Version: February 2023 Page 6 of 16
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 45 of 535

ono sign Envelope ID:84EoA5o1-6yan-4oDS-a8*o-6asuSs3SsC78
East Co d'Alene Lake System Reinforcement
2. PROPOSAL AND RECOMMENDED SOLUTION 'Describe the proposed solution to
the business problem identified above and why this is the test andlor least cost alternative (e.g, cos/benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above'
The complete scope of the Carlin Bay Project will be executed in o phased approach so immediate
concerns are mitigated and operational while the remainder nfthe scope can be completed. The
complete scope includes the following:
° Phase includes construction of the Carlin Bay Station and a 11 5kV transmission line tap from
the Benewah—Pine Creek 11 5kV Transmission Line near O'Gara to the Carlin Bay Station.The
expected in-service date io2O28.
o 115kV Transmission Line Cost: $14.500.000
o Carlin Bay Substation Cost: $13.100.000
8uoinoau Case Justification Narrative Template Version: Fobruary2023 PoQoT uf1G
Exm bit No. 1O
Case Nos.wvU's�5-n1AxU'S�5-01
J. o|L"ciano.Axima
Schedule a. Page 46 orn3n

DocuSign Envelope ID:84EBA5D1-6965-4B89-B843-63629E39BC76
East Coeur d'Alene Lake System Reinforcement
Feeder Feeder
South North 4
Phase I Pro'ectotes
Carlin Bay Substation
-----------------------------t----------
y��y ieo w� y�yim w� y�/y1 wA 1 Future to
f----''-- Blue Creek
1
T, 115 kV
Pine Creek
y nw Io wA
'-------------------------------------------------------------------------------
Legend: O
Exisurig Faci t o,
--New 230 W
—New 115W 115 Wto
New D,,t,,buuon
9QrtlWeit
KEC D,1,,but,o
•u •xse
O'Gara 115 kV to
Substation St Manes
Figure 1:Phase I Implementation Project Diagram
• Phase 2 includes a rebuild of the O'Gara Station to a breaker and a half configuration with space
for a future line position and future capacitor bank. The expected in-service date for this work is
2028.
o O'Gara Substation Cost: $17,100,000
Business Case Justification Narrative Template Version: February 2023 Page 8 of 16
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 47 of 535

DocuSign Envelope ID:84EBA5D1-6965-4B89-B843-63629E39BC76
East Coeur d'Alene Lake System Reinforcement
Feeder Feeder
South North
Carlin Bay Substation Phase 2 Project Notes:
URe a.a ii wra lu[e 115 kV beam wd uie
hap amrwmwe+m.t+y13 SIN asbounm
R616Id111e ala Oro aaeaba011 Mlles
ODnq+ka ina SW"Mr.P A-JMvp
to a RAM capeu0r Ma
8g 3 Vaaape AMut 4 ke FOW.612 wA 0e nWPMO
mory �r .vn �: .vA !L. Fuwrero Gana YatrM br KEC
e____ •�_� Blw Crwk
1 ®SPA Mam mMwnp Mr*C Naaw
O5 0 G00%ftLYW wa eKAw■maeeere aae
M a tate!,a cueacbm M keu P"
i
»we
116 W to
EAMnq Fetlike
New 230 kV O'Gara Substation 1 Pine Creek
New 115 kV
New Diabftb" -.
NEC Distribution
115kVto1�
Benewah
115 kV to
` O St Manes
Mk4 Peek
av+nr
>a wa
t
�% Fe K814
I 1
O'Gara t
0 Feeder611
Figure 2:Phase 2 Implementation Project Diagram
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).3
Study reports prepared by System Planning can be referenced for the East CDA Lake System
Reinforcement. An example of work includes:
3 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 9 of 16
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 48 of 535

DocuSign Envelope ID:84EBA5D1-6965-4B89-B843-63629E39BC76
East Coeur d'Alene Lake System Reinforcement
• 2023 Avista System Plan—Version 0, 2024
• BLU321-OGA611 —2023-24 Winter Peak Loading Summary
• Carlin Bay Station—Version A
Risk analysis performed by System Planning shows the project results in an 80% risk reduction. The
scope of the project reduces likelihood of occurrence of the issues described in other sections. The
impact scores are based on implications of dropping load during contingency situations. The table
below provides analysis results.
Option 1 Option 2 Option 3 Option 4
Issue Description Risk Category Do convert No Proposed
NothingRisk to 25kV Risk O'Gara Risk Scope Risk
Likelihood 4 1 1 1
Financial Impact 2 2 2 2
BLU321 Feeder Stakeholder Impact 3 3 3 3
1.1 Loading Outages 3 152 3 38 3 38 3 38
Safety 4 4 4 4
Environmental 0 0 0 0
Likelihood 5 1 1 1
Financial Impact 2 2 2 2
BLU321 Low Stakeholder Impact 3 3 3 3
1.2 Voltage Outages 3 190 3 38 3 38 3 38
Safety 4 4 4 4
Environmental 0 0 0 0
Likelihood 5 1 1 1
Financial Impact 2 2 2 2
BLU321 Lake Stakeholder Impact 3 3 3 3
1.3 Crossing Cable Outage 3 190 3 38 3 38 3 38
Safety 4 4 4 4
Environmental 0 0 0 0
Likelihood 5 1 1 1
BLU321 Financial Impact 2 2 2 2
Stakeholder Impact 3 3 3 3
1.4 Protection Outages 3 190 3 38 3 38 3 38
Coordination Safety4 4 4 4
Environmental 0 0 0 0
Likelihood 5 0 0 0
Financial Impact 1 1 1 1
BLU321 Open Stakeholder Impact 1 1 1 1
1.5 Delta Voltage Outages 1 20 1 0 1 0 1 0
Safety 1 1 1 1
Environmental 0 0 0 0
Likelihood 5 1 1 1
Financial Impact 2 2 2 2
OGA Feeder Stakeholder Impact 3 3 3 3
2.1 Loading Outages 2 165 2 33 2 33 2 33
Safety 4 4 4 4
Environmental 0 0 0 0
Likelihood 5 1 1 1
Financial Impact 2 2 2 2
OGA Low Stakeholder Impact 3 3 3 3
2.2 Voltage Outages 2 165 2 33 2 33 2 33
Safety 4 4 4 4
Environmental 0 0 0 0
Likelihood 5 1 1 1
OGA Financial Impact 2 2 2 2
2.3 Transformer Stakeholder Impact 3 165 3 33 3 33 3 33
Loading Outages 2 2 2 2
Safety 4 4 1 4 4
Business Case Justification Narrative Template Version: February 2023 Page 10 of 16
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 49 of 535

DocuSign Envelope ID:84EBA5D1-6965-4B89-B843-63629E39BC76
East Coeur d'Alene Lake System Reinforcement
O tion 1 O tion 2 O tion 3 Option 4
Issue Description Risk Category Do Risk convert Risk No Risk Proposed Risk
Nothingto 25kV O'Gara Scope
Environmental 0 0 0 0
Likelihood 4 1 1 1
Financial Impact 2 2 2 2
OGA Protection Stakeholder Impact 3 3 3 3
2.4 Coordination Outages 2 132 2 33 2 33 2 33
Safety 4 4 4 4
Environmental 0 0 0 0
Likelihood 5 0 0 0
Financial Impact 1 1 1 1
OGA Open Delta Stakeholder Impact 1 1 1 1
2.5 Voltage Outages 1 20 1 0 1 0 1 0
Safety 1 1 1 1
Environmental 0 0 0 0
Likelihood 0 0 4 0
Financial Impact 2 2 2 2
3.1 Transmission Stakeholder Impact 3 0 3 0 3 124 3 0
Outages Outages 3 3 3 3
Safety 3 3 3 3
Environmental 0 1 0 0 1 0
Overall Option Risk 1 1389 284 408 284
Reduction in Risk 0% 80% 71% 80%
Option 1 to O tion X
2.3 Summarize in the table and describe below the DIRECT offsets4 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
0&M $ $ $ $ $
New transmission infrastructure projects are required to safely and reliably serve customers. O&M
costs include monthly inspection of the substations, periodic inspection of the transmission line,
substation yard maintenance (i.e., weed prevention, fire extinguisher replacement), and substation
equipment maintenance. Annual O&M costs for a transmission substation is approximately$50,000.
2.4 Summarize in the table and describe below the INDIRECT offsets (Capital
and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
0&M $ $ $ $ $
No indirect capital or O&M offsets are expected to result from this investment. Qualitatively the
project reduces exposure to potential customer outages as described in the problem statement and
avoidance of possible fines for non-compliance with NERC standards. Both examples of savings
cannot be clearly defined with assumed values.
a Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2023 Page 11 of 16
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 50 of 535

DocuSign Envelope ID:84EBA5D1-6965-4B89-B843-63629E39BC76
East Coeur d'Alene Lake System Reinforcement
The table below details the Avista System reliability results for 2023.
Reliability Measure—11111111111mv-2023 Results 20Z2 Results Prior
(2018-2022)
SAIFI 0.79 0.92 0.95 es
SAIDI 113 minutes 146 minutes 140 minutes
(1.89 hours) (2.43 hours) (2.34 hours)
CAmI 142 minutes 158 minutes 148 minutes
(2.37 hours) (2.64 hours) (2.47 hours)
CEM13 3.61% 6.02% 5.73%
CAIFI 1.77 2.05 2.06
Table 2:Reliability Results for Key Measures in 2023t1
The table below details the reliability results for the OGA611 Feeder:
Reliability Measure 2023 Results
SAI R 1.93
CAI DI 3.36
CEM13 31.53%
The table below details the reliability results for the BLU321 Feeder:
Reliability Measure 2023 Results
SAI R 3.92
CAIDI 3.19
CEM13 69.8%
As shown in the tables above, both feeders are substantially above the average system reliability
results. The implementation will help improve the reliability in this area. Additionally, it will add
operational flexibility for the area when work needs to be performed.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternative 1 — Do Nothing/Status Quo: $0
The expected system performance if no mitigation alternatives are executed were previously
discussed in the Business Problem. BLU321 is at capacity to accommodate existing loading levels
as it relates to maintaining adequate feeder protection. Both BLU321 and OGA611 each have 3
stages of voltage regulation (including substation regulators). Providing sufficient voltage regulation
is already a challenge and will become more difficult as load continues to increase. Represented
Business Case Justification Narrative Template Version: February 2023 Page 12 of 16
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 51 of 535

DocuSign Envelope ID:84EBA5D1-6965-4B89-B843-63629E39BC76
East Coeur d'Alene Lake System Reinforcement
below are previous recorded winter peak loading values compared to the last cold load pickup event
recorded.
The following data was recorded for the BLU321 feeder.
• The highest cold load pickup was 397A recorded on 3/25/2021 which was—2.5x the pre-outage
load of 145A.
• The winter peak load on 1/13/2024 was 533A.
• Using 387A as a potential pre-outage load, the cold load pickup is expected to be 2.5 x 387A
= 967A. The cold load pickup exceeds the phase pickup setting of 525A for the ZC150R.
The following data was recorded for the OGA611 feeder.
• The winter peak load on 1/13/2024 was 215A.
• Using 184A as a potential pre-outage load, the cold load pickup is expected to be 2.5 x 184A
=460A. The potential cold load pickup is more than the phase pickup of 310A for ZC613R.
The"do nothing"alternative is not valid for the Carlin Bay Substation project as protection challenges
will continue to increase as load in the area increases.
Alternative 2: $75M
Distribution voltage for BLU321 and OGA611 could be increased from 13.2kV, as it operates today,
to 25kV. Today BLU321 supports 1,840 customers and that number is expected to continue to grow.
This choice would improve distribution reliability for customers on the east side of Lake Coeur
D'Alene and eliminate the existing voltage drop, reduced fault current,and cold load pickup concerns.
The conversion would be very involved and complicated. The option would include reconductoring
the feeder from 15kV cable to 25kV and constructing/reconstructing substations to provide 25kV
transformation.This alternative would address the protection challenges however the significant cost
of this option has deemed the option invalid. Additionally, it would result in normal operation feeder
loading levels in excess of 10 MVA as load growth continues into the future, which is inconsistent
with traditional loading guidelines (i.e., the"500A feeder plan").
Alternative 3: $27.6M
A new Carlin Bay Substation could be fed from a tap of the Benewah — Pine Creek 115kV
Transmission Line near O'Gara. This option would reduce modifications needed at O'Gara thus
reducing the overall cost of the project by almost $17.1 M million. Alternatively, this option does not
address equipment condition concerns at O'Gara and increases customer exposure to outages on
the Benewah — Pine Creek 115kV line thus reducing customer reliability in the area. Approximately
5000+ customers will be exposed to an additional 15 miles of transmission line exposure which may
cause 1-2 outages per year with a duration of 2-4 hours.
Alternative 4: $44.7M
In addition to development of the Carlin Bay Station, this option includes re-building the O'Gara
station to be a switching station. This option increases the overall cost of the project however
provides significant benefits for the reliability of the system. Existing customer exposure to outages,
due to the O'Gara—St. Maries 115kV line section and O'Gara— Pine Creek 115kV line section, will
be eliminated with implementation of a switching station at O'Gara. Customers fed from transmission
between the Benewah and Pine Creek stations will have redundant sources thus increased reliability.
Equipment condition concerns at O'Gara are also alleviated with implementation of this option.
Based on benefits described above, a rebuild of the O'Gara Substation is included in the scope of
the project.
Business Case Justification Narrative Template Version: February 2023 Page 13 of 16
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 52 of 535

DocuSign Envelope ID:84EBA5D1-6965-4B89-B843-63629E39BC76
East Coeur d'Alene Lake System Reinforcement
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
Successful mitigation of the problem statement will be monitored as part of the bi-annual System
Assessment conducted by System Planning. The project will be successful if performance criteria in
short-term planning horizon studies can be met, and performance issues are not observed in the
operations time horizon.Assumptions made in System Assessments are not static therefore projects
are developed based on the best information available. For example,future load forecasts may show
additional load growth not expected when a project is requested. If the project takes ten years to
construct, it is possible the base line assumptions have changed, and additional projects will need to
be justified.
The performance criteria metrics which are monitored as part of the System Assessment process
are provided in DP-SPP-02 — Distribution System Performance. Expected performance following
completion of the project is all impacted distribution equipment will be loaded less than 80% of
applicable facility ratings during forecasted peak load conditions.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Schedule for the new Carlin Bay 115kV Substation, 115kV Transmission Line, and O'Gara 115kV
Substation:
115kV Transmission Line:
2023: Line Siting
2024: Design and Easement Acquisition
2025: Final Design
2026: Construction
2027: Finish Construction
Carlin Bay Substation:
2024: Early Permitting
2025: Distribution Design
2026: Scoping, Design, Site prep and Fencing
2027: M/S and Electrical Construction
2028: Relay& Protection Construction and Energize Substation
O'Gara Substation:
2025: Scoping and Start of Design
2026: Complete Design, Site prep and Fencing
2027: M/S Construction and Start Electrical Construction
2028: Complete Electrical Construction, Relay & Protection Construction and Energize
Substation
Business Case Justification Narrative Template Version: February 2023 Page 14 of 16
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 53 of 535

DocuSign Envelope ID:84EBA5D1-6965-4B89-B843-63629E39BC76
East Coeur d'Alene Lake System Reinforcement
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
For the Carlin Bay Substation and associated projects,there will be a Project Manager, Construction
Inspectors and Design Engineers (Transmission, Substation and Distribution) that will form the
oversight group. The Engineering Roundtable will provide technical review of potential scope
changes with the support of the System Planning and Operations department. Scope changes which
require additional fund requests to the Capital Planning Group will be vetted at the Engineering
Roundtable.
- Expected spend monthly meetings with Electrical Engineering managers.
Business Case Justification Narrative Template Version: February 2023 Page 15 of 16
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 54 of 535

DocuSign Envelope ID:84EBA5D1-6965-4B89-B843-63629E39BC76
East Coeur d'Alene Lake System Reinforcement
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the East Coeur d'Alene Lake System
Reinforcement and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.
DocuSigned by:
Signature: Date: May-14-2024 1 9:55 AM PDT
Print Name: 0304BEIPMWVandenburg
Title: Manager of Engineering Projects
Role: Business Case Owner
DocuSigned by:
Signature: Date: May-14-2024 1 9:57 AM PDT
Print Name: 06C4F~EMWensky
Title: Director of Electrical Engineering
Role: Business Case Sponsor
Signature: Date:
Print Name: N/A
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 16 of 16
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 55 of 535

Electric Replacement and Relocation
EXECUTIVE SUMMARY
The Electric Replacement and Relocation (Road Moves)program is driven by compliance that is mandated
by the "Franchise Agreement' contracts with local city and state entities, and "permits" issued by Railroad
owners. Within each agreement are provisions for relocation of utilities at the request of the right-of-way
(ROW) owner. Under a Franchise Agreement or Permit, Avista is allowed to occupy space within a ROW
owned by the respective jurisdiction in order to serve its customers, but must relocate utilities at the request
of the ROW owner. Electric relocations occur every year, mainly during construction season, but are
primarily unplanned, so historical trends are used to estimate the annual cost to fully fund all the relocation
projects. The annual cost of electric relocations varies slightly year to year. Current funding needs have
increased due to additional road projects driven by additional government funding sources. Fully funding
the business case will likely ensure all electric relocations under franchise agreements or permits will be
completed. This is mandatory work to maintain compliance with existing franchise and operating permits
with state highway districts and railroads. This impacts both Washington and Idaho customers.
The Electric Relocations business case is unplanned, demand driven work that is contractually obligated
and adds high risk to the company if not completed. Funding allocation is based on historical spending
trends. The average historical spend for Electric Relocations has consistently increased over the past five
years,with the exception of last year where we came in under budget at$5.9M, leaving the 3 year average
spend at $7.7M. Since Electric Relocations are directly correlated with the number of highway and street
projects, the reason for the continued increase and some variance in spend is due to an increase in
transportation project spending by local and federal entities.
Business Case Justification Narrative Template Version: February 2023 Page 1 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 56 of 535

Electric Replacement and Relocation
VERSION HISTORY
Version Author Description Date
1.0 Katie Snyder Initial draft of original business case 0411512024
BCRT Team
BCRT Member- Steve Has been reviewed by BCRT and meets necessary requirements 411812024
Carrozzo
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2024 7,000,000 7,000,000
2025 9,000,000 9,000,000
2026 9,000,000 9,000,000
2027 9,000,000 9,000,000
2028 9,000,000 9,000,000
2029 9,000,000 9,000,000
Project Life Span Ongoing
Requesting Organization/Department Electric Operations
Business Case Owner I Sponsor Katie Snyder Paul Good
Sponsor Organization/Department Operations
Phase Execution
Category Mandatory
Driver Mandatory& Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
The Electric Distribution and Transmission Replacement and Relocations (Road Moves)
program is driven by compliance mandated by the "Franchise Agreement" contracts with local
city and state entities and "permits" issued by Railroad owners. A "Franchise Agreement"
generally refers to a non-exclusive right and authority to construct, maintain, and operate a
utility's facility using the public streets, dedications, public utility easements, or other public ways
in the Franchise Area pursuant to a contractual agreement executed by the City and the
Franchisee. Although each Franchise Agreement or permit is a little different, they all serve a
similar purpose in providing utility access along city, county, state, and railroad right-of-way
Business Case Justification Narrative Template Version: February 2023 Page 2 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 57 of 535

Electric Replacement and Relocation
(ROW). The agreement(s) make provisions for Avista to install electric equipment along these
ROWs in order to provide service to Avista customers.
Within each agreement are provisions for relocation of utilities at the request of the ROW owner.
These requests are usually driven by road and or sidewalk re-design projects.
For reference, franchise 95-0990 recorded with Spokane County paragraph VI states `if
at any time, the County shall cause or require the improvement of any County road,
highway or right-of-way wherein Grantee maintains facilities subject to this
franchise by grading or regarding,planking or paving the same, changing the grade,
altering, changing, repairing or relocating the same or by constructing drainage or
sanitary sewer facilities, the grantee upon written notice from the county engineer
shall, with all convenient speed, change the location or readjust the elevation of its
system or other facilities so that the same shall not interfere with such County work
and so that such lines and facilities shall conform to such new grades or routes as
may be established."
For example, a State Department of Transportation (DOT) is widening an intersection or
highway, which requires Avista to relocate their overhead or underground electric facility to
accommodate the new DOT design. A smaller example for instance is a local municipality is
installing new ADA ramps on the corners of local street intersections,which sometimes requires
Avista to relocate a utility pole to accommodate the new ramp design.
The asset conditions replaced through Electric Relocations can vary since the relocations are
unplanned and therefore not coordinated with Avista's Asset Maintenance programs. Most
assets in an Electric Relocation project are replaced because they are unsalvageable or close
to the end of their useful life. In the case of relocating newer assets, efforts are made to re-use
as much material as possible.
Under a Franchise Agreement or Permit,Avista is allowed to occupy space within a ROW owned
by the respective jurisdiction in order to serve its customers. Electric relocations occur every
year primarily during the construction season, but are unplanned, so historical trends are used
to estimate the annual cost to fully fund all the relocation projects. The annual cost of electric
relocations varies slightly year to year. Current funding needs have increased due to additional
road projects driven by both additional government funding sources, therefore fully funding the
business case will likely ensure all electric relocations under Franchise Agreements or Permits
can be completed
1.2 Discuss the major drivers of the business case.
The major driver of this business case is Mandatory&Compliance. Franchise agreements,state
highway and Railroad permits, and the Washington and Idaho Department of Transportation
prescribe that the utility will relocate, at their expense, when in conflict with entity activities. We
need to complete this Mandatory work to maintain compliance with existing franchise and
operating permits with all parties.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
This work is needed, because not doing the mandatory work to fulfill our agreements with state
and local entities would result in us being out of compliance. If we are no longer in compliance
with our Franchise agreements and permits, we could potentially lose the right to install electric
equipment along these ROWS in order to provide service to Avista customers.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 58 of 535

Electric Replacement and Relocation
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
This work is needed, because not doing the mandatory work to fulfill our agreements with state
and local entities would result in us being out of compliance. If we are no longer in compliance
with our Franchise agreements and permits, we could potentially lose the right to install electric
equipment along these ROWS in order to provide service to Avista customers.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
N/A
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
This solution is to perform the required mandatory work as set forth by state and local entities
under the Franchise Agreements and Permits Avista has entered. This is in order to stay in
compliance and continue to be allowed to install electric equipment along ROW's that will enable
us to provide service to Avista's customers.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
In order to prepare this business case we review historical spend to help predict what to expect
for the current and future years. For instance, our five-year average spend is $5.6M and our
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 59 of 535

Electric Replacement and Relocation
spend has been increasing by an average of 17% per year. This would reason that if our spend
was $5.9M in 2023, we could require as much as $7M for Road Moves in 2024. We did see a
decrease in spending in 2023, but we believe this was an anomaly due to local entities moving
out work that had been scheduled for last year. Due to this, we anticipate 2024 having a higher
spend.
Figure 1 Shows the historical 5-year trend in spend and the annual percentage increase rate.
As you can see the spend has consistently trended upward since 2019, with the exception of
2023.
5 Year Historical Trend -Elec Replacement and Relocation
$12,000,000
$10,000,000 `t
$8,000,000 20-F
$6,000,000 0%
$4,000,000 -20%
$2,000,000 -40%
$- -60%
2019 2020 2021 2022 2023
Elec Road Moves 2056 $3,246,503 $4,871,826 $7,253,326 $10,104,256 $5,860,776
-Percent Change from Previous Year 46% 50% 49% 39% -42%
Elec Road Moves 2056 -Percent Change from Previous Year
Figure 1: 5-Year Historical Trend— Elec Replacement and Relocation
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
There are no direct offsets related to this Business Case.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 60 of 535

Electric Replacement and Relocation
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
The Electric Replacement and Relocation program is required due to franchise agreements with
the state, country, and city jurisdictions within our service territories. If any state, county, or city
jurisdiction is conducting road work in our service territory,we are required to move/relocate our
facilities to accommodate the work. Any breach in these agreements could have an impact on
Avista's ability to operate in the public right-of-way. Indirect offsets include the ability to upgrade
aging equipment associated with the facility relocation which will extend the life of the
asset. Examples:An older/aging utility vault needs to be relocated for a road project. Avista will
relocate and upgrade the facility to current standards which will improve longevity, reliability,
and safety.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
This is mandatory work in order for us to remain in compliance and be allowed to continue
operating in the public right-of-way. Due to the nature of the work there are no alternatives. If
unfunded Avista would not be able to perform necessary work and would be out of compliance
with established franchise agreements and/or permits.
Alternative 1:
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 61 of 535

Electric Replacement and Relocation
Alternative 2:
Alternative 3:
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
Measures to determine successful delivery on business case objectives include:
• Year-To-Date Spend (Tracked monthly)
• Compliance with Franchise agreements and/or Railroad permits.
Figure 2 shows the Year-to-Date spend for the current year and a historical for the previous two
years. Based on the previous years we are currently below where we were this time in 2021, but
below this time in 2022. This chart is updated and reviewed monthly in order to project what we
anticipate the year end spend being based on previous years.
ER 2056 Dist Line Relocations/Road Moves
12,000,000
10,000,000 10,104,256
8,000,000
6,999,997
2022
5,860,776
6,000,000 2023
2024
�2024 Budget
4,000,000
2,000,000
834,082
0
1 2 3 4 5 6 7 8 9 10 11 12
Figure 2: ER 2056 (Electric Relocations and Road Moves) Year-to-Date Spend
Business Case Justification Narrative Template Version: February 2023 Page 7 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 62 of 535

Electric Replacement and Relocation
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
As long as we are operating in the public right-of-way,we must continue to complete mandatory work
to remain in compliance. Therefore, this is an ongoing program with no foreseen end date. However,
as we complete each road move under this program it is immediately becomes"used and useful"so
this business case transfers to plant monthly.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
This business case is written by the business case owner, reviewed by the business case sponsor,
and then reviewed by the business case review team. It's then submitted to the Financial Planning
and Analysis (FP&A)team for final approvals. It's spend is continuously monitored by the Operations
Round Table which is comprised of Business Case owners and the department Sponsor, who meet
once a month, and then finally the FP&A who also meet monthly.
Business Case Justification Narrative Template Version: February 2023 Page 8 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 63 of 535

Electric Replacement and Relocation
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Electric Replacement and Relocation and
agree with the approach it presents. Significant changes to this will be coordinated with and approved
by the undersigned or their designated representatives.
Signature: &a&,�_ s Date: 5/10/2024
Print Name: Katie Sny er
Title: Business Analyst III
Role: Business Case Owner
Signature: T*d 60d Date: 5/15/2024
Print Name: Paul Good
Title: Director Electric Operations
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 9 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 64 of 535

DocuSign Envelope ID:B852F7EA-84B2-437C-8164-70D90409E5D4
Electric Storm
EXECUTIVE SUMMARY
The Electric Storm Business Case is focused on restoring Avista's transmission,
substation, communications, and distribution systems (damaged plant) into serviceable
condition during a weather storm event or other natural disaster where assets are
damaged. These storm events are random and often occur with short notice. This
business case is to fund a rapid response to unexpected damages and outages, so
customer outages are minimized. The business case provides funds for replacing poles,
cross arms, conductor, transformers, and all other defined retirement units damaged
during weather storm events. The damage can be due to high winds, heavy ice and snow
loads, lightning strikes, flooding, or wildfires as an example. The importance of quickly
replacing damaged facilities is vital to providing reliable service to our customers. This
impacts customers in WA and ID.
The annual budget amount is determined based on the historical average rate of capital
restoration work including restoration activity related to major event days (MEDs) of
relativity minor restoration impact. Request excludes costs related to very large MEDs. If
not funded, the work will still occur as needed for outages caused by weather storm
events or other natural disasters and would be absorbed through other business cases.
VERSION HISTORY
Version Author Description Date
1.0 Joe Wright Initial draft of original business case 12/12/23
Business Case Justification Narrative Template Version: February 2023 Page 1 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 65 of 535

DocuSign Envelope ID:B852F7EA-84B2-437C-8164-70D90409E5D4
Electric Storm
BCRT Team
BCRT N>rear Has been revievvedbyBCRTand meets necessaryrequirements
mem
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2024 $5,000,000 $5,000,000
2025 $5,000,000 $5,000,000
2026 $5,000,000 $5,000,000
2027 $5,000,000 $5,000,000
2028 $5,000,000 $5,000,000
Project Life Span Annual Program
Requesting Organization/Department Operations
Business Case Owner I Sponsor Paul Good Josh DiLuciano
Sponsor Organization/Department Operations
Phase Execution
Category Program
Driver Failed Plant&Operations
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
Business Case Justification Narrative Template Version: February 2023 Page 2 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 66 of 535

DocuSign Envelope ID:B852F7EA-84B2-437C-8164-70D90409E5D4
Electric Storm
i. BUSINESS PROBLEM - This section must provide the overallbusiness case information
conveying the benefit to the customer,what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
The Electric Storm Business Case (BC) is focused on restoring Avista's
transmission, substation, communications, and distribution systems (damaged
plant) into serviceable condition during a weather storm event or other natural
disasters where assets are damaged. These events are random and often occur
with short notice. This business case funds a rapid response to unexpected
damages, so customer outages are minimized. The business case provides
funds for replacing poles, cross arms, conductor, transformers, and other
defined retirement units damaged during storm events. The damage can be due
to high winds, heavy ice and snow loads, lightning strikes, flooding, or wildfires.
The importance of quickly replacing damaged facilities is vital to providing
reliable service to our customers.
1.2 Discuss the major drivers of the business case.
The primary driver for the Electric Storm BC is Failed Plant and Operations. The
work is a key component to minimizing customer outage times and contributes
to Avista's reliability indices like System Average Interruption Frequency Index
(SAIFI) and Customer Average Interruption Duration Index (CAIDI). The
secondary driver for this business case is Customer Service Quality and
Reliability
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The importance of quickly replacing damaged facilities is vital to providing
reliable service to our customers. The Electric Storm BC is to fund a rapid
response to unexpected damages and outages, so customer outages are
minimized. If this business case is not funded the costs to restoring power to our
customers will be absorbed by another business case. The needed work will
continue to occur.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
The Electric Storm business case aligns with the company's strategic goal of
Safe and Reliable Infrastructure. The work is a key component to minimizing
customer outage times and thus contributes to Avista's reliability indices like
SAIFI and CAIDI.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 67 of 535

DocuSign Envelope ID:B852F7EA-84B2-437C-8164-70D90409E5D4
Electric Storm
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
N/A
2. PROPOSAL AND RECOMMENDED SOLUTION -ascnbetheproposedsolutionto
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The Electric Storm Business Case (BC) is focused on restoring Avista's
transmission, substation, communications, and distribution systems (damaged
plant) into serviceable condition during a weather storm event or other natural
disasters where assets are damaged. These events are random and often occur
with short notice. This business case funds a rapid response to unexpected
damages, so customer outages are minimized. The business case provides
funds for replacing poles, cross arms, conductor, transformers, and other
defined retirement units damaged during storm events.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).'
The annual budget amount is determined based on the historical average rate
of capital restoration work.
Figure 1 shows the historical costs (2017-2022) for the distribution/transmission
storm business case and YTD 2023 expenses through October. From 2017-
2022, the average annual cost for capital storm response was $8.6 million
dollars, with a range of$3.6MM (2018) to $14.6MM (2021). There were 7 MEDs
in 2020 and 4 in 2021. The majority of the MED costs in 2021, however, occurred
' Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 68 of 535

DocuSign Envelope ID:B852F7EA-84B2-437C-8164-70D90409E5D4
Electric Storm
in January, one $7.2MM storm. Consequently, 2020 results were excluded and
2021 results were adjusted downward to exclude the particularly large January
storm for determining the proposed funding level. The average spend for 2017-
2019/2021-2022 was $5.4MM. This includes some MED activity of
comparatively minor restoration impact during these years. Proposed funding
for 2024-2028 is $5M per year. Further funding for significant MEDs will be
requested as needed.
Sum of Transaction Amount
DX/TX Cap Storm Actuals
I Jan 2021
16,000,000
14,630,591 windstorm$7.2M
14,000,000 13,732,822
12,000,000
IQ000,000
8,000,000 6,815,294 599, ,6367
6,309,201 ■Total
6,000,000
4,000,000 3,574,683 3,926,511
2,000,000 ,
0
2017 2018 2019 202(1 2021 2022
Accounting Year .T
Figure 1:Storm Historical Costs
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset ascription 2024 2025 2026 2027 2028
Capital $ $ $ $ $
08M $ $ $ $ $
There are no offsets to O&M. There is no identified direct savings related to this
business case. This business case is completed to replace failed equipment due
to extreme weather events.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 69 of 535

DocuSign Envelope ID:B852F7EA-84B2-437C-8164-70D90409E5D4
Electric Storm
2.4 Summarize in the table, and describe below the INDIRECT offsets' (Capital
and O&M) that result by undertaking this investment.
Offsets Offset ascription 2024 2025 2026 2027 2028
Capital $ $ $ $ $
08M $ $ $ $ $
There are no offsets to O&M.
Current RCW standards obligate us to perform repair work following storm
damage. Therefore, an amount of capital is earmarked for a normal year of
weather events.
Although there are no financial offsets, an ICE (Interruption Cost Estimate)
may be calculated for determining an avoided indirect cost for having this
program.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
The alternative to this business case request is not funding. The costs
associated with repairing damages as a result of a weather storm event or a
natural disaster would be covered through a different business case. Damages
from these events must be repaired, regardless of funding.
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
The primary measure that will be used to determine success is outage duration
including other reliability measures such as Avista's reliability indices like SAM and
CAIDI. These measures will demonstrate the impact of the work charged to this
business case.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 70 of 535

DocuSign Envelope ID:B852F7EA-84B2-437C-8164-70D90409E5D4
Electric Storm
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Weather storm events or natural disasters are a continuous risk. Work will occur
as needed as a result of damaged facilities related to these events. Many times,
multiple events may occur within one year in different office areas. Past data shows
there has not been a year where a storm has not happened. Since this is often
emergency work, assets become used and useful and transferred to plant
immediately.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
The Electric Storm work is overseen by the local area operations engineers and
area construction managers. The work is unplanned and non-specific in nature
but occurs regularly. In the event of larger scale storms or natural disasters, like
the historical storm event in November 2015, a formal Incident Command
System (ICS) is created to manage the resources needed to respond. Other
large events are managed through an emergency operating plan (EOP) with the
Director of Operations.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 71 of 535

DocuSign Envelope ID:B852F7EA-84B2-437C-8164-70D90409E5D4
Electric Storm
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Electric Storm and agree with the
approach it presents. Significant changes to this will be coordinated with and approved by
the undersigned or their designated representatives.
DocoSignetl by:
Signature: Date: Dec-15-2023 112:28 PM PST
Pain, l eel,
SADIIAAIABSCAA9
Print Name: Paul Good
Title: Director of Electric Operations
Role: Business Case Owner
DSigned by:
Signature: 56Z v;�� Date: Dec-15-2023 1 8:35 AM PST
3�T1E7dF65
Print Name: 3oshua Di Luciano
Title: VP Energy Delivery
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 8 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 72 of 535

Joint Use Projects
EXECUTIVE SUMMARY
Joint Use is the regulated use of utility poles and other structures by 3rd party
telecommunications companies in order for them to provide their services to the
customers we have in common. Avista licenses 78 unique enitities that are attached to
over 175,000 poles across our service territory. Avista is required by federal, state, and
local law to allow non-discrimantory access to each of these licensees. Even though this
relationship is mandated by law, and is compliance driven, Avista agrees that this
practice provides a direct benefit to our customers who desire those services.
Part of this requirement includes the obligation of Avista to replace infrastructure to
taller stronger structures in order to accommodate or "make ready" those facilities for
new attachments. This "make-ready" work falls under capital expense and Avista is
allowed to recover the actual costs from the requesting attacher. Avista is also permitted
to recoup a portion of the costs associated with replacing & maintaining it's shared
infratructure through a regulated yearly pole rental fee.
Avista could face potential regulatory and or civil legal action if timelines and obligations
are not met due to a lack of funding. We also risk having an overloaded infrastructure,
jeopardizing the safety and reliability of our system. The outcome of these actions could
result in significant financial loss and penalties.
VERSION HISTORY
Version Author Description Date
1.0 Jesse Butler Initial draft of original business case 41212024
BCRT BCRT Team Member Has been reviewed by BCRT and meets necessary requirements 0510812024
—Katie Snyder
Business Case Justification Narrative Template Version: February 2024 Page 1 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 73 of 535

Joint Use Projects
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT($)
2024 $4M $4M
2025 $5M $5M
2026 $4M $4M
2027 $3.5M $3.5M
2028 $3.5M $3.5M
2029 $3.5M $3.5M
Project Life Span Perpetual
Requesting Organization/Department Operations/Joint Use
Business Case Owner I Sponsor Jesse Butler I Vern Malensky
Sponsor Organization/Department Operations/Joint Use
Phase Execution
Category Mandatory
Driver Mandatory& Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
Business Case Justification Narrative Template Version: February 2024 Page 2 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 74 of 535

Joint Use Projects
BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed? Access
to safe and reliable utility infrastructure by third parties is not only a crucial
element of the connected world in which we live but it is also mandated by
regulators at the federal and state levels. Avista therefore has a duty to repair,
replace or add infrastructure to accommodate those requests.
1.2 Discuss the major drivers of the business case. The major drivers of this
business case are the joint use and licensee's who request new pole
attachments or who must upgrade their existing systems to meet the burgeoning
and ever-increasing demand for reliable and cost efficient communication
needs. This has a direct benefit to not only Avista customers but Avista itself as
we are also consumers of those same telecommunications products. As
mentioned previously, fair, and non-discriminatory access to investor-owned
utility infrastructure is codified in Federal and State laws dating back to the
Federal Telecommunications Act of 1934 which laid the groundwork for the
current system of asset sharing.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
This work is needed currently and will be needed on an ongoing basis not only
for existing wired telecommunication providers but for wireless providers who
are more often than not reliant upon existing vertical utility assets to locate their
equipment. These technologies are commonly referred to as 4G, 5G and LTE.
The risk of not executing to meet these demands could result in regulatory
action, resultant fines, and possible civil litigation that could far outweigh any
short-term savings. Damage to Avista's reputation and loss of customer trust
could also result, and those monetary costs are incalculable.
Business Case Justification Narrative Template Version: February 2024 Page 3 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 75 of 535

Joint Use Projects
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
The investment that is made in Avista's physical plant, to accommodate joint use
telecommunications, benefits the shared customer base of Avista and the joint use
providers. It places our customers at the center of our focus and decreases rate
pressure through the annual rent that is paid by our joint use providers.
Also, it allows Avista to provide safe, reliable, and cost-effective services, by
providing an NESC compliant work environment for all workers who require access
to the electric distribution system, which is required by law.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
Below is the link to the Federal Communications Commission website and a link
for the Washington state Legislature. This is where the federal and state
guidelines/laws we have to adhere to can be found.
Federal Communications Commission
Washington State Legislature
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Our solution is to use the funding from this business case to ensure we follow state
and federal guidelines that require us to provide fair and non-descriminate access
to our infrustructure for the purpose of telecommunications attachments.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2024 Page 4 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 76 of 535

Joint Use Projects
2.2 Describe and provide reference to CIRRARR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits, or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
Current joint use capital business case amounts were derived from historic spend
data coupled with projected activity based on trends seen in the joint use tracking
sheet. This worksheet is where all new pole attachment requests from joint use
licensees are recorded. The data includes the number of poles each joint user
would like to attach to, the date a job is started and completed, and the estimated
and actual costs of the capital make-ready work related to a specific job. Trend,
cost, and performance metrics from this tracking sheet are compiled and shared
with the Joint Use Steering Committee on a quarterly basis.
Below is a chart showing the gross spend for Joint Use over the last three years.
The increases with sudden decreases show where we recovered some of the cost
through invoicing. This is a demonstration of the return on our investment; we pay
upfront cost to meet mandatory compliance and upgrade our assets that
contribute to safer and more reliable service for our customers, and we recoup
part of those costs from the Joint Users.
ER 2074 Joint Use
6,000,000
5,000,000
4,542,717
4,000,000
-2021
3,000,000 ,073,427
—zozz
�2023
2,000,000 1,868,704
1,000,000
0
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2024 Page 5 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 77 of 535

Joint Use Projects
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
0&M $ $ $ $ $
N/A
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
0&M $ $ $ $ $
The Joint Use program is required by law and is clearly defined and regulated by
the FCC and the Public Utility Commissions in both Washington and Idaho. Part
of this requirement includes an obligation by Avista to replace infrastructure to
taller/stronger structures to accommodate or "make ready" those facilities for new
attachments by our joint use licensees. However, these same rules also allow
Avista to recover a portion of the costs associated with these improvements.
The indirect offset is the installation of new infrastructure and the replacement of
aging infrastructure, at a significantly reduced cost to Avista. In general, joint use
licensees pay for up to half of the cost of pole replacements and infrastructure
upgrades. Example: An older/aging utility pole needs to be replaced so that a joint
use licensee can safely attach to that pole, that joint use licensee will then pay for
all, or a portion of the costs, associated with replacing that pole.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
a Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2024 Page 6 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 78 of 535

Joint Use Projects
An additional indirect offset is that the replacement of this aging infrastructure
and/or addition of new infrastructure acts to enhance and further harden Avista's
network against adverse weather and other damage that would directly impact our
ratepayers.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternative 1:
No realistic alternatives exist. The only alternative would be to cease performing
this work which would result in regulatory/legal action and customer
dissatisfaction. In addition, we would be defaulting on 73 Joint Use Master
License agreements.
Alternative 2:
Alternative 3:
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
We track and measure our ability to meet WUTC guidelines bi-monthly. This
Information is presented to the Joint Use Steering Committee for their review.
Business Case Justification Narrative Template Version: February 2024 Page 7 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 79 of 535

Joint Use Projects
Application Approvals & New Contracts
Average Application Approval Time/Joint Use Company
Average of Net Approval Time
AVISTA 18
CHARTER 20
CIVIC 24
COM 13
CTL 37
ELI 12
FTBM 30
INTERMAX 17
MCI 32
NOANET 28
POC 34
POL 18
POW 9
SPARKLIGHT 27
SUDDENLINK 20
TDSM 8
VZW 0
XO 23
ZAYO 26
ZIPLY 24
Joint Use Mutual Licensing Agreement Information
Total number of New -F New
contracts in place Contracts Contracts Contracts
78 0 3 8 0
Business Case Justification Narrative Template Version: February 2024 Page 8 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 80 of 535

Joint Use Projects
Work Demand - Attachment Requests 2023
CIVIC 4 59 352 16 431
ZIPLY 16 106 90 2 214
FTBM 6 130 4 140
CTL 10 23 105 138
TDS 46 34 4 84
CHARTER 13 48 5 66
TDSM 28 1 29
DECLARATION NTWK 26 2 28
INTERMAX 4 23 27
SPARKLIGHT 2 17 19
LINCOLN COUNTY 10 8 18
VYVE-NORTHLAND 18 18
MCI 16 1 17
ADAMS CO 10 6 16
POC 2 9 11
ZAYO 2 8 10
CONCEPT COMM 4 6 10
COLVILLE TRIBE 4 6 10
ELI 2 6 8
POW 6 6
FATBEAM 4 4
WHOLESAIL 4 4
AVISTA 4 4
POL 3 3
WOW 2 2
ARDENT WIRELESS 2 2
KNIGHTCOM 2 2
XO COMMUNINCATIONS 2 2
TOWN OF WASHTUCNA 2 2
DAVIS COMMUNICATIONS 2 2
MOBILITIE 2 2
ST.JOHN 2 2
WIFIBER 2 2
VZW 2 2
COM 2 2
NOANET 2 2
GRAND TOTAL 46 242 945 33 1,339
Data as of 12/31/23
Backlog(The clock starts)—Application,design,and fee received. Not yet fielded or reviewed.
Waiting(clock on hold)—Redlines returned to customer,waiting for response and updated design from customer.
Business Case Justification Narrative Template Version: February 2024 Page 9 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 81 of 535

Joint Use Projects
AVISTA 22 17
CHARTER 377 146 192
CIVIC 2,224 777 1,378
CHARTER
7 4
CTL 1,528 420 876
E LI 33 8 24
FT B M 2,054 1,944 44
I NTE RMAX 490 367 50
MCI 163 124 14
NOANET 3 2
POC 371 303 9
POL 5 4
POW 52 47 2
SPARKLIGHT 129 14 108
TDS 1,286 968 2
TDSM 34 12 4
VZW 1 1
ZAYO 61 1 57
ZIPLY 5,849 3,648 1,493
WHOLESAIL 77 63 14
VYVE-NORTHLAND 173 36 133
LINCOLN COUNTY 1,747 1,644 50
MOBILITIE (30) (30)
WIFIBER 75 61
KNIGHTCOM 20 18
XO COMMUNICATIONS -
AVIS COMMUNICATIONS 2 1
DECLARATION NTWK 1,297 1,108
ADAMS CO 761 681 3
ARDENT WIRELESS 14 8
TOWN OF WASHTUCNA 42 31
WOW 30 - 28
CONCEPT COMM 401 401
ST.JOHN 126 - 120
COLVILLE TRIBE 469 374
FATBEAM 9 7
GRAND TOTAL 19,902 12.798 5,013
2.7 Please provide the timeline of when this work is scheduled to commence
and complete, if known.
This capital work related to this business case are on-going and immediate.
Transfers to plant occur on a monthly basis and the assets become used and
useful immediately following physical construction.
Business Case Justification Narrative Template Version: February 2024 Page 10 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 82 of 535

Joint Use Projects
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
The advisory group for this business case is the Operations Round Table. This
team is a Director/Manager level review team that monitors the year to date spend
for various capital projects including Joint Use. Meetings are held monthly. In-year
Change requests would be reviewed by this team prior to going to the Capital
Planning Group for approval.
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Joint Use Business Case and agree
with the approach it presents. Significant changes to this will be coordinated with and
approved by the undersigned or their designated representatives.
tler
Signature: Jesse Butler Date: l02 .0signed by 09:04: 8-07' Date: 5/13/2024
Date:2024.05.13 09:04:48-07'00'
Print Name: Jesse Butler
Title: Joint Use Business Manager
Role: Business Case Owner
Signature: Vern Malensk Date: l024.0dbyVern05-07' 0' Date: 05.13.2024
Y Date:2024.05.13 09:30:05-07'00'
Print Name: Vern Malensky
Title: Director of Electrical Engineering
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2024 Page 11 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 83 of 535

Meter Minor Blanket
EXECUTIVE SUMMARY
The meter minor blanket is used to charge the labor associated with new electric meter installations
in Washington and Idaho due to the replacement of failed plant(meters)that can no longer gather
or communicate accurate consumption data.
The Meter Minor Blanket Business Case is driven by tariff requirements that mandate Avista's
obligation to serve existing customer load within our franchised area. Annual spending is
approximately $250k per year.
VERSION HISTORY
Version Author Description Date
1.0 Dan Austin Initial draft of on inal business case 511012024
BCRT Team
BCRT Member—Katie Has been reviewed by BCRT and meets necessary requirements 511012024
Snyder
Business Case Justification Narrative Template Version: February 2023 Page 1 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 84 of 535

Meter Minor Blanket
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2024 $250,000 $250,000
2025 $250,000 $250,000
2026 $250,000 $250,000
2027 $250,000 $250,000
2028 $250,000 $250,000
2029 $250,000 $250,000
Project Life Span Ongoing
Requesting Organization/Department Electric Meter Shop
Business Case Owner I Sponsor Dan Austin Paul Good
Sponsor Organization/Department Electric Operations
Phase Execution
Category Program
Driver Failed Plant &Operations
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
tnvesiment Drivers
BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
The meter minor blanket is used to charge the labor associated with new electric meter
installations in Washington and Idaho when a replacement is needed to due failed plant(meters)
that can no longer gather or communicate accurate consumption data. Failed plant could be the
result of various scenarios including, but not limited to, age, weather or environmental damage,
hardware failure.or radio communication failures.A meter must be installed as soon as possible
to accurately capture customer energy consumption data. For this reason, Avista must sustain
a continuous stock of each electric meter type and budget the required labor to install these
meters. The meter Minor Blanket Business Case is driven by tariff requirement that mandate
Avista's obligation to serve existing customer load within our franchised area.
Business Case Justification Narrative Template Version: February 2023 Page 2 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 85 of 535

Meter Minor Blanket
1.2 Discuss the major drivers of the business case.
The current or potential problem is the failure and needed replacement of meters. Ifthe meter
has failed and isn't promptly replaced we will not be able to accurately record customer usage
and the customer will not be able to see their usage data online. This data is what enables us
to charge customers accurately for their actual usage, helps customers make wise decisions
on their daily usage, and may even encourage conservation.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The work is required now because we need to be ready to respond to failed meter right away.
If we don't have the funding to provide the right resources to replace meters as they fail we will
not be able to properly measure customer's usage. If we mitigated this request it could cause
a build up of failed meters and an increase in estimated bills.This is not a benefit to the customer
or Avista.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
Having working meters in the field and being able to to accurately measure a customer usage
is in the customer and the company's best interest. This is in line with our vision by keeping our
customer's at the center of everything we do.
1.5 Supplemental Information — please descril and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
There we no specific studies that were done to initiate the creation of the business case.
Installing and replacing failed meters with new meters allows us to bill the customer accurately
per the requirement of the tarrif.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 86 of 535

Meter Minor Blanket
As depicted in the graph below we are staying fairly consistent with the number of meters/dollars
required each month to ensure all failed meters are getting replaced in a timely manner. The
three year average spend for this business case is $281 K.
ER 2073 Elec Meter Replacement Non Revenue
400,000
344,294
��300D
3L1D,000
"4.000 254,47;
2a2;
J00,000 -2ab,a46
2C2:
150,000 '�"
1 D0,000
50,0W
0
JAN FEB MAR APR MAY JUN JUL AUG 5EP OCT NOV DEC
Table 1: 3-Year average spend for Meter Minor Business case (2021-2023)
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The recommended solution is to fund this business case to enable Avista to have the right
inventory and resources to replace meters as they fail. If we do not fund this business case and
we cannot replace meters as they fail we will not meet the requirement set forth in the tariff.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 87 of 535

Meter Minor Blanket
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoid ice estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value , or evidence of spend amount to
anticipated return).2
N/A— This is a requirement of our tariff and no studies or metrics are available. However, the
benefit to our customesr is that we are getting accurate readings from their meters for their
usage and therefore billing them correctly.Additionally, they can view their actual usage on our
website to make informed decisions about their electric use.
2.3 Summarize in the table, and describe below the DIRECT offsets' or
savings (Capital and OW) that result by undertaking this investment.
Offsets Offset Description 2025 2026 , 202_7 2028 2029
Capital $ $ Is $ $
0&M $ $ $ $ S
N/A—This is a requirement of our tariff and there are no direct offsets.
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
a Indirect offsets are those items that do not directly reduce the current costs of the Company. but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 88 of 535

Meter Minor Blanket
The indirect offset we see by funding this business case is the savings of not having to send a
meter reader to each location to read the meters. If we weren't able to replace the failed meters
in a timely manner we would have to roll a truck each month to get the reads in order to bill
customers for the correct usage. On average, rolling a truck to read a meter costs about $47.
Depending on how many failed meters we needed to read each month this could end up being
a significant cost. This business case allows us to avoid those unnecessary costs.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
No reasonable alternatives exist. This is a requirement of our tariff and must be completed.
Alternative 1:
Alternative 2:
Alternative 3:
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
The only metric that's curren►ty being used to ensure and demonstrate that the investment is
being delivered upon is the tracking of our spending each month. This shows that we have the
stock and resources needed to complete this work throughout the year.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 89 of 535

Meter Minor Blanket
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
There is no end date for this business case. The work completed under this business case is used
and useful right away and transfers to plant monthly.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
The business case is reviewed and approved by our Capital Planning Group (CPG) and the
annual spend is also reviewed every three weeks by the Operation Round Table (ORT) that
is comprised of the Director of Electric Operations, various operations managers, and
business case owners.
Business Case Justification Narrative Template Version:February 2023 Page 7 of 3
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 90 of 535

Meter Minor Blanket
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the <Business Case Name> and agree with the
approach it presents. Significant changes to this will be coordinated with and approved by the
undersigned or their designated representatives.
Signature: L' Date: /"l G• (LP z�Z C/
i
Print Name: Dan Austin
Title: Manager Electric Meter Shop
Role: Business Case Owner
Signature: TAd C7000( Date: 5/16/2024
Print Name: Paul Good
Title: Director Electric Operations
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 8 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 91 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
1.0 BUSINESS CASE REQUEST - 5 YEAR PLANNING 2024
Year Requested Amount CPG Approved Amount
(Admin use only)
2025 $11,000,000
2026 $11,000,000
2027 $8,500,000
2028 $2,500,000
2029 $0
1.1 DISCUSS HOW THE ABOVE REQUESTED AMOUNT WAS CALCULATED
INCLUDING ANY CONSIDERATION OF HISTORICAL SPENDING, ESTIMATES,
CONFIDENCE LEVELS AND ESCALATION RATES.
This request includes dollars for the design, equipment, and construction of the Metro 115kV
Station Rebuild. This project is currently under construction in downtown Spokane.
Major Project Milestones
- 2025— Power Transformers (Three) Received.
- 2026— Substation Complex Complete
- 2027—Communication and Security Construction Complete.
- 2028—Final Project Closeout.
2.0 INITIAL BUSINESS CASE APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the funds request and agree with the approach
presented,and that it has been approved by the relevant governance group. Signatures are required before
funding can be considered.
Name Role Signature Date
Brian Chain BC Owner DocuSigned by: May-02-2024 1 3:49 PM PDT
Vern Malensky BC Sponsor 40 4`FFi CFI cp9i S/ May-03-2024 1 1:41 M PDT
F P&A 06C4FF5A�lBO99E4400B.... 1c
Business Case Funds Request—version 04.21.2022 Page 1 of 1
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 92 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
EXECUTIVE SUMMARY
The Metro 115kV Substation serves the urban core of downtown Spokane and has done so reliably for
almost 50 years. Customer outages in this area are counted in terms of"minutes per decade", which has
enabled our customers to implement and sustain a dense population of both commercial and residential
interests, in a zero-lot line environment. The high reliability of the Spokane urban core comes about through
the Metro Substation being partnered with the Post Street Substation to provide full redundancy to the
downtown core. This strategy is typical for most large cities. The Metro Substation typically powers half of
downtown Spokane, including the Historic Davenport Hotel, Washington Trust, Century Link, and Wells
Fargo buildings among many others.
Our customers' trust in our reliable service that depends on this station, with components that are
approaching the end of life, equipment that no longer meets present safety standards, and a unique existing
site that imposes severe operational constraints. The existing transformers are 40+ years old, are unique
and do not have spares, and use of the mobile transformer is not an option at Metro. These constraints
threaten to create significant and extended customer outages if major equipment failure for a significant
portion of the downtown area. This project will address both the equipment and site issues in the most
efficient and affordable way possible, based on the alternatives and risk analysis performed for this
substation and detailed further in this document.
The result of this project will be a flexible and reliable station that fulfills needs in multiple operating divisions.
The new substation will provide safer equipment, necessary redundancy, increased capacity, and a design
that enables a longer station lifespan where individual pieces of equipment can be safely serviced.
Additionally, the new substation would include two additional distribution feeders that will provide needed
capacity and a redundant path for the hospital district and lower South Hill. A rebuilt Metro Substation will
provide the reliability that our customers expect.
The total project cost is estimated at$73 Million.The selected option for the Metro 115kV Substation rebuild
includes four 115kV lines, ring bus configuration with 6 breakers, two 30 MVA power transformers, 9
network feeders and 2 distribution feeders, 8 air core reactors with enclosures, and switchgear in its own
enclosure. Also included in the substation cost is an architectural wall enclosure to provide security around
the site, an underground cable vault for the large amount of network cables, a control and battery enclosure
to house the control panels, and multiple underground duct banks that provide pathways in/out of the site
for distribution, network, and transmission. The location of the new Metro substation in the City's downtown
core requires the surrounding wall enclosure to adhere to a design review and permitting process that also
includes architectural, landscaping, and other requirements to meet the downtown aesthetic. The smaller
footprint of this site requires unique layouts and designs to accommodate all of the structures and
equipment that are needed. Substantial cost increases in equipment and materials in the past few years
have affected the overall project budget and long-lead time equipment has had a negative impact on the
timeline resulting in a longer construction period as well.
The risks associated with the existing Metro substation are significant and could include extended outages
for half of the downtown area that is fed via Metro and Post St. The mobile substation is not an option at
this location to back up the site and keep the downtown area energized due to space constraints and
technical incompatibilities. Beyond a temporary tie-line solution in the event of a transformer outage, there
is no other option to maintain critical service to our downtown customers. Safety risks include significant
fire risks to adjacent structures that are within 50 feet of the oil-filled equipment.Additionally,the switchgear
which is not arc-flash rated puts personnel at risk as they must be inside the front of the cubicle to manually
switch it. Due to the long lead times of major equipment(3 years for transformers)and the length of time to
construct such a large and unique substation, the cost of the project is substantial. The longer the project
takes to start and complete construction and energize, the higher the overall project cost due to
compounding construction costs, all while there is an ongoing increase in the potential risk of equipment
failure at the existing station.
The Metro rebuild project was scoped in 2020 and a Project Charter was started and approved in 2021.
This effort included analysis and assessments of operational risks and challenges, mitigation options and
Business Case Justification Narrative Template Version: February 2024 Page 1 of 21
Exhibit No. 10
Case Nos.AW-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 93 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
costs for multiple rebuild, brownfield, and greenfield scenarios, and project estimation and milestones.
These documents were developed by engineering teams, reviewed and approved by engineering
managers and the Director. Continued monitoring and controlling, and reporting of the project scope,
schedule and budget occur on a monthly basis with the department managers and Director. Any proposed
changes to the project are managed and tracked through the change management process.
Major Project Milestones
- 2025— Power Transformers (Three) Received.
- 2026—Substation Complex Complete
- 2027—Communication and Security Construction Complete.
- 2028—Final Project Closeout.
VERSION HISTORY
Version Author Description Date
1.0 Karen Kusel/ Final Draft of Business Case 3/1/2023
Crystal Holmes
2.0 Karen Kusel/ Annual Update of Business Case 512024
Brian Chain
os
BCRT I Steve Carrozzo I Has been reviewed by BCRT and meets necessary requirements
Business Case Justification Narrative Template Version: February 2024 Page 2 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 94 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
GENERAL INFORMATION
YEAR SPEND AMOUNT($) TRANSFER TO PLANT ($)
ACTUALS AND EXPECTED ACTUALS AND EXPECTED
2018 $2,850,000 $2,850,000
2019 $3,300
2020 $200,000
2021 $1,600,000
2022 $3,610,000
2023 $12,700,000
2024 $18,800,000
2025 $11,000,000 $3,200,000
2026 $11,000,000 $55,800,000
2027 $8,500,000 $6,000,000
2028 $2,500,000 $3,500,000
2029 $0 $0
Project Life Span 11 years(2018— 2028)
Requesting Organization/Department M08/Substation Engineering
Business Case Owner Sponsor Brian Chain Vern Malensky
Sponsor Organization/Department Energy Delivery
Phase Execution
Category Project
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
Transmission Related Issues
- Metro-Post St MTR-PST and Third & Hatch-Post St 3HT-PST Transmission Line Cables
in Shared Duct Line/Manholes (3HT: Third & Hatch, PST: Post Street)
Issue: Between Post Street and Metro substations the latter being where the Third &
Hatch-Post St 3HT-PST line transitions to underground cable)the two 115 kV lines
share the same duct bank and --10 manholes/splice vaults. The cables are exposed in
this area to a double circuit failure due to single circuit problems (e.g., splice failure,
cable fault, manhole fire).
Business Case Justification Narrative Template Version: February 2024 Page 3 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 95 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
Risk: The shared duct bank path is susceptible to a single cause of failure (e.g., dig-in)
that affects both lines, similar to a double circuit 115 kV overhead design. Outage work
affects both lines in the same way.
- Tunnel Design Causes Transmission Outages for Unrelated Work
Issue: Immediately south of the existing Metro Substation, in the Steam Plant alley, is
an approximately100' long "tunnel"that contains many types of cable including the 115
kV 3HT-PST Third & Hatch-Post St line racked on the tunnel walls. Other cables are
various Avista and joint use communications cables, secondary cabling that is part of
the Downtown Network and 13 kV Metro-Post St MTR-PST tie line cabling—6 1500
kCM copper EPR cables, critical to backup operation of Downtown in the event of an
equipment failure at either Metro or Post Street. Safe work practices from the industry
are in use at Avista; these dictate that crews and engineers are not able to enter the
tunnel (or any 115 kV underground facility)with the 115 kV energized. This requirement
has led to the need to take the 115 kV transmission out of service, making the Bulk
Electrical System (BES) less reliable for unrelated work.
Risk: The many shared uses of the Metro tunnel drive outages on the 115 kV 3HT-PST
line that pose operational challenges and lessen the overall reliability of the Bulk
Electric System.
- 115 kV Line Outages Required for Other Various Unrelated Work
Issue: Metro-Sunset 115 kV MTR-SUN transmission line exits the station and goes over
specialized structures on top of the Steam Plant building.
With the recent Steam Plant restaurant modifications/upgrades, kitchen vent fan(s)
have been installed underneath this line and it is assumed we will need some sort of
on-going future maintenance, which will require an outage to this circuit.
Given that Steam Plant workers and maintenance crews are not familiar with the
procedures required by WECC and NERC with regard to the BES, often outages to this
line are requested with only 1-2 weeks of planned Steam Plant work. Avista's standard
requires at least 21 days of notice for non-emergency outages.
Due to the limited conductor clearance to the Steam Plant roof, there is a fence
installed prohibiting access underneath this line. Controlling who has access is ongoing;
non- qualified personnel have had access.
Due to clearances, maintenance work to the exterior of adjacent buildings requires a
safety watch and/or line outage. This is namely the building south of the OH section of
PST-3HT at Metro.
Double 115 kV line outages are required for almost all vault inspection/maintenance
work of underground sections of both PST-3HT and MTR-PST. There are around ten
transmission vaults that are shared between these two lines, mostly on Lincoln,
between Post St and Metro. One way we have been operating around these conditions
is by taking line outages at night for O&M work to be performed on overtime. Double
line outages during the night are 2 to 2.5 times the cost of single line outages that can
be performed during the day. This is due to the doubled labor cost per hour plus the
need to have multiple crews and additional switchmen for the duration of the outage for
multiple switching operations throughout the night.
Business Case Justification Narrative Template Version: February 2024 Page 4 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 96 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
Risk: Unrelated non-utility work causes outages on the 115 kV 3HT-PST line that pose
operational challenges and lessen the overall reliability of the BES. Non-qualified
workers have possible access to transmission line areas that do not have compliant
NESC clearances.
Nearby Overhead Transmission Lines— General Risk Assessment
Issues: The Metro-Sunset transmission MTR-SUN line was built in 1976 (47 years old)
and north of 1-90 there are four original structures (excluding the lattice steel structures
on the Steam Plant roof—a building that Avista no longer owns).
The structures are along Lincoln St., which is one of the busiest north-south
thoroughfares in Spokane. Several of these structures are on the corners of streets and
alleys, putting them in prime locations for vehicle impacts.
The two tangent structures are class#3 wood poles, and do not meet NESC code with
regards to strength requirements.
The pole on the corner of Steam Plant Alley is guyed in two locations. One guy is
across Lincoln St. and is secured into the side of a brick building, and the other is guyed
to the north, approximately 175' over the entrance to the Steam Plant, into a BNSF
railroad trestle.
Current structures in the vicinity, including steel lattice structures, would not be suitable
for a conductor upgrade to 795 ACSS, a higher capacity and current Avista standard
conductor than existing, due to the existing structures not meeting NESC strength
requirements.
Avista no longer owns this building so any access for inspections or maintenance by
Avista must be coordinated with the current owners.
Due to the Lattice Steel Structure on the roof of the Steam Plant, there have been many
necessary outages at the request of the owners to complete work and maintenance on
the building. These include roof repair and maintenance, restaurant cooking vents
install and servicing, air conditioning repairs and maintenance, and other structural
maintenance.
The overhead section of the Post St-Third and Hatch PST-3HT transmission line was
built in 1987 (36 years old) and consists of three self-supporting steel structures and
one wood structure, north of 1-90.
The current configuration for transitioning from OH to UG at Metro does not lend itself
well to a mobile sub installation if one was required for an extended time to make
repairs at the current location.
Clearance to the building south of Metro does not allow for exterior maintenance
without an outage.
A large steel pole in the middle of the sidewalk along Post St, approximately 6 inches
from the curb.
Risk: Various out of date and non-standard transmission structures provide an
increased potential for failure (car-hit poles, structural failure, corrosion, guy anchor
failures or breaks). This could result in line faults, reduced reliability to the BES, and
Business Case Justification Narrative Template Version: February 2024 Page 5 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 97 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
public safety hazards. Approximately 1-2 poles per year are hit/damaged in the
downtown area.
115 kV Source Reliability(Recent Transmission Trip)
Issue: Transmission service to this station is redundant, but compared to other two-line
stations and has had issues in the past with one side being underground and the other
being overhead. For example, in 2018, a line tripped in the area, when a contractor dug
up a guy wire which caused the wire to snap, resulting in the 115 kV Metro-Sunset 115
kV transmission MTR-SUN line and College &Walnut Feeder 12F4 (an overhead radial
feeder in the area)to fault together.
Both the 115 kV line and the College &Walnut feeder tripped out. The other source to
Metro, the 115 kV Metro-Post St line, also tripped. Due to the lack of event recording
equipment (old microprocessor relays) at Metro, the line could not be closed back to
service and resulted in an extended outage. The lack of necessary information to
determine what had occurred eliminated any confidence to re-energize.
With both 115kV source lines tripped, Metro was momentarily without a source for half
of Downtown. The relaying for the underground cable line between Metro and Post St
does not allow reclosing, so this line stayed out of service. Metro at this point was a
radial feed.
Fortunately, the line held once energized. Had the line needed to be repaired, or
replaced, there would have been a substantial delay as Avista does not stock the parts,
nor do we have the expertise in-house to do the work. While Metro was solely sourced
by one 115kV line for about a week and a half, it could have been months, if repairs had
been necessary. Note that the replacement of the oil-filled cabling with newer cross-
linked polyethylene (XLPE) cabling does not change the fact that our most experienced
in-house distribution cablemen do not have the training, experience, or equipment
necessary to install transmission splices, even on XLPE. We would have to bring in
external contractor resources and also find replacement cables that are significant long
lead time materials.
Risk: Single transmission line trips can, and have cascaded, causing a full Metro
Substation outage. Cable transmission line trips cannot be repaired in-house and leave
Metro susceptible to an extended sustained outage for an N-1 trip during the
subsequent repair time, could extend to months. Having two transmission lines
(sources) creates redundancy which reduces this risk significantly.
Distribution Related Issues
- Racking Breakers for Feeder Outages
Issue: The switchgear at Metro Substation is some of the most heavily utilized on the
system, from a feeder outage standpoint. This is because, due to the secondary
network, it is inconsequential to customers for a feeder to be out of service. All primary
conductors are underground cabling, which cannot be worked on while energized.
Therefore, in the Downtown Network, Hot Line Holds are not used at all. Instead, if any
work is necessary on the feeder, the feeder is completely taken out of service. This
results in more planned switchgear breaker operations as well as more instances of
breakers being racked in and out, as compared to any other distribution station on the
system, except for Post Street, the other Downtown Network substation.
Business Case Justification Narrative Template Version: February 2024 Page 6 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 98 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
Remote racking is available at Post Street, but not at Metro. Instead, the older
switchgear is either jacked into place using a portable jacking motor, or in some cases,
ratcheted horizontally into the energized 13 kV bus, manually. In order to do either
requires a cableman to be physically inside the front of the switchgear cubicle.
While this operation is safe assuming everything goes correctly, it is not necessarily a
design that is a good idea to "run to failure" as many failure scenarios involve severe
employee injury or death due to arc flash. When Metro's switchgear was procured, arc
flash was not an industry-recognized concern.
Risk: Arc flash during racking operations will have severe consequences to cablemen
who, by design, are directly in the line of fire.
- Three Metro East Feeder Exits Need Upgraded for Thermal Reasons
Issue: The present Metro East feeder exit cables all show at or over their capacity limits
in Powerworld, a power flow system modeling software, under a contingency feeder trip
analysis for both summer and winter loading.
The Powerworld modeling provides data in the figure below. The worst cable capacity
limits is Feeder#13636, which peaks at around 96%. Feeder#13637 is around 93%.
Feeder#13638 lags and is "only" hitting about 87% but should be upgraded at the
same time. Typically, over 80% is the threshold for starting to look at options to mitigate
thermal issues and this site is obviously overdue.
METR0115 METROSUB
ME Secondai7yl 40 400
METRO 1.00 pu 1.04 pu
MESUBSTATION
115.00 KV 13.79 KV
PSE rims
12970 kW � w
3799 kvar ��
MH61
4101
1.02 u
Risk: Failure of a feeder exit cable due to being run over capacity would result in an
outage to a quarter of downtown. Cable overloads occur under contingency (when one
of the other feeders to that quadrant are already out of service) so the second feeder
trip triggers the Automatic Feeder Reduction (AFR) scheme which dumps the remaining
feeder in the network in order to prevent further cascading failure in both the primary
and secondary.
Cable replacement and commissioning would take days to weeks depending on duct
bank damage and whether the old cable was able to be removed. During that time, the
Business Case Justification Narrative Template Version: February 2024 Page 7 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 99 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
outage would continue as no options to backfeed primary exist within the Downtown
Network.
Lower South Hill Radial Feeder Reliability
Issue: The existing feeders that serve the lower south hill and the hospital district have
experienced several extended outages. These feeders have exposure due to both
length (College &Walnut 121`4 for example) and other special circumstances
(transmission underbuilds, river crossings). Between 2018-2020, there were at least 2
to 3 outages on the College &Walnut 12F4 feeder that directly impacted the MultiCare
Deaconess Hospital requiring them to go on backup generators. When on backup
generators, they cannot perform any new surgeries.
Risk: Multiple recent outages in this area have caused many customer issues including
cancellation of surgeries at Deaconess. This is a significant public risk, and the
hospitals are critical customers. Work arounds in the past have included reconfiguring
the feeders to take on the hospital load but this raises the load on the entire system and
depending upon the season (hot or cold conditions/loads) it may be difficult or not
possible to resolve.
Substation Related Issues
- Transformer/Low Side Fault Clearing
Issue: The existing Metro substation is presently only one of three stations on Avista's
entire system that requires a 115 kV bus trip in order to clear a transformer or
transformer low-side fault. Due to the lack of circuit switchers and the lack of space to
add them. Which in turn is due to the station being built on a site that is entirely too
small for the intended purposes. The existing scheme will dump the 115 kV bus using
the transmission breakers to both Sunset and Post St transmission lines. With the bus
and the southern half of Downtown de-energized, an air switch must be opened, which
is supposed to be done automatically. However, it should be noted that these
transformers disconnect switches have rarely been maintained due to their electrical
location; operational success under real conditions is not guaranteed and has proven to
be an issue with other 115 kV transformer disconnect switches.
Risk: If the air switches operate properly and automatically, then the load in the station
is restored after only a momentary outage to half of Downtown. If they do not operate,
then the outage has the potential to grow longer while a crew is called to the site in
order to force the switch open.
- Fire Threat to Nearby Buildings
Issue: Part of the switchgear at Metro is inside an alcove/garage underneath a section
of the Steam Plant building to the west of the station. Avista no longer owns the Steam
Plant. The Steam Plant is constructed of brick and steel with no added fireproofing.
Required distancing between oil-filled equipment and a "possibly-manned" panel house
in any of our stations is 50 feet, per IEEE 979. This is based on industry standards.
When oil-filled equipment must be closer to panel houses than 50 feet, a firewall is
required to be placed in the gap. There is no firewall, nor space to install one.
Business Case Justification Narrative Template Version: February 2024 Page 8 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 100 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
Risk: While the panel house at Metro was constructed within 50 feet of an oil filled 115
kV circuit breaker, the larger concern is that both transformers and both 115 kV circuit
breakers (oil-filled)are within 40 feet of the Steam Plant building itself. Again, there is
no fireproofing. The Washington Trust Data Building to the south is also only--30 feet
away. In the event of a failure to trip of any protective functionality inside the station,
there is a significant risk of a catastrophic commercial building fire potentially putting
property and lives in danger.
Batteries at the Existing Station are Undersized
Issue: Batteries at the existing Metro are undersized given both the importance of the
station (transmission breakers, six feeders of urban load) and the amount of equipment
in the station. The station's batteries are presently sized at 100 amp-hours (Ah).
Stations), 48V DC and would only last a few hours. A 125V DC system is now the
standard for transmission substations, providing 8-12 hours of backup per IEEE 485.
Only 4 Avista substations have smaller batteries than Metro.
Risk: Batteries that are too small do not become an issue until a very critical moment
(such as an extended station service outage or battery charger failure). Avista has been
lucky to avoid a severe consequence in these scenarios, as can be experienced if a
battery runs down in such a situation. Loss of battery backup results in a station service
failure, loss of battery charger, breakers cannot trip or close on their own, and the
station loses operability. System Operations is well aware of the criticality of station
batteries.
The worst-case scenario at Metro could be a failed charger with a missed alarm in
System Operations as there is no battery voltage indication to SCADA at Metro, due
primarily to the lack of microprocessor relaying and modern SCADA at Metro. Without
this indication to start an immediate crew callout, the undersized battery would run
down very quickly (within hours, not days) and limit the amount of time for the missed
alarm to be caught.
Note also, if a feeder or transmission breaker trip had been required during this time,
the battery is unlikely to support the trip, which would result in the breaker failing to
operate. In turn this could create the same kind of catastrophic effect that Grant County
Public Utility District(GCPUD)saw in their Ephrata Substation fire, after the battery was
unavailable to support a DC-powered breaker trip. The difference at Metro is that the
smaller site, and lack of built-in fire protection for surrounding buildings and railroad,
would threaten much larger consequences than just a "simple" substation fire.
Size of Existing Site is Insufficient
Issue: The chart below shows a comparison of stations by a metric of"square feet per
circuit". Circuit in this case means either a transmission line terminating on a breaker, a
distribution line, or built-in space for a future distribution line. Substation Engineering
recommended several of the known "small" stations to compare Metro against. These
included other similar stations with 115 kV breakers and/or switchgear, as well as a
"tiny" station (O'Gara).
Business Case Justification Narrative Template Version: February 2024 Page 9 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 101 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
0 Square Feet/Circuit
40000 ©Total Square Feet In Station 9 ckts
35000
30000 9 ckts 6 ckts
25000 4 ckts
20000
15000 I
10000 3 ckts
5000
0
O'Gara Metro Chester Northeast Pound CDA 15th
Lane
'Metro's circuit(ckt)count does not take into account the 3HT-PST line.
which transitions to underground within the existing Metro site
Risk: This metric does not necessarily speak to the specific challenges faced at the
existing site, but it does provide context generally as to why Metro is unique, and why it
seems to present so many of these specific challenges.
Note that"size per circuit"was not chosen as a metric simply because of the results it
produced. If you compare, for example, the simple overall square footage of the existing
Metro site to every other transmission station on Avista's system, it is the second
smallest at—12,000 square feet despite serving significantly more load.
It could also be noted that many of the stations that face significant space challenges
inside the fence have mitigating factors that allow emergency operations to take place.
For example, there typically options to install the mobile substation, replace 115 kV
breakers, or crane in a transformer, but with the challenges at Metro due to both the
surrounding environment and the equipment inside, these mitigations are not possible.
AFR Relaying Not Controllable by Feeder
Issue: The unique secondary network that is fed from the Downtown Network feeders
out of the existing Metro Substation has associated unique relaying —an Automatic
Feeder Reduction or AFR scheme. AFR is intended to protect both the primary and
secondary cabling in the Downtown Network from overloads in the event of more than
one feeder being out of service.
Feeders can be"out of service" in one of two ways: the primary breaker can be opened
in the substation, or all network protectors downstream can be opened. As part of a
normal primary clearance switching order, both situations must occur.
The AFR scheme is set up such that, if the primary breaker is open, then the relaying is
automatically aware of the inability of that particular feeder to serve load (leaving the
remaining feeders in that network as the sole providers of energy). However, unlike at
Post Street, the AFR cannot be manually indicated to, in the event that network
protectors downstream are open and not serving load.
Business Case Justification Narrative Template Version: February 2024 Page 10 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 102 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
Risk: Metro's AFR configuration means that, at least once during every switching order,
there are moments to sometimes hours (depending on needs of the order and crew
availability)when tens of thousands of feet of cabling is exposed to a cascading
overload event, if a second feeder is tripped for a fault. There are around 20 of these
orders performed out of Metro every year.
- The "Pigeon Problem"
Issue: The Metro Substation is in a location that lends to having a lot of pigeons around.
The pigeons defecate all over the substation.
Risk: This is not only a health hazard for our personnel but an electrical hazard as well.
The droppings can cause unplanned outages due to insulator flashovers. To clean the
station there has to be an entire 115 kV bus outage, which is extremely difficult to
schedule.
- 115 kV PT Issues
Issue: On 4/2/2020, it was identified that the B phase 115 kV Bus PT was leaking. The
serviceman tried to use the oil level gauge to determine the oil level, which would have
helped with determining the urgency behind the replacement. Unfortunately, the gauge
was not legible. That is not uncommon for old equipment. The PTs were manufactured
in 1976.
Risk: The failure mode for PT's is quite destructive and has led to flying glass and oil
fires. To replace the PT's, there has to be a whole 115 kV Bus outage, which is
extremely difficult to schedule. The outage interrupts the continuity of the 115 kV path
from Third & Hatch to Sunset. It also requires two simultaneous transformer outages at
Metro. At any other site this would be a mandatory mobile transformer installation due
to the reduction in distribution reliability in the area but is not possible at Metro.
- Recent LTC Issues Found
Issue: In May of 2018, Avista crews conducted routine transformer testing on both
Transformer#1 and Transformer#2. The crew found an issue with Transformer#2
Load Tap Changer(LTC). They found that when the LTC is tapped in the lower
direction, the tap changer may not complete a full operation.
Risk: Failure of an LTC would require the connected transformer to be taken out of
service until fixed or replaced. This would result in an increasing load on remaining
feeders and increased potential for negative cascading effect on the system.
- Avista Does Not Carry Spare LTC or Throat-connected Transformers
Issue: The repair on Transformer#2 LTC brought up the concern about not having a
spare transformer with an LTC.
Business Case Justification Narrative Template Version: February 2024 Page 11 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 103 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
Risk: Installing a transformer without an LTC would cause the distribution to be
unregulated, which is not acceptable. There is no proven option available to install
voltage regulators at this station. Space to physically place them, available points in
which to connect them in series, and electronic controllers that need to work in an
abnormal paralleled fashion are all issues that would have to be solved. There is no
way to quickly repair or mitigate this given the current facility.
Without the availability of a spare unit, one must be ordered. Lead times for
transformers have varied but are currently around 3 years. In the meantime, while the
order was being manufactured, delivered and installed, the N-1 case (e.g., another
transformer or LTC or tie line failure)would leave half of downtown without power and
no way to mitigate.
Relaying Archaic: Last 115 kV Blocking Schemes on Avista's System
Issue: Transmission line relaying at Metro is electromechanical based (primarily KID
relays). The fleet is on average over 40 years old, is past its usefulness as it is archaic
equipment and provides no operational visibility or records for event analysis after a
system disturbance. Additionally, the Metro-Sunset line is the last transmission line in
Avista's system to use a carrier blocking scheme. Newer schemes communicate with
the system as to faults or status of other equipment or faults on the system. While
dependable, blocking schemes are less secure in nature.
Risk: Relay failures may not be able to be responded to in a timely manner. Spares are
limited to those which have been retired from other stations. Expertise around setting
KID relays has left the company. The last carrier blocking scheme is a threat to mis-
operate, resulting in unnecessary transmission outages, decreased reliability, and
FERC PRC-004 reporting.
1.2 Discuss the major drivers of the business case.
The Metro 115kV Station Rebuild project fits firmly within the Asset Condition and Customer
Service Quality and Reliability drivers. Put simply, this project replaces old equipment with new
equipment, which resets the curve with regard to asset life cycles, while also decreasing the
likelihood of catastrophic equipment failures and resultant customer outages over the next 50
years.
However, elements of other investment drivers also apply. The end product of this project will
allow construction and operations to occur without violating OSHA-driven circuit grounding
requirements (one example of several Compliance drivers). It will also have upgraded feeder
exits in the Metro East quadrant,which are presently at overload limits and need to be upgraded
regardless. The transmission configuration allows more operational flexibility for 115 kV lines on
both the South Hill and West Plains (Performance & Capacity). Finally, the completion of this
project avoids a very costly and slow response to major equipment failures (any transformers,
LTC's, switchgear, 115 kV breakers) which would likely end up translating into customer
outages, unplanned Failed Plant expenses and a negative public image for Avista.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The risks associated with the existing Metro substation are significant and could include
extended outages for half of the downtown area that is fed via Metro and Post St. The mobile
Business Case Justification Narrative Template Version: February 2024 Page 12 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 104 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
substation is not an option at this location to stand up the site and keep the downtown area
energized due to space constraints and technical incompatibilities. Beyond a temporary tie-line
solution in the event of a transformer outage, there is no other option to maintain critical service
to our downtown customers. Safety risks include significant fire risks to adjacent structures and
occupants that are within 50 feet of the oil-filled equipment. Additionally, the switchgear which
is not arc-flash rated puts personnel at risk as they must be inside the front of the cubicle to
manually switch it. The risks of not moving forward with the new site and substation include the
latter but also the negative public impact of not being able to provide power to the heart of the
City for an undetermined amount of time. Due to the long lead times of major equipment(3 years
for transformers) and the length of time to construct such a large and unique substation, the
cost of the project is substantial. The longer the project takes to start and complete construction
and energize, the higher the overall project cost, and there is an increase in the potential risk of
older equipment failure.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
The Metro Substation project is the epitome of our Vision: "Better Energy for Life". We already
serve the downtown core with the current Metro substation, but we want to do it better by
supplying electricity more safely, more reliably, and more responsibly. We aim to accomplish
this by addressing safety and reliability issues that the current Metro Substation has and do it in
a responsible way by engaging stakeholders well.
The new Metro Substation will use some of the latest technology in substation construction. As
such, it aligns with our mission. Metro is an innovative energy solution that will improve our
customers' lives safely, responsibly and affordably. As stated before, the new Metro Substation
will address a number of safety and reliability issues that the old Metro Substation has. We
intend to do this responsibly and affordably. Nothing is planned for the project that isn't a request
from a stakeholder (City of Spokane, for example) or isn't necessary from an operational or
safety requirement.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
Please refer to the Project Initiation Charter document that includes the following memos in
addition to the sections above:
- Metro — Operational Risks & Challenges of Existing Configuration: Categorizes and
summarizes the risks and challenges posed by the existing configuration of our electrical system
in and around Metro Substation.
- Metro — Mitigation Options & Costs: Categorizes and summarizes mitigation options and
their associated costs for operational issues identified at Metro Substation.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2024 Page 13 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 105 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
115kV Metro Substation—Rebuild Options: History of the Metro Substation and its relation
to the Spokane Central Steam Heat Plant, summarizes issues with each Equipment Type in the
Metro Substation (as of 2009).
- Metro Station System Impact Study by System Planning: Technical analysis of the Metro
Substation rebuilds impact to the transmission system in the region.
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
In the table below,the project options and mitigations were identified and evaluated for cost,
feasibility,and risk early in the Initiation phase and documented in the Project Charter.These
options were re- evaluated and updated in Fall 2022. As detailed in the table below, the
Rebuild on New Site was selected as the best, most cost-effective and feasible option to
proceed with. Further detailed documentation of the options is included in the Project Charter
and supporting documents. Based on the Project Initiation Charter, it is recommended that
the station be rebuilt on new property approximately two blocks to the south. The rebuilt
station will utilize an open-air transmission bus design with metal-clad switchgear on the
distribution side. Both transmission and distribution busses will be arranged in a ring
configuration.
The rebuild of Metro on a new site mitigates nearly all concerns and risks associated with the
existing installation. Reference the table below and in Section 2.5 for alternative costs, risks
and risk reduction. The rebuild also provides a better operating configuration that will result
in much lower impacts as failures are (inevitably) observed over the life of the installation.
For example, a 115 kV breaker failure at the new Metro will not result in a full station outage.
In fact, depending on the exact nature of the failure, it may not result in any outage at all. At
the old station, half of Downtown could be out of power.
O&M costs associated with the new station would be the lowest observed relative to all options.
Options Capital Cost Estimate Class Reduced
Risk
SELECTED: Rebuild on New Site $73M Class 3 93%
1) Status Quo $0 - 0%
2) Selective Mitigation at Existing Site $12M Class 4 High Risk 44%
(Years 1-6)
3) Rebuild on New Site(GIS) $97M Class 5 93%
4) New Transmission Site, Rebuilt $85M Class 5 91%
Distribution Site Not Feasible
5) Downtown West& Downtown East $103M Class 5 82%
Not Feasible
Class 5: -20% to+100% Strategic Planning & Concept Level
Class 4:-15%to+50% Order-of-Magnitude, Feasibility Study
Business Case Justification Narrative Template Version: February 2024 Page 14 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 106 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
Class 3:-10%to+30% Budgetary, Semi-Detailed
2.2 Describe and provide reference to CIRRARR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
In 2019 and 2020 multiple assessments and analysis were performed as part of the evaluation
of the existing substation, scoping for the new substation and preparations for the new Metro
Substation Project Charter that was approved in 2021. Refer to section 1.5 for a list of the
reference documents. During these assessments, several options and alternate locations were
evaluated for cost,risk and risk reduction,reliability,redundancy,capacity,and how they improve
or mitigate current issues and risks for the Downtown core and our customers(Reference sections
2.1, 2.5, and 2.6). The summary of the information, assessments, analysis, and documentation
provided in and referenced within this document were all considered when preparing this capital
request.
IRR Annual Revenue
Requirement
Base Case Rebuild on New Site 7.90% $5,613,603
Alt 1 - Status Quo 6.38% $5,894,718
Alt 2 - Selective Mitigation at Existing Site 4.82% $7,251,968
Alt 3 - Rebuild on New Site (GIS) 4.03% $8,132,620
Alt 4- New Transmission Site, Rebuilt Distribution Site 4.96% $7,118,115
Alt 5 - Downtown West and Downtown East 3.64% $8,639,873
2.3 Summarize in the table and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
There are no direct O&M savings if the Metro Substation is rebuilt. Any savings are offset by
increased costs to inspect, test, and maintain a much larger station. Annual O&M costs for a
distribution substation is approximately$30,000.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $0 I $0 $0 $0 $0
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2024 Page 15 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 107 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
00 1 $0 $0 $0 $0 $0
2.4 Summarize in the table and describe below the INDIRECT offsets4
(Capital and OW) that result by undertaking this investment.
Asset condition issues are present in several types of equipment at the current Metro substation
(see Section 1.1 Substation Related Issues for details). Reliability and safety concerns are also
present. These three types of issues cause the greatest number of Servicemen callouts. If the
substation rebuild is completed, Servicemen will spend less time maintaining and `limping along'
equipment. They will complete the work more efficiently since the safety issues (i.e., switchgear
arc flash) are not present and do not have to planned for(i.e., Arc Flash suits are not required).
The savings could be as much as$180,000 per year in additional Serviceman labor(salary plus
overhead costs)system wide.
Offsets Offset 2025 2026 2027 2028 2029
Description
Asset Condition
based $10,000 $10,000 $10,000 $10,000 $10,000
Capital equipment (Average) (Average) (Average) (Average) (Average)
changeouts
Loaded Cost of
One Additional
O&M Serviceman to $180,000 $180,000 $180,000 $180,000 $180,000
help cover
higher call out
rates.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternative 1:
Status Quo/no Change. Capital Costs No capital costs in years 1 to 9, complete rebuild starting
in year 10.
Risk: Small site, feeders are beyond thermal capacity, significant fire risk to adjacent buildings,
breakers are arc flash risk during racking, no spare transformer or mobile option. failures may
result in outages for half of downtown for unknown duration. There is no reduction in risk.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2024 Page 16 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 108 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
Alternative 2:
Selective Mitigation at Existing Site — Upgrade overloaded feeder exits, install arc flash
prevention relaying, install larger battery bank, install newer AFR relays, and purchase spare
transformer. Capital Costs-$12M in years 1 and 6 with a complete rebuild assumed in year 10.
Risk: Small site, significant fire risk to adjacent buildings, failures may result in outages for half
of downtown for unknown duration.
Alternative 3:
Rebuild on New Site (GIS) — Installing Gas Insulated Switchgear would mean the need for
contract labor to install the equipment and this equipment requires a high cost to install. Capital
Cost- $97M.
Risk: Mitigates almost all risks but comes with a higher cost for specialty equipment and
installation.
Alternative 4:
New Transmission Site, Rebuilt Distribution Site—Brownfield rebuild of Distribution and a need
for a link between the old and new site makes this option complicated and expensive. Capital
Cost- $85M.
Risk: Mitigates some issues but is costly because the existing site would still have to be rebuilt
and upgraded with newer distribution equipment and still is a fire hazard to the adjacent building.
Alternative 5:
Downtown West & Downtown East — (Additional options considered in Fall 2022): Downtown
West is needed to off-load College and Walnut substation. Downtown East does not have
property. Capital Cost- $103M.
Risk: Mitigates some risks but doesn't offload the existing Metro loads nor fully support
downtown. Both sites would have to be developed in order to support the downtown area.These
sites are identified as additional needs for other upcoming customer loads and future
expansions. Both locations would require significant relocation of underground distribution and
transmission lines throughout the downtown streets.
Business Case Justification Narrative Template Version: February 2024 Page 17 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 109 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
Over the life of this station, Spokane and the downtown loads have grown. OSHA-driven
work practices for electrical workers have evolved, as have the IEEE standards for arc flash
and distances between equipment and structures. Avista's tolerance for risk has changed.
The existing station falls short of serving today's load in a safe and reliable manner and will
only get worse over time. Reliability for our most critical downtown customers, including the
hospitals, is essential. There are also unique possibilities for catastrophic failure at this site,
with little or no good options for operational mitigations including the inability to use a mobile
transformer. Potential equipment failures could result in outages to half of the downtown
core for an undetermined amount of time, as well as fire risks to adjacent buildings and
occupants. The rebuild of the Metro substation would provide the reliability and redundancy
necessary to mitigate outage concerns.The new equipment would meet the IEEE standards
for arc flash and the distances between structures and equipment would be resolved on this
larger site. Monthly monitoring and controlling of the project budgets, schedules, and scope
will be performed by the team with further discussions or analysis as needed throughout the
project duration.
Transmission-Related Issues
• 2028-2033 No outages affecting both MTR-PST and 3HT-PST lines because of
the shared duct bank.
• 2028-2033 No outages on the 3HT-PST line from shared use of the Metro tunnel
• 2028-2033 No outages on the 3HT-PST line from non-utility workers having
access in an area without NESC clearances.
• 2028-2033 No outages on the MTR-SUN line's four original structures north of
1-90
• 2028-2033 No outages on the PST-3HT line's three self-supporting steel and
one wood structure north of 1-90
• 2028-2033 No single transmission line trips cause a full Metro Substation
outage.
Distribution-Related Issues
• 2028-2033 No deaths from arc flash racking bycablemen
• 2028-2033 No failures of feeder exit cable due to it being run over capacity.
• 2028-2033 No canceling of surgeries at Deaconess due to College &Walnut
feeder outages
Substation-Related Issues
• 2028-2033 No non-momentary outages at the Metro Substation because the air
switches did not operate properly.
• 2028-2033 No fire started at adjacent buildings to Metro Substation
Business Case Justification Narrative Template Version: February 2024 Page 18 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 110 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
• 2028-2033 No battery voltage issues not reported through SCADA.
• 2028-2033 No cascading cabling overload events during switching orders.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
This project is planned for construction over multiple years. The bulk of the project is planned to
transfer to plant once construction of the substation is complete.
YEAR TYPE OF WORK
2018 Property Parcels
2019
2020 Engineering Design Begins
2021 Engineering Design, Building Demolition
2022 Engineering Design, Property Grading, Major
Equipment Payments
2023 Engineering Design, Major Equipment
Payments, Wall Construction
2024 Wall and Substation Construction
2025 Auto Transformer Received, Construction
Continues
2026 Substation Construction Complete
2027 Communication and Security Construction
Complete
2028 Final Equipment Testing and Commissioning
Complete, As-Built Drawings Updated
This project started in 2020 with the completion of studies and analysis and the signing of the
Project Charter in early 2021. Design began and will continue through 2023. Construction of
the enclosure wall, cable vault, control and battery enclosure, and duct banks is to occur in
2023 and 2024. Avista crews will perform build out of the substation into 2026 with
anticipated completion in late 2026 and into 2027 for cutovers and final energizations.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
Brian Chain — Business Case Owner/Manager, Substation Engineering
Brian Vandenburg— Manager, Engineering Projects
Mike Bosshardt —Senior Engineer, Downtown Network
Business Case Justification Narrative Template Version: February 2024 Page 19 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 111 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
Brian Parsons—Senior Engineer, Substation Civil/Structural Engineer
Patrick Henderson—Senior Engineer, Substation Electrical Engineer
Bryan Hyde—Senior Engineer, Transmission Engineer
Tim Figart—Principal Engineer, Distribution Engineer
Crystal Holmes— Project Manager, Substation Project Delivery
Mike Lang— Project Manager, ET/Comm/Network/Security Project Delivery
Power Engineers—Substation Design Consulting Engineers
The Substation project progress, schedules, and budget are tracked and communicated
monthly with the Business Case owner and department Director. Any necessary quarterly
updates for SOX are made, as well as yearly project budget requests are coordinated
through the Business Case owner and the CPG, as necessary. Larger project issues
involving scope, schedule, and/or budget are brought forth to the project team noted above
and any communications and/or recommendations including any change requests would be
brought forth to the Sponsor/Director-level stakeholders,as applicable.
Business Case Justification Narrative Template Version: February 2024 Page 20 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 112 of 535

DocuSign Envelope ID:74121ACF-5716-41D2-A58F-04C0959B3B62
Metro 115kV Substation
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Metro 115 kV Substation and agree with the
approach it presents. Significant changes to this will be coordinated with and approved by the
undersigned or their designated representatives.
DocuSigned by:
Signature: Date: May-02-2024 1 3:49 PM PDT
Print Name: c40120pPaM s�.ain
Title: Manager, Substation Engineering
Role: Business Case Owner
DocuSigned by:
Signature: Date: May-03-2024 1 1:41 PM PDT
Print Name: 06c4AA&ffq blensky
Title: Director, Electrical Engineering
Role: Business Case Sponsor
Signature: Date:
Print Name: Brian Vandenburg
Title: Manager, Engineering Projects
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2024 Page 21 of 21
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 113 of 535

Docusign Envelope ID:825E3A90-F88A-407A-8DD3-5B461 133ADA81
New Revenue - Growth
EXECUTIVE SUMMARY
Avista defines these investments as "customer requests for new service connections,
line extensions, transmission interconnections, or system reinforcements to serve a
single large customer." We have often in the past referred to new service connects as
"growth," as in growth in the number of customers, however, these investments are
beyond the control of the Company, and as such they do not reflect a plan or strategy
on the part of Avista. Responding quickly to these customer requests is a requirement
of providing utility service. Typical projects include installing electric facilities in a new
housing or commercial development, installing or replacing electric meters, or adding
street or area lights per a request from an individual customer, a city, or county agency.
As would be expected, fluctuation in the number of new customer connections is largely
dependent on local economic conditions both in the housing and business sectors.
New customers are served for electric in WA and ID and gas in WA, ID, and OR.
Both connects forecast and 12-month rolling Cost Per Service information are used to
calculate costs directly related to providing service to customers. Electric and Gas
devices are also included in this business case - Meters, Transformers, Gas
Regulators, and ERTs (Encoder Receiver Transmitter). Many of these Meters,
Transformers, and ERTs are used as replacements for Wood Pole Management, and
Periodic Meter Changes, for example.
Growth Business Case Funds request:
ELEC&GAS 2025 1 2026 2027 2028 1 2029
Connects Forecast:Res&Comm 9,434 1 9,138 9,106 9,121 1 9,121
Extensions,Services 50,001,574 48,511,564 49,384,495 49,258,202 49,258,202
Lighting 2,471,078 2,471,078 2,471,078 2,471,078 2,471,078
Meters&Devices 12,678,791 13,291,389 13,641,025 14,306,324 15,046,589
Transformers&Network Protectors 20,750,000 21,750,000 23,850,000 26,160,000 28,701,000
Business Case Total 85,901,442 86,024,030 89,346,598 92,195,604 95,476,869
The 5 yr average annual spend for this business case has been around $89M.
Requests for service are variable in number and in cost, sometimes requiring significant
investment for system reinforcements such as gas regulator stations and electric
distribution infrastructure. This funds request is based on ordinary expectation as
supported by forecast and input from electric and gas operations engineers.
For 2025, there are updated impacts to Growth costs, see 2.2 for more detail.
VERSION HISTORY
Business Case Justification Narrative Template Version: February 2023 Page 1 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 114 of 535

Docusign Envelope ID:825E3A90-F88A-407A-8DD3-5B461 133ADA81
New Revenue - Growth
Version Author Description Date
1.0 Joe Wright Initial draft of original business case 5102124
BCRT Team
BCRT Memember-Joe Has been reviewed by BCRT and meets necessary requirements 5102124
Wright
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT($)
2025 $85,901,442 $85,901,442
2026 $86,024,030 $87,087,040
2027 $89,346,598 $89,089,306
2028 $92,195,604 $92,321,897
2029 $95,476,869 $95,476,869
Project Life Span 5 years
Requesting Organization/Department Energy Delivery
Business Case Owner I Sponsor Paul Good Josh DiLuciano
Sponsor Organization/Department Energy Delivery
Phase Execution
Category Mandatory
Driver Customer Requested
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
The New Revenue — Growth Business Case is driven by tariff
requirements that mandate obligation to serve new customer load when
requested within our franchised area.
Business Case Justification Narrative Template Version: February 2023 Page 2 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 115 of 535

Docusign Envelope ID:825E3A90-F88A-407A-8DD3-5B461 133ADA81
New Revenue - Growth
1.2 Discuss the major drivers of the business case.
Customer Requested: The New Revenue—Growth Business Case serves
as support of several focus areas in Avista. We seek to serve the interests
of our customers, in a safe and responsible manner, while strengthening
the financial performance of the utility. Our growth contributes to strong
communities, ongoing value to our customers, and the device portion of
the business case keeps our system safe and reliable.
All new customers on Avista's system are benefitted by this business
case. In addition, all customers who have their metering or regulation
changed, or who have transformers replaced, benefit from this business
case.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
Avista is required to serve appropriate new load, complying with our
Certificate of Convenience and Necessity, and as part of our Obligation to
Serve.
The New Revenue — Growth Business Case will provide funds for
connecting new Electric and Gas customers in accordance with our filed
tariffs in each state.
Our obligation to serve, mandates that we must extend service to new
customers in our franchised service areas. We do not currently have an
alternative to serving new customers. All projects are subject to our Line
Extension Tariffs, filed with each State Utility Commission.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
This business case is about connecting customers to Avista's facilities. The
work directly reflects our focus area for customers as well as our mission
statement."We must hold our customer's interests at the forefront of all our
decisions" and "We improve our customer's lives through innovative energy
solutions."
Business Case Justification Narrative Template Version: February 2023 Page 3 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 116 of 535

Docusign Envelope ID:825E3A90-F88A-407A-8DD3-5B461B3ADA81
New Revenue - Growth
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
N/A
2. PROPOSAL AND RECOMMENDED SOLUTION - Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Providing service to customers upon request is mandated. As needed
customer project coordinators (CPCs) and engineers review requests to
determine solutions that best meet the needs of the customer and Avista.
These extraordinary requests lend themselves to more visibility and
oversight.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
Avista uses a rolling 12-month Cost Per New Service spreadsheet to measure
ER1000, Electric New Revenue, and ER1001, Gas New Revenue spending.
Device blankets are subject to demand for both new revenue and non-revenue
installation and replacement.
Enclosed is a spreadsheet showing projected spend through 2029 with a
breakout by Expenditure Request for the New Revenue — Growth Business
Case. Connects forecast and 12 -month rolling Cost Per Service information are
used. Electric and Gas devices are also included, such as Meters,
Transformers, Gas Regulators, and ERTs (Encoder Receiver Transmitter).
Many of the Meters, Transformers, and ERTs are used as replacements for
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 117 of 535

Docusign Envelope ID:825E3A90-F88A-407A-8DD3-5B461 133ADA81
New Revenue - Growth
Transformer Change Out Program, Wood Pole Management, and Periodic
Meter Changes.
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
There are no identified direct savings associated with this business case. This
business case supports the installation of equipment to support new
customers.
There are no direct or indirect savings represented in the Growth business
case. The Growth Business Case is driven by tariff requirements that mandate
obligation to serve new customer load when requested within our franchised
area. The business case also includes initial purchase of transformers, as well
as electric and gas meters and devices which are on hand for immediate
response for reliability and customer response reasons. The work utilizing this
equipment is represented in various business cases.
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
There are no identified indirect savings associated with this business case.
This business case supports the installation of equipment to support new
customers.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 118 of 535

Docusign Envelope ID:825E3A90-F88A-407A-8DD3-5B461 133ADA81
New Revenue - Growth
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternative 1:
In some instances, there may be alternative ways to serve a customer.
Customer project coordinators and engineers determine the solution that best
serves the customer while considering subsequent customers and Avista's
infrastructure.
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
We periodically review and update the line extension tariffs to ensure we are
not creating excessive rate pressure in connecting new customers.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Work timeline is primarily driven by the request of the customer. The transfer
to plant occurs monthly.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
The Energy Delivery Director Team assumes the role of advisory group for
the New Revenue — Growth Business Case, with quarterly reporting to the
Board of Directors through the Financial Planning & Analysis department.
The appropriate extension and service tariffs are designed and updated by
the Avista Regulatory Affairs Department, in cooperation with Construction
Services, and the Financial Planning & Analysis department. All Customer
Project Coordinators are trained regularly, by Regulatory Affairs and
Finance, on tariff application.
For the Electric and Gas New Revenue Expenditure Requests (ERs):
Operations managers and directors receive monthly Cost of Service reports
providing 12-month rolling average costs for the construction areas. This
allows for review of trending of costs for decision-making regarding
processes and resources.
For the Metering and Devices ERs: Monthly Capital ER and project results
reports are distributed. These provide updated variance information
facilitating oversight by the Electric Meter Shop and Gas Engineering
department.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 119 of 535

Docusign Envelope ID:825E3A90-F88A-407A-8DD3-5B461 133ADA81
New Revenue - Growth
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the New Revenue — Growth and agree
with the approach it presents. Significant changes to this will be coordinated with and
approved by the undersigned or their designated representatives.
Signed by:
Signature: PAU Good, Date: Aug-31-2024 1 3:40 PM PDT
Print Name: Paul Good
Title:
Director of Electric Operations
Role: Business Case Owner
Signed by:
Signature: 56SL vtbtLial h Date: Aug-30-2024 1 12:02 PM PDT
Print Name: josh Di Luci ano
Title: VP Energy Delivery
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 7 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 120 of 535

DocuSign Envelope ID: C26DCAF1-CAD2-4348-A8D1-A453F0303C8B
Substation - Asset Condition
1.0 BUSINESS CASE REQUEST — 5 YEAR PLANNING 2024
Year Requested Amount CPG Approved Amount
(Admin use only)
2025 $21,025,000
2026 $5,200,000
2027 $3,100,000
2028 $3,600,000
2029 $4,700,000
1.1 DISCUSS HOW THE ABOVE REQUESTED AMOUNT WAS CALCULATED
INCLUDING ANY CONSIDERATION OF HISTORICAL SPENDING, ESTIMATES,
CONFIDENCE LEVELS AND ESCALATION RATES.
This business case provides the asset management equipment replacements due to asset
condition, Substation property purchases and equipment purchases for system spares.
Major Equipment payments:
Year Power Transformers Auto Transformers High Voltage Breakers
2025 $2,250,000 $3,400,000 $600,000
2026 $1,300,000 $0
Total of 9 Transformers Total of 1 Auto Total of 4 HV Breakers
Other Major Projects:
- Garfield Transformer Replacement—planned for 2025.
- Poleline Substation Construction Completion (2025).
- Substation Property Purchases.
o $5M in 2025, $21M each year after.
2.0 INITIAL BUSINESS CASE APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the funds request and agree with the approach
presented,and that it has been approved by the relevant governance group. Signatures are required before
funding can be considered.
Name Role Signature Date
D...Signed by:
Brian Chain BC Owner bhou"("w May-02-2024 1 4:06 PM PDT
Vern Malensky BC Sponsor May-03-2024 1 2:03 PM PDT
F P&A 06C4FF5AB09E4QB_.
Business Case Funds Request—version 04.21.2022 Page 1 of 1
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 121 of 535

DocuSign Envelope ID: C26DCAF1-CAD2-4348-A8D1-A453F0303C8B
Substation - Asset Condition
EXECUTIVE SUMMARY
The Substation - Asset Condition business case is one of the largest business cases for Avista because
there is a vast amount of expensive equipment, such as power transformers, high voltage circuit breakers,
etc, necessary to serve customers reliably throughout our electric system.
Substations transform electrical energy from high voltage transmission lines to lower voltage distribution
lines that feed customers service points. Substations also allow switching, which reroutes electricity to
enable reliability to customers and employee safety. Substations can be meter points as well as locations
that provide protection for the expensive assets that can be vulnerable to faults. Substations are one of the
main locations where voltage can be controlled.
The Substation Asset Condition Business Case is comprised of three ERs. ER 2000 includes major
equipment spares (power transformers, high voltage breakers etc) that are held in stock until they are
transferred to a location. ER 2204 includes major substation projects that contain multiple equipment asset
condition issues, compliance updates and capacity upgrades.A substation rebuild is planned when several
equipment types are at end of life.These projects also include significant Distribution system,Transmission
system and Communication system work. This ER also includes property purchases for future substations.
ER 2215 includes small substation projects (single transformer replacements, regulator upgrades, etc)that
have been deemed needed due to asset condition. Equipment failures are now funded through the
Substation— Failed Plant business case.
Substation equipment needs to be replaced when it fails to fulfill its intended function. Substation equipment
may also need to be replaced when it has become obsolete. Obsolescence is due to parts or software not
being available to maintain a piece of equipment.
Good, reliable electric service to the distribution system is dependant on the Substation Asset Condition
Business Case being able to address issues when necessary at Avista's 165 substations. If not funded,
customers would have poor electric service, numerous outages and be dissatisfied.
Major Equipment payments:
Year Power Transformers Auto Transformers High Voltage Breakers
2025 $2,250,000 $3,400,000 $600,000
2026 $1,300,000 $0
Total of 9 Transformers Total of 1 Auto Total of 4 HV Breakers
Other Major Projects:
- Garfield Transformer Replacement—planned for 2025.
- Poleline Substation Construction Completion (2025).
- Substation Property Purchases.
o $5M in 2025, $2M each year after.
VERSION HISTORY
Version Author Description Date
1.0 Madden/Kusel Initial draft of original business case 511212023
2.0 Chain/Kusel Annual revision of business case 312024
DS
BCRT Steve Carrozzo Has been reviewed by BCRT and meets necessary requirements
Business Case Justification Narrative Template Version: February 2024 Page 1 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 122 of 535

DocuSign Envelope ID: C26DCAF1-CAD2-4348-A8D1-A453F0303C8B
Substation - Asset Condition
GENERAL INFORMATION
YEAR PLANNED SPEND
AMOUNT($) PLANNED TRANSFER TO PLANT ($)
2025 $21,025,000 $20,000,000
2026 $5,200,000 $3,750,000
2027 $3,100,000 $2,500,000
2028 $3,600,000 $1,000,000
2029 $4,700,000 $2,000,000
Project Life Span Ongoing
Requesting Organization/Department Substation Engineering
Business Case Owner Sponsor Brian Chain Vern Malensky
Sponsor Organization/Department Electrical Engineering
Phase Execution
Category Program
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - THIS SECTION MUST PROVIDE THE
OVERALL BUSINESS CASE INFORMATION CONVEYING THE
BENEFIT TO THE CUSTOMER, WHAT THE PROJECT WILL DO
AND CURRENT PROBLEM STATEMENT.
1.1 What is the current or potential problem that is being addressed?
Avista substations have numerous age related issues that lead to failures and need to be
addressed on a regular basis. At a point where an overwhelming number of issues in a
substation yard exist, rebuilding the entire substation is necessary.
The Substation Asset Condition Business Case includes three types of projects: Capital Spares,
Asset Management Capital Maintenance and Substation Rebuilds.
ER 2000 includes major equipment spares (power transformers and high voltage breakers)that
are held in stock until they are transferred to a substation location. This ER and associated
project numbers are separated from the other two ERs in this business case because they don't
have specific substation projects that they are associated with at the time of purchase of the
assets. Most of these units are spares for future work and are deemed used and useful after
they are installed at a substation.
ER 2215 includes small substation projects (single transformer replacements, regulator
upgrades, high-voltage circuit breakers, lower voltage circuit breakers and reclosers, circuit
switchers, capacitor banks, etc.)that have been deemed needed due to asset condition leading
to imminent equipment failure. This ER is for individual equipment replacements and is
Business Case Justification Narrative Template Version: February 2024 Page 2 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 123 of 535

DocuSign Envelope ID: C26DCAF1-CAD2-4348-A8D1-A453F0303C8B
Substation - Asset Condition
separated from the other two ERs in this business case because it is focused on specific stations
but is not a total rebuild of a substation.
ER 2204 includes major substation projects, i.e. a rebuild,that include multiple equipment asset
condition issues, compliance updates or capacity upgrades. A substation rebuild is planned
when several equipment types are at end of life or have other reasons triggering the need for
replacement. These projects also include significant Distribution system, Transmission system
and Communication system work.
It is preferred to perform substation rebuilds on a non-energized substation parcel (or portion of
the current property) which is called a 'greenfield' rebuild. This allows for quicker construction
and safer conditions for the crews building the new station.A substation can also be built on the
current site, a 'brownfield' rebuild. Brownfield rebuilds are much more complicated due to
construction occurring within an energized substation.
Replacing substation apparatus and equipment as it approaches end of life or becomes obsolete
is necessary to maintain safe and reliable operation of Avista's transmission and distribution
systems.Avista's purpose is to improve life's quality with energy, safely, reliably and affordably.
Functioning substations are key to fulfilling this purpose.
Substation equipment that no longer fulfills its intended purpose has failed. Often, the failure is
a complete inability to function. Beginning in 2024, these equipment failures will be completed
under the Substation—Failed Plant business case.
Rebuilding significant portions of substation or the entire subsation may be triggered after an
equipment failure due to some of the other equipment in the substation being obsolete.
Obsolete equipment is equipment that there are no or limited replacement parts or software is
not supported.
While asset condition is the primary driver triggering the need to replace major apparatus and
equipment, additional factors that may contribute to the need to broaden the scope of a station
rebuild project include operational and maintenance requirements, updated design and
construction standards, SCADA communications, future customer load-service needs, and
other programs (e.g. Grid Modernization). This would provide some costs efficiencies for Avista
to do all this work at once.
Because much of the equipment in a substation was installed at the same time, it often reaches
the end of life at a similar period in time. Therefore, Asset Management evaluations of a
substation can be performed to determine if just a few pieces of equipment need to be replaced
or if it is cost-effective to rebuild the entire substation.
Another reason a substation rebuild project may expand in scope after a piece of equipment
fails is that updated equipment spacing requirements may need to be accommodated.
Appropriate spacing of equipment in a substation is necessary because of the need to limit the
situation of a fire traveling from one piece of equipment to another piece of equipment.
Additionally, arc flash safety distances as well as proper physical access to equipment may be
reasons why additional spacing between equipment is warranted and thus, among other factors
a substation rebuild may be needed.
Aging apparatus and equipment plus changes in customer needs and compliance requirements
contribute to the heavy need for substation rebuilds on the Avista system. Using up of extra
capacity on the Avista distribution system has Avista's Electric Distribution Substations in a state
of vulnerability. Substation failures can result in customer outages because of a lack of capacity
for Operations Engineers to be able to switch around outages with the use of other capacity on
the system
As with any electric supply system, there are many types of equipment at varying ages and
conditions. See the table below a list of major substation equipment and the total number
currently operating in the Avista system. Currently,Avista owns and maintains 165 substations.
Business Case Justification Narrative Template Version: February 2024 Page 3 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 124 of 535

DocuSign Envelope ID: C26DCAF1-CAD2-4348-A8D1-A453F0303C8B
Substation - Asset Condition
Equipment Type System Count
Air Switch (>100kV) 1,051
Battery Banks 135
Circuit Breakers(<100kV) 480
Circuit Breakers(>100kV) 380
Circuit Switchers 123
Power Transformers 228
Voltage Regulators 1,094
Below is the list of oldest equipment operating in Avista substations. South Lewiston, Garfield
and Kooskia 115kV substations are on the 5-year plan for rebuilds or equipment replacements.
Substation Desc Equipment Type Asset Description Manuf Year
South Lewiston 115kV Circuit Breakers(<100kV) 1348 OCR 1924
South Lewiston 115kV Circuit Breakers(<100kV) 1358 OCR 1924
Leon Jct. 115kV Air Switch (>100kV) A-145 Air Switch 1930
Four Lakes 115kV Air Switch (>100kV) A-16(B-1731)LINE DISC 1946
Four Lakes 115kV Air Switch (>100kV) D-2138/7085 GRID SWT 1946
Garfield 115kV Power Transformers Transformer#1 1946
Four Lakes 115kV Air Switch (>100kV) A-14(B-1729)LINE DISC 1947
Four Lakes 115kV Air Switch (>100kV) A-16(B-1730)LINE DISC 1947
Four Lakes 115kV Air Switch (>100kV) D-244/7083 GRID SWT 1947
Four Lakes 115kV Air Switch (>100kV) D-841/7084 GRID SWT 1947
Kooskia 115kV Power Transformers Transformer#1 1947
1.2 Discuss the major drivers of the business case.
The work included in this business case is asset condition based.
Asset Management Replacement projects include equipment replacements
based on the following strategies:
Equipment Type Asset Management Strategy
Air Switches(>115kV) Inspection-based replacement
Battery Banks Calendar-based replacement
Circuit Breakers(>115kV) Monitor-based and Inspection-based replacement
Circuit Breakers(<115kV) Inspection-based replacement
Circuit Switchers Inspection-based replacement
Power Transformers Monitor-based and Inspection-based replacement
Voltage Regulators Inspection-based replacements
Business Case Justification Narrative Template Version: February 2024 Page 4 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 125 of 535

DocuSign Envelope ID: C26DCAF1-CAD2-4348-A8D1-A453F0303C8B
Substation - Asset Condition
Substation rebuilds are typically asset condition based but other drivers like
Performance & Capacity and Customer Service Quality and Reliability can play a
role in triggering a total substation rebuild.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The Substation Asset Condition Business Case is a programmatic business case because of
the need for continued rebuilding substations, replacing substation equipment and support of
spare substation parts. With 165 substations, continued addressing of asset condition issues is
necessary so that substation infrastructure continues to operate and service customers. If
neglected, substations would not be able to support the electric system and outages to large
numbers of customers would result. Substations typically serve between 1,000 and 3,000
customers.
Because Avista has 165 substations and substations can last 80 years, Avista needs to rebuild
about 2 substations per year to keep from having an overwhelming number of substations that
need to be rebuilt.
Equipment expected life varies from equipment piece to equipment piece. Heavy electronic
pieces of equipment may only last 10-15 years where mechanical equipment may last as long
as 80 years. Continual replacement of equipment throughout the 165 substations helps to limit
the number of stations that need to be totally rebuilt.Targeting levelized replacements or at least
tracking them being aware of how close replacements are to levelized amount is an Asset
Management strategy that helps keep reliability high and limits the potential of a bow wave of
replacements that need to be done at the same time.
Spare substation equipment is necessary to have on hand so that when a piece of equipment
fails to operate and must be replaced, there are spares available. Typically a small number of
the major equipment is necessary to have as spares because the equipment usually lasts quite
long. Beginning in 2020, lead times on equipment have increased exponentially on most items,
which necessitates having more spare pieces of equipment. Not having enough spare
equipment in case of need can lead to a substation failure and thus, customer outages and poor
customer experience.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
The Substation Asset Condition Business Case keeps the system functioning which is critical to
serving our customers well and unlocking pathways to growth. The Perform Focus Area of
Avista's focus goals is the primary alignment with the requested business case but there are
elements to the business case which are aligned with the theme of our Vision, Mission, and
Focus Areas.
Our Customers:
Existing and future customers in the Avista service area interested in having reliable electrical
service. Avista needs to deliver a system which can maintain serving customers reliably.
Our People:
Business Case Justification Narrative Template Version: February 2024 Page 5 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 126 of 535

DocuSign Envelope ID: C26DCAF1-CAD2-4348-A8D1-A453F0303C8B
Substation - Asset Condition
The portion of our company who will support the implementation of the project represents a core
electric utility collection of our employees. These employees will benefit from this business case
by having safe substations to work in.
Perform:
With continued work to address asset condition issues, our system will remain reliable and serve
customers well.
Invent:
Rebuilding substations with standard equipment is typical but Avista has the opportunity to
improve the equipment, construction and delivery process as part of a large-scale program.
Vision; Better energy for life:
Investment in the substation system represents a long term invest of infrastructure which will be
in place to serve our customers for several generations.
Mission; We improve our customers' lives through innovative energy solutions:
The Substation Asset Condition Business Case has been identified as the best method to
maintain the reliability of Avista's substation system that are part of the backbone of an electrical
system.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
All of Avista's substations except for one are located outside. Sun and weather take a toll on the
equipment located outside. Over time, advances in technology make some substation
equipment obsolete. The equipment may either not provide the function that is now expected of
that equipment or replacement parts may not be available.
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The recommended approach is to replace substation apparatus and equipment as needed due
to asset condition and rebuild substations when the majority of assets in the impacted substation
have been determined to have reached their end of life. This business case aligns with the
Company's mission to deliver safe and reliable electric service to customers by preventing the
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2024 Page 6 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 127 of 535

DocuSign Envelope ID: C26DCAF1-CAD2-4348-A8D1-A453F0303C8B
Substation - Asset Condition
potential failure of substations that would lead to degradation of reliability and mitigating the
frequency and duration of outages due to equipment failure.
Increased costs due to inflation as well as aging substations and substation equipment has led
to an increase in the budget for the Substation Rebuilds Business Case over the last five years.
The inclusion of the large Metro project in the budget for 2022 and 2023 has contributed to the
increase of spend.
As of the 2023 budget, the Metro Project was separated into its own business case, so the
budget estimates for Metro are not shown in the budget requests for 2025-2029.
Project prioritization is supported by the Engineering Roundtable (ERT) and substation subject
matter experts for prioritization of work within this risk category. Project and funding levels are
reviewed and approved by the ERT on an annual basis.
Fixing the equipment issues when they fail to function is necessary as is getting a good amount
of life out of each piece of equipment until it approaches end of life. The balance is found by
evaluating each piece of equipment and the substation as a whole when there are an
overwhelming amount of equipment in a substation that is close to end of typical life.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
In a memo document dated December 27, 2017, Substation Performance Requirements were
outlined by Rich Hydzik, Transmission Operations Engineer and Garth Brandon, then the Chief
System Operator. The document identified issues which were integral to the reliable operation
of the Avista electric system.This document is directly related to the Substation Asset Condition
Business Case because it aims at addressing the identified issues.
Substation equipment requires regular maintenance to function reliably for good customer
service. Well designed substations enable equipment maintenance without service outages to
to customers. Short momentary outages (less than 4 hours) to conduct switching may be
required to allow maintenance activities to take place but extended outages are not acceptable
customer service.
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
O&M $ $ $ $ $
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2024 Page 7 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 128 of 535

DocuSign Envelope ID: C26DCAF1-CAD2-4348-A8D1-A453F0303C8B
Substation - Asset Condition
No direct offsets are anticipated because rebuilding substations requires O&M activities such
as monthly inspections and equipment maintenance. Annual O&M costs for a distribution
substation is approximately $30,000. Annual O&M costs for a transmission substation is
approximately$50,000
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and OW) that result by undertaking this investment.
Offsets Offset 2025 2026 2027 2028 2029
Description
Capital $0 $0 $0 $0 $0
Substation
Rebuilds &
O&M Asset $176,800 $176,800 $176,800 $176,800 $176,800
Management
Offsets
The indirect offsets assume that each substation has four pieces of equipment that require `limp
along' maintenance(power transformer, low voltage breaker recloser, high voltage breaker, and
a voltage regulator). It is assumed that a Generation Production & Substation Support (GPSS)
Serviceman spends approximately 10 hours each week driving to a substation, maintaining
equipment to `limp it along' instead of replacing it, and cleaning up.
1,040 hours (two locations * 10 hours of O&M * 52 weeks = 1,040 hours) of additional
maintenance would be needed if these station rebuilds did not take place. Avista rebuilds two
substations per year on average. If that work is not done, then 1 additional GPSS Serviceman
will be needed to address the limp along maintenance needed to keep those stations in service.
One additional Serviceman,will cost$176,800 annually(1 Journeyman Electrician *$85 loaded
labor/hour*40 hours/week*52 weeks). This figure does not include tools, materials and vehicle
costs (miles and maintenance) used during this equipment maintenance.
Risk of Outages due to not replacing equipment.
There is a risk of customer outages and an associated cost to customers for outages as a result
of not replacing equipment when it is needing to be replaced. The cost turns out to not be
material. Risk Cost= Prob of Failure* Prob(consequence)*Cost(consequence). Assuming 30
voltage regulator failures that result in customer outages per year. Also assuming -1,000
customers per feeder. Risk Cost = 4% prob of failure * 1% catastrophic failure (customers out)
* (1,000 customers *4 hour outage * $116.15/hr) = $185.84 per outage * 30 failures per year=
$5,575 per year.
If a substation Transformer fails, assume 3,000 customers out (three feeders). Assume 1
transformer failure / year. Risk Cost = 0.4% prob of failure * 1% catastrophic failure * 3,000
customers*8 hour outage*$116.15/hr= $111.50 per outage * 1 failure per year= $111.50 per
year.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2024 Page 8 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 129 of 535

DocuSign Envelope ID: C26DCAF1-CAD2-4348-A8D1-A453F0303C8B
Substation - Asset Condition
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
The options for asset condition issues on the system are limited to do nothing, maintain current
funding level and reduce the current funding level. Each of the options are discussed below:
Option 1: Do nothing - Not recommended because it would not be prudent to let the system
deteriorate and not fix things in the substations that have failed. Obsolete and/or high loss
equipment, deteriorated wood structures, and non-standard construction or equipment would
remain in service until failure. Below are discussions of the consequences of not funding the
individual ERs.
Option 2: Maintain current funding level. Project prioritization is supported by the Engineering
Roundtable and substation subject matter experts for prioritization of work within this risk
category. The project and funding levels are reviewed on an annual basis.
Option 3: Reduce current Asset Condition capital investments.This option is not recommended.
This option would lead to a reduction in the level of reliability and or operating flexibility that can
be achieved by the transmission and distribution systems.
See the table below for a risk comparison between funding the business case and not funding
the business case. Note that the Substation Asset Condition Business Case is projected to
reduce the likelihood of an Environmental; Safety and Health to the Public; Legal, Regulatory,
External Business Affairs; Safety and Health to Employees; and Customer Service and
Reliability from once every 10 years to once every 50 years.
Business Case Justification Narrative Template Version: February 2024 Page 9 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 130 of 535

DocuSign Envelope ID: C26DCAF1-CAD2-4348-A8D1-A453F0303C8B
Substation - Asset Condition
Unfunded Risk
Likelihood Environmental Safety and Legal, Safety Customer
of Event Health: Public Regulatory, and Service and
External Health: Reliability
Business Employee (#customers
Affairs * duration of an
outage)
<Once/ 10 Large volume Potential for Could result Potential >7,500
years transformer of minimal or minor in a for Customer hours
spill, hazardous injury, Outages sustained minimal or
waste cleanup, and/or negative minor
moderate to low equipment impact to injury Lost
volume or level damage, Public local, Time
PCBs, minimal health online, or Incident
impact to infrastructure industrial and
waterways, impact up to 24 relationship Severaity
repeated or hours and/or Rate
moderate air national/ increase
emission global year or
exceedance. media year
coverage
Revised Risk if funded/completed
Likelihood Environmental Safety and Legal, Safety Customer
of Event Health: Public Regulatory, and Service and
External Health: Reliability
Business Employee (#customers
Affairs *duration of
an outage)
<Once/50 Isolated spill with Potential for No likely Potential <1,500
years 0 to low level injury, Public impact on for injury Customer hours
PCBs, no health media or
migration, air infrastructure regulatory
emission minor impact up to 8 relationship
exceedance, hours
standard clean-up
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
Success for the asset condition business case can be measured ultimately by the average age
of the listed equipment types operating in substations.
The table below lists common substation equipment,the number of pieces of the equipment has
in service and the average number of replacements per year for that equipment type. From the
system count and the average replacements per year, an average levelized replacement length
in years can be calculated. For comparison purposes, the number of pieces of equipment
needed to be on a 20 year replacement cycle where 5% of the system for that equipment type
is replaced is show in the table as well.
Business Case Justification Narrative Template Version: February 2024 Page 10 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 131 of 535

DocuSign Envelope ID: C26DCAF1-CAD2-4348-A8D1-A453F0303C8B
Substation - Asset Condition
Equipment Type Avista Avista Average Avista Average
System Replacement per Levelized
Count Year(2018-2022) Replacement Length
Air Switches 1,051 26.80 40.0 years
(>100kV)
Battery Banks 135 11.00 12.5 years
Circuit Breakers 480 13.20 38.5 years
(<100kV)
Circuit Breakers 380 16.60 24.1 years
(>100kV)
Circuit Switchers 123 2.75 45.8 years
Power Transformers 228 5.40 44.3 years
Voltage Regulators 1,094 61.60 18.1 years
The table demonstrates that not all equipment lasts the same period of time. Avista does not
have an Asset Management strategy where pieces of equipment are replaced based on age.
Instead each piece of equipment is evaluated as to whether it is meeting its required function.
However, it is good practice to monitor what the average levelized replacement length is for
each piece of major equipment to know if a bow wave of replacements are being created
because of a low number of replacements are occurring.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Projects within this business case are at all stages of work. There are continually several
substation rebuild projects in scoping,design,construction, commissioning and closeout stages.
Asset management replacements are being assessed, designed and constructed throughout
the year.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
Each of the three ERs that are part of the Substation Asset Condition Business Case have
different steering committes or governance teams.
ER 2000, the ER for Substation Spare Major Equipment is governed by the Apparatus
Engineers and Substation Engineering Manager.
ER 2204, the Substation Rebuilds ER is governed by Engineering Rountable (ERT) Members:
Substation Engineering, Transmission Engineering, Distribution Engineering, Communication
Engineering, IT/ET Network Engineering, System Planning, and System Operations.
Business Case Justification Narrative Template Version: February 2024 Page 11 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 132 of 535

DocuSign Envelope ID: C26DCAF1-CAD2-4348-A8D1-A453F0303C8B
Substation - Asset Condition
ER 2215, the Substation Asset Management ER is governed by the Substation Maintenance
Engineers, Distribution Area Engineers, Electric Shop Servicemen, Distribution Area
Servicemen, and Substation Engineering Manager.
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Substation—Asset Condition and agree with
the approach it presents. Significant changes to this will be coordinated with and approved by the
undersigned or their designated representatives.
DocuSigned by:
Signature: Date: May-02-2024 1 4:06 PM PDT
Print Name: c40121M M40hain
Title: Manager, Substation Engineering
Role: Business Case Owner
DocuSigned by:
Signature: Ut,V�(— habA,'A-u Date: May-03-2024 1 2:03 PM PDT
Print Name: 06c4FWPP€Malensky
Title: Director, Electrical Engineering
Role: Business Case Sponsor
DocuSigned by:
Signature: f2l(iaA& V�" Date: May-03-2024 1 8:49 AM PDT
Print Name: 0304BE&FAIM9Vandenburg
Title: Manager, Engineering Projects
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2024 Page 12 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 133 of 535

DocuSign Envelope ID:244DBD63-018D-4BE3-A2BE-8265FA47DB79
Substation - Performance and Capacity
1.0 BUSINESS CASE REQUEST - 5 YEAR PLANNING 2024
Year Requested Amount CPG Approved Amount
(Admin use only)
2025 $14,900,000
2026 $24,000,000
2027 $24,800,000
2028 $34,000,000
2029 $25,000,000
1.1 DISCUSS HOW THE ABOVE REQUESTED AMOUNT WAS CALCULATED
INCLUDING ANY CONSIDERATION OF HISTORICAL SPENDING, ESTIMATES,
CONFIDENCE LEVELS AND ESCALATION RATES.
The Substation — Performance and Capacity Business Case is intended to be a programmatic
business case allowing the continual flow of performance and capacity projects to be funded under
one business case with projects that have the same project driver.
Major Projects Planned (>$10 million):
- Bronx Substation Rebuild (electrical construction 2025-2027). $14M.
- Five Mile Substation Construction (electrical construction 2027-2029). $19M.
- Melville Substation Construction (electrical construction 2027-2028) — Transmission Line
easement work has begun. $26M.
- Midway Substation Construction (electrical construction 2028-2029). $16M.
- Pleasant View Substation Capacity Mitigation (electrical construction 2026-2028). $12M.
2.0 INITIAL BUSINESS CASE APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the funds request and agree with the approach
presented,and that it has been approved by the relevant governance group. Signatures are required before
funding can be considered.
Name Role Signature Date
DocuSigned by:
Brian Chain BC Owner ggnn yy May-03-2024 1 8:5 AM PDT
4012FF13CM491...
Vern Malensky BC Sponsor May-03-2024 1 2:0 PM PDT
F P&A 06C4FF5AB09E40B.
Business Case Funds Request—version 04.21.2022 Page 1 of 1
Exhihit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 134 of 535

DocuSign Envelope ID:244DBD63-018D-4BE3-A2BE-8265FA47DB79
Substation - Performance and Capacity
EXECUTIVE SUMMARY
Inadequate electric distribution system capacity to serve new customer growth has been identified through
technical studies and real-time operations. The System Planning team performs an evaluation of the
distribution system biannually which includes a ten-year forecast of expected distribution substation
equipment loading during peak summer and winter conditions.The most recent analysis performed in 2023
and documented in 2023-2024 System Assessment Version 0 concluded several anticipated capacity
deficiencies in Avista's distribution substations over the next ten years. Capacity issues arise from
increased customer demand.The growth in demand is driven by migration of customers to Avista's service
territory and changes in end-use equipment such as transportation electrification and building electrification.
The 2023-2024 System Assessment incorporated improved statistical evaluation of peak loading conditions
and improved modeling accuracy utilizing additional distribution planning engineers therefore additional
capacity issues have been identified compared to previous assessments. The 2021 summer peak loading,
documented in Heat EOP Event Analysis—Version 0, 2021, provided an example of observed operational
issues which led to customer outages (not all customer outages were caused by inadequate distribution
substation capacity). Technical analysis performed as part of the system assessment process is intended
to identify expected capacity issues before they cause real-time operational issues.
The recommended solution to mitigate the observed capacity deficiencies is to programmatically add
distribution substation capacity through the construction of new substations and upgrades to existing
stations. Estimated costs for 2025-2029 vary between $11 and $35 million based on construction resource
capabilities, constrained outage windows, and competing high priority projects. A list of mitigation projects
provided in the 2023-2024 System Assessment associated with this business case includes:
• Bronx Station Rebuild - Reconstruct existing Bronx Station to include distribution
facilities with a 20MVA transformer and two distribution feeders. The 115kV portion of
the station will include two 115kV transmission line positions protected with circuit
breakers and configuration suitable for future expansion.
• Poleline (Prairie) Station Rebuild - Construct new distribution station to replace
Avista facilities at existing Prairie Station. New station to include two 30MVA
transformers, four feeders, and looped-through transmission line.
• Valley Capacity Mitigation — Rebuild existing Valley Station with increased
distribution capacity.
• Pleasant View Capacity Mitigation - Rebuild existing Pleasant View Station with
increased distribution capacity.
• North Spokane Distribution Reinforcement (Northeast) - Replace two existing
20MVA transformers with 30MVA transformers and add new NE12F6 feeder.
Transformer circuit switchers replacements are included in scope to eliminate existing
fault blocking scheme. Distribution integration scope includes new switches and an
express feeder truck.
• Orin Capacity Mitigation - Construct new distribution station connected to BPA's
Colville— Republic 115kV Transmission line. New station will include a single 20MVA
transformer and two distribution feeders.
• Glenrose Capacity Mitigation - Replace existing transformer with 30MVA and
rebalance feeders. Regulator upgrades assumed to be an existing flex crew project.
• Bunker Hill Customer Capacity - Install new 20MVA transformer to replace existing
transformer and construct new dedicated customer distribution feeder.
• Melville Station -New switching station near existing tap to Four Lakes Station off the
South Fairchild Tap 115kV transmission line. Construct new transmission line from
Airway Heights to Melville including passing through Russel Road and Craig Road
distribution stations. Requires new transmission line terminal at existing Airway Heights
Station.
Business Case Justification Narrative Template Version: February 2024 Page 1 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 135 of 535

DocuSign Envelope ID:244DBD63-018D-4BE3-A2BE-8265FA47DB79
Substation - Performance and Capacity
• North Spokane Transmission Reinforcement (Five Mile 115kV Station)' —
Construct new Five Mile Station with new loop through of Nine Mile - Westside 115
requiring 3 miles of new 115 line. New BPA interconnection at Bell Station to create a
Bell — Five Mile 115 line using 1.5 mile of new line and portion of Beacon - Francis &
Cedar 115 line. New Francis & Cedar— Five Mile line using 1.5 mile of new line.
• Midway Station—Construct new distribution station to include 30MVA transformer and
two distribution feeders.
Adequate system capacity to serve customers is aligned with Avista's vision: Better Energy for Life.
Investment in the electric distribution system capacity provides Avista with the ability to meet the demands
of our customers and the communities we live in. Without adequate capacity, Avista will be required to turn
customer's power off during peak loading conditions and the company will not be able to accommodate
new customer requests for service in certain locations.
The Substation — Performance and Capacity Business Case is intended to be a programmatic business
case allowing the continual flow of performance and capacity projects to be funded under one business
case with projects that have the same project driver. Each project under the program is evaluated and
prioritized by the Engineering Roundtable.
VERSION HISTORY
Version Author Description Date
Karen Kusel/
1.0 John Gross/ Initial draft of original business case 0512023
Glenn Madden
Karen Kusel/
2.0 John Gross/ Annual update of business case 0412024
Brian Chain
DS
BCRT 1 Steve Carrozzo I Has been reviewed by BCRT and meets necessary requirements
' The North Spokane Transmission Reinforcement project includes a new substation which addresses
performance and capacity issues related to the transmission system which differs from the other projects
included in the scope of this business case.
Business Case Justification Narrative Template Version: February 2024 Page 2 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 136 of 535

DocuSign Envelope ID:244DBD63-018D-4BE3-A2BE-8265FA47DB79
Substation - Performance and Capacity
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2025 $14,900,000 $8,200,000
2026 $24,000,000 $1,300,000
2027 $24,800,000 $33,000,000
2028 $34,000,000 $46,000,000
2029 $25,000,000 $25,800,000
Project Life Span Ongoing
Requesting Organization/Department Substation Engineering
Business Case Owner Sponsor Brian Chain Vern Malensky
Sponsor Organization/Department Electrical Engineering
Phase Execution
Category Program
Driver Performance & Capacity
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
The Substation — Performance and Capacity Business Case supports new or modifications to
substations in the system to serve new and growing load, increased system reliability, and
operational flexibility. New substations under this program will require planning and operational
studies,justification, and approved project diagrams prior to funding. Capacity issues arise from
increased customer demand. The growth in demand is driven by migration of customers to
Avista's service territory and changes in end-use equipment such as transportation
electrification and building electrification.
The below figures illustrate the expected load growth for Avista's Balancing Authority area for
peak summer and winter conditions. The summer load forecast is estimating approximately 20-
25MW growth per year and the winter load forecast is estimating approximately 35-45MW per
year. Winter growth rates are expected to be higher than past decades due to the trending of
reduced natural gas usage for building heat.
Business Case Justification Narrative Template Version: February 2024 Page 3 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 137 of 535

DocuSign Envelope ID:244DBD63-018D-4BE3-A2BE-8265FA47DB79
Substation - Performance and Capacity
Summer Balancing Area Forecast
3600
Actual Summer
3400 2021 Forecast
2022 Forecast
3200 -„2023 Forecast
3000
2800
a
9 26M
2400 - -
2200 --I-----
2000
1800
2008 2013 2018 2023 2028 2033 2038
Winter Balancing Area Forecast
36W
.>-Actual W inter
3400 2021 Forecast
2022 Forecast
3200
�2023 Forecast
3000
3 2800
F
1400 _
2200
zaao
1800
20M 2013 2018 2C23 2028 2033 2M
The added load forecasted in the above figures will be spread across the Avista service territory,
but the specific areas of North Spokane, Sandpoint, Colville, West Plains, Post Falls, and Coeur
d'Alene are expected to have higher growth rates. The existing distribution system capacity has
been shown to be inadequate to accommodate the new load.The below map is a representation
of expected feeder equipment utilization in the year 2033 from the 2023-2024 System
Assessment. Areas with red highlighted feeder indicate observed performance issues from the
distribution system planning studies. Areas with low growth rates may still have capacity issues
identified from previous deferral of necessary mitigation projects.
Business Case Justification Narrative Template Version: February 2024 Page 4 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 138 of 535

DocuSign Envelope ID:244DBD63-018D-4BE3-A2BE-8265FA47DB79
Substation - Performance and Capacity
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The following tables from the 2023-2024 System Assessment provide a summary of system
wide performance concerns with equipment exceeding 80% of their applicable facility ratings.
The first table represents assumed conditions for a peak summer scenario and the second table
represents assumed conditions for a peak winter scenario. Each identified performance concern
is then further evaluated with more specific data and a project alternative evaluation is
Business Case Justification Narrative Template Version: February 2024 Page 5 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 139 of 535

DocuSign Envelope ID:244DBD63-018D-4BE3-A2BE-8265FA47DB79
Substation - Performance and Capacity
performed. Once a project is selected and vetted through the Engineering Roundtable, it is
added to the applicable Business Case for funding.
' MJU. - =
SUN12F5 55.2 61.3 68.0 75.5 83.9 93.1 103.=114.7i 3
PRA-XFMR#2 84.0 88.9 94.1 99.7WA
118.3 -1125.2 132.61 140.3 148.6
LIB12F3 83.3 88.0 92.9 98.1 115.5 0122.0 128.80 136.1 143.7
PRA221 83.7 88.2 93.0 98.0114.7 120.9 127.4 134.3 141.5
SUN-XFMR#2 2023 64.4 69.6 75.3 81.4 88.0 95.1 102.8 111.1 120.1 129.9 140.4
NE-XFMR#1 71.7 76.2 81.0 86.1 91.5 97.2 103.4 109.9 116.8 124.1 131.9
TEN1254 86.6 90.1 93.6 97.3 109.4 113.7 118.2 122.9 127.8
GRA-XFMR#1 78.5 82.1 85.8 89.6 93.7 97.9 106.9 111.7 116.7 121.9
NE12F4 69.1 73.1 77.3 81.8 86.5 91.5 96.8 hi102.3 108.2 114.5 121.1
RAT233 73.2 76.7 80.3 84.1 88.1 92.3 96.6 W101.2 106.0 111.0 116.3
HUE-XFMR#1 84.0 86.5 89.1 91.7 94.5 97.3 4nn1) M�"" 106.3 109.4 1112.7
SPT-XFMR#1 81.8 84.4 87.2 90.0 92.9 95.8 98.9 105.4 108.8 1112.3
LIB-XFMR#2 66.0 69.5 73.2 77.1 81.2 85.6 90.1 94.9 W00.0 105.3 1111.0
PF-XFMR#1 75.2 78.1 81.2 84.3 87.6 91.0 94.5 98.2-IW2.0 106.0 1110.1
L&S12F4 67.7 71.0 74.5 78.1 81.9 85.9 90.1 94.5 99.1 103.9 109.0
TEN1257 76.0 78.8 81.6 84.6 87.6 90.8 94.1 97.5 104.7 108.5
COB-XFMR#1 84.8 86.9 89.1 91.3 93.6 95.9 98.3 L 105.8 108.5
SIP-XFMR#1 64.9 68.3 71.9 75.6 79.6 83.7 88.1 92.7 97.6 L 102.7 108.0
GRA12F1 79.0 81.5 84.1 86.7 89.5 92.3 95.2 98.2 104.5 107.8
HUE142 71.7 74.7 77.8 81.0 84.3 87.8 91.4 95.2 99.2 1103.3 0107.5
LOL-XFMR#3 82.8 85.0 87.1 89.4 91.6 94.0 96.4 98.8 104.0 1106.6
IDR253 79.2 81.6 84.0 86.5 89.1 91.7 94.4 97.2 0106.1
GRA12F3 53.9 57.6 61.6 65.9 70.5 75.5 80.7 86.3 92.4 98.8 1 105.7
SPT-XFMR#2 76.8 79.3 81.8 84.4 87.2 90.0 92.9 95.8 98.9 105.4
IDR-XFMR#1 76.3 78.7 81.1 83.6 86.1 88.8 91.5 94.3 97.2 103.2
PRA222 58.0 61.4 64.9 68.7 72.7 76.9 81.4 86.1 91.1 96.4 IK02.0
TEN-XFMR#2 83.9 85.5 87.2 88.8 90.5 92.2 94.0 95.8 97.6 99.5 MMJ.4
ROS-XFMR#2 82.9 84.6 86.3 88.0 89.7 91.5 93.3 95.2 97.1 99.0
LOL1359 83.1 84.6 86.2 87.8 89.4 91.0 92.7 94.4 96.2 98.0 99.8
GLN12F2 86.4 87.7 88.9 90.2 91.4 92.7 94.1 95.4 96.8 98.1 99.5
NE12F1 67.1 69.8 72.5 75.4 78.4 81.5 84.7 88.0 91.5 95.1 98.9
COB12F2 73.0 75.2 77.5 79.8 82.3 84.8 87.4 90.0 92.7 95.6 98.5
NE12F3 49.7 53.2 56.9 60.9 65.2 69.7 74.6 79.8 85.4 91.4 97.8
TVW131 58.6 61.7 64.9 68.3 71.9 75.7 79.6 83.8 88.2 92.8 97.6
SOT-XFMR#1 73.6 75.6 77.6 79.7 81.9 84.1 86.3 88.7 91.1 93.5 96.0
PF211 51.4 54.8 58.3 62.0 66.0 70.3 74.8 79.6 84.7 90.2 96.0
SLW1368 66.4 68.9 71.5 74.2 77.0 79.9 82.8 85.9 89.2 92.5 96.0
KAM 1291 70.4 72.6 74.9 77.2 79.7 82.2 84.7 87.4 90.1 92.9 95.9
BEA12F2 77.2 78.9 80.6 82.3 84.1 85.9 87.7 89.6 91.5 93.5 95.5
NE-XFMR#2 69.5 71.7 74.0 76.3 78.8 81.3 83.9 86.6 89.4 92.2 95.2
GLN-XFMR#1 85.5 86.4 87.3 88.3 89.2 90.2 91.1 92.1 93.1 94.1 95.1
M15-XFMR#1 86.8 87.6 88.4 89.2 90.0 90.8 91.6 92.4 93.3 94.1 94.9
NW12F1 70.3 72.4 74.6 76.9 79.2 81.7 84.1 86.7 89.4 92.1 94.9
DAL131 72.7 74.7 76.7 78.7 80.9 83.1 85.3 87.6 90.0 92.4 94.9
RAT231 69.0 71.2 73.5 75.9 78.3 80.8 83.4 86.1 88.9 91.7 94.7
SPU123 70.2 72.3 74.5 76.7 79.1 81.4 83.9 86.4 89.1 91.7 94.5
3HT12F7 68.5 70.7 73.0 75.4 77.8 80.3 82.9 85.6 88.4 91.3 94.2
L&S12F2 73.2 75.0 76.9 78.8 80.8 82.8 84.8 86.9 89.1 91.3 93.5
CDA124 83.0 84.0 85.0 86.0 87.0 88.0 89.1 90.1 91.2 92.3 93.4
NE12F2 71.5 73.4 75.4 77.4 79.5 81.7 83.9 86.1 88.4 90.8 93.3
SIP12F5 60.4 63.1 65.9 68.8 71.9 75.0 78.4 81.8 85.5 89.2 93.2
INT12F1 78.6 80.0 81.3 82.7 84.1 85.5 86.9 88.4 89.9 91.4 93.0
ODS-XFMR#1 70.8 72.8 74.7 76.8 78.9 81.1 83.3 85.5 87.9 90.3 92.8
GLN12F1 86.5 87.1 87.7 88.3 88.9 89.4 90.1 90.7 91.3 91.9 92.5
US-XFMR#1 74.5 76.1 77.7 79.3 81.0 82.8 84.5 86.3 88.2 90.0 92.0
M15512 78.0 79.3 80.6 81.9 83.2 84.6 86.0 87.4 88.8 90.3 91.8
TUR116 68.8 70.8 72.9 75.0 77.1 79.4 81.6 84.0 86.4 88.9 91.5
WAK-XFMR#2 84.5 85.1 85.8 86.4 87.1 87.7 88.4 89.1 89.8 90.4 91.1
SUN-XFMR#1 2023 74.8 76.2 77.7 79.2 80.8 82.4 84.0 85.6 87.3 89.0 90.8
GRA12F2 65.3 67.5 69.7 71.9 74.3 76.7 79.2 81.8 84.4 87.2 90.0
F&C-XFMR#2 79.1 80.1 81.1 82.2 83.2 84.3 85.4 86.5 87.6 88.7 89.9
M15514 67.2 69.2 71.2 73.2 75.4 77.5 79.8 82.1 84.5 86.9 89.5
SOT521 67.1 69.0 71.0 73.0 75.1 77.2 79.4 81.7 84.0 86.4 88.9
Business Case Justification Narrative Template Version: February 2024 Page 6 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
I DiLuciano,Avista
Schedule 3,Page 140 of 535

DocuSign Envelope ID:244DBD63-018D-4BE3-A2BE-8265FA47DB79
Substation - Performance and Capacity
L&S12F3 68.5 70.3 72.2 74.1 76.0 78.0 80.1 82.2 84.3 86.6 88.8
ROS12F5 71.7 73.2 74.8 76.4 78.0 79.6 81.3 83.0 84.8 86.6 88.4
BLU321 52.2 55.0 58.0 61.1 64.4 67.9 71.5 75.4 79.5 83.8 88.3
INT-XFMR#1 73.8 75.1 76.5 77.8 79.2 80.6 82.1 83.5 85.0 86.5 88.1
WAK12F4 75.4 76.5 77.7 78.9 80.2 81.4 82.7 84.0 85.3 86.6 88.0
ROS-XFMR#1 71.8 73.3 74.7 76.2 77.7 79.3 80.9 82.5 84.1 85.8 87.5
SLW-XFMR#1 84.1 84.5 84.8 85.1 85.4 85.7 86.0 86.4 86.7 87.0 87.3
F&C12F4 75.3 76.4 77.5 78.6 79.8 81.0 82.1 83.3 84.6 85.8 87.1
3HT12F5 62.7 64.7 66.8 69.0 71.3 73.6 76.0 78.5 81.0 83.7 86.4
M15-XFMR#2 71.5 72.8 74.2 75.6 77.0 78.5 80.0 81.5 83.0 84.6 86.2
ROS12F1 67.8 69.4 71.0 72.7 74.4 76.2 78.0 79.9 81.8 83.7 85.7
TEN-XFMR#1 66.5 68.2 70.0 71.7 73.6 75.4 77.4 79.3 81.4 83.4 85.6
WAK-XFMR#1 85.3 85.3 85.3 85.3 85.3 85.3 85.3 85.3 85.3 85.3 85.3
APW112 78.3 79.0 79.6 80.2 80.9 81.5 82.2 82.8 83.5 84.1 84.8
BEA-XFMR#2 71.3 72.5 73.8 75.0 76.3 77.6 79.0 80.3 81.7 83.1 84.5
SIP-XFMR#2 64.6 66.3 68.1 69.9 71.8 73.8 75.7 77.8 79.9 82.0 84.3
SIP12F4 63.8 65.5 67.4 69.3 71.2 73.2 75.2 77.3 79.5 81.7 84.0
MEA12F1 64.9 66.6 68.2 70.0 71.7 73.5 75.4 77.3 79.3 81.3 83.3
F&C12F2 82.9 82.9 82.9 82.9 82.9 82.9 82.9 82.9 82.9 82.9 82.9
BEA12F5 65.5 67.0 68.6 70.2 71.9 73.6 75.3 77.0 78.9 80.7 82.6
MIL12F3 69.3 70.5 71.7 73.0 74.3 75.6 77.0 78.3 79.7 81.1 82.6
HUE141 75.2 75.8 76.5 77.2 77.9 78.6 79.3 80.0 80.8 81.5 82.2
C&W12F6 68.6 69.8 71.1 72.4 73.7 75.0 76.4 77.8 79.2 80.6 82.1
SIP12F2 47.3 50.0 52.8 55.8 58.9 62.2 65.7 69.3 73.2 77.3 81.6
WAK12F3 81.6 81.6 81.6 81.6 81.6 81.6 81.6 81.6 81.6 81.6 81.6
CFD1210 81.6 81.6 81.6 81.6 81.6 81.6 81.6 81.6 81.6 81.6 81.6
MIL12F2 66.8 68.1 69.5 70.9 72.3 73.7 75.2 76.7 78.2 79.8 81.4
MIL-XFMR#1 64.6 66.1 67.6 69.2 70.8 72.5 74.1 75.8 77.6 79.4 81.2
COB12F1 68.6 69.7 70.9 72.1 73.3 74.6 75.8 77.1 78.4 79.7 81.1
APW-XFMR#1 72.3 73.1 73.9 74.8 75.6 76.5 77.3 78.2 79.1 80.0 80.9
BKR-XFMR#1 71.9 72.7 73.6 74.4 75.3 76.2 77.1 78.0 78.9 79.9 80.8
MIL-XFMR#2 69.6 70.6 71.6 72.6 73.7 74.8 75.8 76.9 78.1 79.2 80.3
31HIT-XFMR#2 65.2 66.6 67.9 69.4 70.8 72.3 73.8 75.3 76.9 78.5 80.1
TIMMF 1 1 . 1 1 :
SUN12F5 67.4 75.5 85 95.7 .1 136.3 152.3 168.8 187 207
ORI-XFMR#1 26.5 130.7 134.6 139.6 143.6 149
OR112F3 26.3 130.6 134.2 139.4 143.1 148.6
RAT233 80.5 84.3 88.3 92 96.3 100.4 105.2 110.1 115.3 120.8 126.5
NE-XFMR#1 68.9 69.3 74.4 79.7 85 90.7 96.8 103.3 110.3 117.6 125
GRA12F3 60.7 65.2 70.5 75.7 81.4 87.9 94 100.5 107.8 115.3 123.3
L&S12F4 75.8 79.6 83.5 87.6 91.4 --95.9-r 100.7 105.6 110.8 116.8 122.6
MLN-XFMR#2 87.4 90.3 93.3 96.4 99.6 103 106.5 110.2 114 118 122.2
TUR116 93 95.7 98.4 1MT 106.5 109 111.6 114.2 116.9 119.7
CLV-XFMR#3 Ob.. 1 lag 117.6 118.4 118.9
LIB12F3 64.3 68.3 72.4 76.9 81.6 87 92.3 98.4 105 111.9 118.8
LIB-XFMR#2 65.8 69.6 73.7 78 82.6 87.6 93 99 105.3 112.1 118.7
SPT-XFMR#1 90 92.3 94.6 97.2 99.7 104.8M 110.7 113.7 117.1
SPT-XFMR#2 90 92.3 94.6 97.2 99.7 104.7 110.6 113.7 117.1
NE12F4 73.9 77.4 74.9 79.2 83.8 88.6 93.7 99.1 104.7 110.7 117.1
PRA-XFMR#2 68.1 71.7 75.4 79.5 83.6 88.2 93.1 98.2 103.7 109.7 115.9
BLU321 68.2 71.9 75.8 79.8 84.2 88.8 93.6 98.5 103.8 109.7 115.5
KAM 1291 83.9 86.4 89.3 91.9 95.1 97.9 4106.2
111.3 115.4
TUR117 71.7 75.1 78.6 82.7 86.6 90.6 94.8 98.8 107.1 111.6 1
OLD-XFMR#1 58.2 62.1 66.3 70.8 75.7 80.5 85.6 91.2103.3 110
GRA-XFMR#1 68.4 71.6 75.4 79.1 82.8 87.1 91.4 95.7104.9 109.9
NE12F3 49.9 54 58.8 64 69 74.4 80.2 86.6100.6 107.6
PAL312 86.7 89.9 92.8 95.8 99.3 106.2
CKF-XFMR#1 85.6 87.4 89.4 91.5 93.5 95.7 97.6 99.7 106.1
WIL-XFMR#1 91.1 92.3 93.6 95 96.5 97.9 99.2 105.4
OLD721 55.6 59.4 63.4 67.7 72.3 76.9 81.8 87.1 92.7 98.7 105.1
PRA221 63 66.1 69.5 73 76.4 80.3 84.6 89 93.8 99.3 104.7
SPA-XFMR#1 90.6 91.8 93 94.2 95.5 96.8 98.1 99.4 103.6
Business Case Justification Narrative Template Version: February 2024 Page 7 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
I DiLuciano,Avista
Schedule 3,Page 141 of 535

DocuSign Envelope ID:244DBD63-018D-4BE3-A2BE-8265FA47DB79
Substation - Performance and Capacity
GRA12F2 73.5 76.1 79.1 81.9 84.5 87.5 90.5 93.4 96.4 99.6 102.9
PRA222 58.3 61.7 65.3 68.7 72.7 76.9 81.4 86.1 91.1 96.9 102.5
M15-XFMR#1 92.6 93.4 94.6 95.6 96.4 97.2 98.5 99.5 & 102.4
SIP12F2 61.5 64.3 67.6 71 74.7 78.5 82.5 87.1 91.6 96.2 101.6
PRV-XFMR#1 89.8 90.7 91.9 92.9 93.9 95 96.1 97.3 98.5 99.7 100.
L&S12F3 76.3 78.2 80.5 82.5 85 87.6 89.7 92.5 94.8 97.6b_jDOM
APW112 75 75.6 97 97.3 97.6 97.9 98.2 99 99.3 99.7 100
TUR-XFMR#2 70.8 73.4 76.1 79 82 84.8 87.7 90.6 93.6 96.8 99.9
SIP-XFMR#1 62.1 64.9 67.9 71.1 74.6 78.2 81.9 86.2 90.3 94.7 99.8
GRV-XFMR#1 87.2 88.2 89 90.1 91 91.9 93 94 94.9 94.9 97.1
LIB12F4 55.2 58.2 61.5 64.9 68.5 72.3 76.7 81.4 86.4 91.7 96.9
SOT-XFMR#1 74.6 76.6 78.5 80.7 82.7 84.8 87.2 89.5 91.7 94.1 96.6
CHW-XFMR#1 73.5 75.2 76.9 78.6 80.3 82 83.2 84.7 87 88.6 96.2
M15514 74.5 76.3 78.1 80.4 82.3 84.2 86.7 88.7 90.9 93.5 95.7
L&S12F2 72.3 74.4 76.3 78.5 80.9 83.3 85.3 87.8 90.5 92.7 95
CHW12F3 68.5 70.2 71.9 73.8 75.6 77.1 78.9 81.9 81.4 88.3 94.5
IDR253 68.6 71 73.4 75.5 77.7 80 82.4 84.9 87.4 90 92.7
SUN12F2 71.8 73.8 75.5 77.7 79.5 81.3 83.6 85.6 88 90 92.5
SIP-XFMR#3 91.8 91.8 91.8 91.8 91.8 91.8 91.8 91.8 91.8 91.8 91.8
ORO1282 72 74 75.6 77.3 79.4 81.1 83.3 85.2 87.5 89.4 91.8
OR-XFMR#1 66.9 69 71.2 73.3 75.4 77.6 80 82.5 84.8 87.5 90.1
NE12F1 58.4 61 63.4 66.2 69.1 72.1 75.3 78.6 82.1 85.7 89.5
EWN-XFMR#1 89.4 89.4 89.4 89.4 89.4 89.4 89.4 89.4 89.4 89.4 89.4
GRV1272 75.7 76.9 78 79.6 80.7 82 83.2 84.8 86.1 86.1 89.1
GIF-XFMR#2 59.7 61.9 64.4 67.1 69.6 72.6 75.7 79 81.8 85.3 89.1
SAG-XFMR#1 65.7 67.9 70 72.2 74.4 76.6 78.9 81.3 83.7 86.4 89
ROS12F2 71.1 72.5 74.3 75.8 77.7 79.3 81.2 82.9 84.9 87.1 88.8
3HT12F5 65.2 67.4 69.3 71.5 73.6 76 78.5 80.7 83.4 86.1 88.6
3HT12F7 63.1 65.5 67.6 69.8 72.4 74.8 77.2 80.1 82.7 85.8 88.5
SPL361 88.4 88.4 88.4 88.4 88.4 88.4 88.4 88.4 88.4 88.4 88.4
M15512 74.3 75.5 77.2 78.5 79.8 81.1 82.8 84.2 85.6 87 88.4
ODN-XFMR#1 69.5 71 72.2 73.6 75.2 76.7 78.7 80.7 82.8 85.1 87.8
MLN12F2 40.9 44 47.4 51 54.9 59.1 64 69.3 74.6 80.8 87.5
L&S-XFMR#1 69 70.5 72.2 73.9 75.7 77.5 79.3 81.4 83.1 85.2 87.3
PF211 47.4 50.4 53.7 56.8 60.5 64.4 68.1 72.5 77.1 82.1 87.3
DIA-XFMR#1 85.8 85.8 85.8 85.8 85.8 85.8 85.8 85.8 85.8 85.8 85.8
DAL131 67.2 69 70.5 72.1 73.7 75.7 77.3 79.1 81.2 83 85.2
C&W12F6 69.7 71.4 72.7 74 75.4 77.1 78.5 79.9 81.8 83.3 84.8
TVW131 51.6 54.3 56.8 59.8 62.5 65.8 69.2 72.4 76.2 80.1 84.3
SUN12F1 75 75.8 76.5 77.7 78.5 79.3 80.5 81.3 82.1 83.4 84.2
BEA12F2 67.6 68.9 70.7 72.1 73.5 75.4 76.9 78.5 80.4 82.1 83.7
CKF711 67.3 68.6 70.4 72.1 73.5 75.3 76.8 78.3 79.9 81.5 83.1
3HT12F4 80.6 80.7 80.8 81.3 81.4 82 82.5 82.6 82.7 82.9 83
SIP-XFMR#2 63.9 65.7 67.2 68.9 70.7 72.6 74.3 76.4 78.3 80.6 82.5
31HIT-XFMR#2 67.5 68.7 70 71.5 72.8 74.3 76 77.5 79 80.7 82.3
LOO-XFMR#1 77.5 77.9 78.4 78.8 79.3 79.6 80 80.5 80.9 81.5 82.2
SIP12F3 66.6 68.2 69.4 70.7 72.4 73.8 75.2 77.1 78.6 80.6 82.1
SPT4S21 47.5 50.3 53 56.1 59.3 62.2 65.6 69.4 73.4 77.5 81.9
MEA12F1 65 66.6 67.9 69.2 70.9 72.7 74.2 76.1 77.6 79.6 81.3
LIB12F1 80.6 80.6 80.6 80.6 80.7 80.7 81.1 81.1 81.1 81.1 81.2
ROS12F3 54.4 56.7 58.8 61.3 63.8 66.2 68.9 71.8 74.4 77.6 80.8
C&W12F2 73.5 74.5 75.1 75.7 76.4 77 78 78.7 79.3 80 80.6
NE-XFMR#2 56.7 58.7 60.9 63 65.1 67.3 69.7 72.2 74.8 77.7 80.3
SE12F2 80.2 80.2 80.2 80.2 80.2 80.2 80.2 80.2 80.2 80.2 80.2
SLW1368 57.4 59.1 61.2 63 65.3 67.3 69.7 71.9 74.6 77.3 80.2
MIS-XFMR#1 80.1 80.1 80.1 80.1 80.1 80.1 80.1 80.1 80.1 80.1 80.1
CHW12F2 61.1 62.8 64.6 66.3 67.9 69.8 71.8 73.7 75.7 77.7 80.1
Business Case Justification Narrative Template Version: February 2024 Page 8 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
I DiLuciano,Avista
Schedule 3,Page 142 of 535

DocuSign Envelope ID:244DBD63-018D-4BE3-A2BE-8265FA47DB79
Substation - Performance and Capacity
1.2 Discuss the major drivers of the business case.
The Substation — Performance and Capacity business case primary driver is Performance and
Capacity. The identified problem being addressed by the proposed solution is inadequate
distribution substation capacity to serve expected customer demand. Capacity is generally
quantified through system planning engineering analysis showing utilization percentage of
applicable facility ratings. Providing an electric system with sufficient capacity to meet customer
demands will allow equipment to be operated within designed limits while maintaining service
to customers.
A secondary driver of the business case is Asset Condition. Some mitigation alternatives include
adding capacity at existing distribution substations which may require the replacement or
upgrades to the existing equipment in the substation. Justification to replace the existing
equipment may not be prudent based only on the condition of the asset. When replacing the
equipment to address capacity issues, the potential asset condition issues will be addressed.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The risk of not approving the business case or deferring the requested capital funds will lead to
insufficient distribution system capacity to adequately serve customer demand. The 2021 Heat
Wave, see Heat EOP Event Analysis report, is an example of past observed system
performance where customer's power was turned off due to, in part, inadequate system
capacity. In some instances, deferring proposed capacity projects may not lead to immediate
performance issues but it will create an engineering, construction, and capital resource
constraint in future years as the necessary projects will still be needed.
This business case is an ongoing program of multi-year substation projects that are at all stages
of construction (Initiation, Planning, Execution and Closeout). This business case serves as the
umbrella for all projects within Substation Engineering that have a primary driver of Performance
and Capacity.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strateizic Goals
The Substation— Performance and Capacity business case provides additional capacity to the
system which is "critical to serving our customers well and unlocking pathways to growth." The
Perform Focus Area of Avista's focus goals is the primary alignment with the requested projects
but there are elements to the projects which are aligned with the theme of our Vision, Mission,
and Focus Areas.
Our Customers:
Existing and future customers expect to have electrical service.Avista needs to deliver a system
which can serve the customer demands and continue to meet the company's defined reliability
objectives.
Our People:
The portion of our company who will support the implementation of the projects represents a
core electric utility collection of our employees. These employees will take pride in the effort of
adding infrastructure to the electric system to meet the needs of our customers.
Perform:
With completion of the projects, Avista will be unlocking growth potential in the areas of each
project.
Business Case Justification Narrative Template Version: February 2024 Page 9 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 143 of 535

DocuSign Envelope ID:244DBD63-018D-4BE3-A2BE-8265FA47DB79
Substation - Performance and Capacity
Vision; Better energy for life:
Investment in the electric distribution system represents a long-term investment of infrastructure
which will be in place to serve our customers for several generations.
Mission: We improve our customers' lives through innovative energy solutions.
Distribution substation capacity projects are needed to meet the demands of our customers.
Customer's livelihoods depend on the electrical services we provide.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.2
A comprehensive evaluation of the distribution system adequacy is performed bi-annually as
part of the System Assessment process. Documentation of the results is provided in the System
Assessment.The most recent document is the 2023-2024 System Assessment Version 0(2023-
2024 Avista System Assess ment-VO.pdf). The tables provided in Section 1.1 above provides
the observed performance issues. The 2023-2024 System Assessment incorporated
improved statistical evaluation of peak loading conditions and improved modeling
accuracy utilizing additional distribution planning engineers therefore additional
capacity issues have been identified compared to previous assessments.
A list of mitigation projects provided in the 2021-2022 System Assessment associated with this
business case includes:
• Bronx Station Rebuild - Reconstruct existing Bronx Station to include
distribution facilities with a 20MVA transformer and two distribution feeders.
The 115kV portion of the station will include two 115kV transmission line
positions protected with circuit breakers and configuration suitable for future
expansion.
• Poleline (Prairie) Station Rebuild - Construct new distribution station to
replace Avista facilities at existing Prairie Station. New station to include two
30MVA transformers, four feeders, and looped-through transmission line.
• Valley Capacity Mitigation— Rebuild existing Valley Station with increased
distribution capacity.
• Pleasant View Capacity Mitigation-Rebuild existing Pleasant View Station
with increased distribution capacity.
• North Spokane Distribution Reinforcement (Northeast) - Replace two
existing 20MVA transformers with 30MVA transformers and add new
NE12F6 feeder. Transformer circuit switchers replacements are included in
scope to eliminate existing fault blocking scheme. Distribution integration
scope includes new switches and an express feeder truck.
• Orin Capacity Mitigation - Construct new distribution station connected to
BPA's Colville— Republic 115kV Transmission line. New station will include
a single 20MVA transformer and two distribution feeders.
• Glenrose Capacity Mitigation - Replace existing transformer with 30MVA
and rebalance feeders. Regulator upgrades assumed to be an existing flex
crew project.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2024 Page 10 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 144 of 535

DocuSign Envelope ID:244DBD63-018D-4BE3-A2BE-8265FA47DB79
Substation - Performance and Capacity
• Bunker Hill Customer Capacity-Install new 20MVA transformer to replace
existing transformer and construct new dedicated customer distribution
feeder.
• Melville Station - New switching station near existing tap to Four Lakes
Station off the South Fairchild Tap 115kV transmission line. Construct new
transmission line from Airway Heights to Melville including passing through
Russel Road and Craig Road distribution stations. Requires new
transmission line terminal at existing Airway Heights Station.
• North Spokane Transmission Reinforcement (Five Mile 115kV Station)
— Construct new Five Mile Station with new loop through of Nine Mile -
Westside 115 requiring 3 miles of new 115 line. New BPA interconnection at
Bell Station to create a Bell — Five Mile 115 line using 1.5 mile of new line
and portion of Beacon - Francis & Cedar 115 line. New Francis & Cedar —
Five Mile line using 1.5 mile of new line.
• Midway Station — Construct new distribution station to include 30MVA
transformer and two distribution feeders. Each individual performance issue
and associated project is reviewed and prioritized by the Engineering
Roundtable.
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The business problem identified is inadequate distribution system capacity to serve customers.
The proposed solution is to programmatically fund substation projects to add capacity to the
system. Specific capacity deficiencies and mitigation projects will be identified by System
Planning in coordination with internal and external stakeholders. The Engineering Roundtable
will review and prioritize each project. Substation projects which require capacity upgrades or
new distribution substations are proposed to be funded through the Substation — Performance
and Capacity business case. Historically funding levels in the business case has generally
resulted in approximately one substation project per year. When specific projects are better
understood in funding years 1-3, actual cost estimates are used for the funding request.
Implementation of the proposed solution will strategically add capacity to the system to mitigate
the issues identified in the 2023-2024 System Assessment. Each project under this program will
require planning and operational studies,justifications, and project reports prior to funding.
Business Case Justification Narrative Template Version: February 2024 Page 11 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 145 of 535

DocuSign Envelope ID:244DBD63-018D-4BE3-A2BE-8265FA47DB79
Substation - Performance and Capacity
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).3
Study reports prepared by System Planning can be referenced for the Substation—Performance
and Capacity business case. An example of work includes:
•2023-2024 System Assessment—Version 0, 2023
• Heat EOP Event Analysis—Version 0, 2021
• Poleline(Prairie)Substation Rebuild Project—Version 0, 2023
• Northeast Capacity Mitigation—Version A, 2023
• North Spokane Distribution System Analysis—Version 0, 2023
•Orin Capacity Mitigation Project—Version A, 2023
•Glenrose Capacity Mitigation—Version A, 2024
• Bunker Hill Mine Load Addition—Version 0, 2022
• North Spokane Transmission Reinforcement Study—Version 0,2024
Individual project documentation is under development for project not included in the above
listed reports. Each project report will include detailed study results showing how the project will
mitigate identified capacity issues.
2.3 Summarize in the table and describe below the DIRECT offsets4 or
savings (Capital and OW) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
No direct offset or savings are expected as a result from this investment. Having the right amount
of backup capacity in each area is critical for the continued appropriate management of the
electric system. Any direct savings would be offset by direct costs due to more stations to
inspect, test and maintain. Some savings will be seen with SCADA being extended to about 40
substations over the next several years—this will benefit our wildfire prevention efforts, quicker
outage remediation and general maintenance needs. [Reference 2022-2023—TTP Forecast by
BC by Director for Offset Exercise-Final]
Annual O&M costs for a distribution substation is approximately$30,000.Annual O&M costs for
a transmission substation is approximately$50,000.
3 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
4 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2024 Page 12 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 146 of 535

DocuSign Envelope ID:244DBD63-018D-4BE3-A2BE-8265FA47DB79
Substation - Performance and Capacity
2.4 Summarize in the table and describe below the INDIRECT offsets5
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
No indirect capital or O&M offsets are expected to result from this investment. Adding SCADA
to substations means more data collected about the substation which will require more
personnel to analyze and manage the data. Adding new substations to the electric system will
require additional GPSS personnel (Batterymen, Servicemen, and general staff)to inspect, test
and maintain the new substations plus Substation Engineers to manage the compliance and
maintenance requirements for these new substations. [Reference 2022-2023 — TTP Forecast
by BC by Director for Offset Exercise-Final]
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, which were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Each individual project funded by this business case includes evaluation of project alternatives.
Alternatives may include alternate substation expansion projects, expanding existing substation
capacity, constructing new substations, potential targeted demand side management,
installation of utility scale battery systems, and feeder loading optimization through phase
balancing and load transfers to adjacent facilities.
With a programmatic business case, reasonable alternatives to consider are narrowed to
variation in funding levels. Under funding the business case from the requested amount will
result in the deferral of addressing the identified performance issues. Continual deferral of
projects will result in a compression of needed funding in future years.
Alternative 1:
Do not adequately fund new distribution substation capacity projects. $Unknown
Alternative 2:
Fund two performance and capacity substation projects per year on average. $25 million/year
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
Successful mitigation of the problem statement will be monitored as part of the bi-annual System
Assessment conducted by System Planning. The project(s) will be successful if performance
criteria in short-term planning horizon studies can be met, and performance issues are not
5 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2024 Page 13 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 147 of 535

DocuSign Envelope ID:244DBD63-018D-4BE3-A2BE-8265FA47DB79
Substation - Performance and Capacity
observed in the operations time horizon. Assumptions made in System Assessments are not
static therefore projects are developed based on the best information available. For example,
future load forecasts may show additional load growth not expected when a project is requested.
If the project takes ten years to construct, it is possible the base line assumptions have changed,
and additional projects will need to be justified.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
This is an ongoing business case. New projects are being scoped and initiated while complete
projects are constructed and in closeout.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
The Engineering Roundtable will provide technical review of potential scope changes with the
support of the System Planning and Operations department. Scope changes which require
additional fund requests to the Capital Planning Group will be vetted at the Engineering
Roundtable. Substation Engineering and Engineering Project Delivery will manage the projects
with a project team consisting of a Project Manager, Lead Electrical Engineer, a Lead Civil
Engineer, and many others that support the project.
Business Case Justification Narrative Template Version: February 2024 Page 14 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 148 of 535

DocuSign Envelope ID:244DBD63-018D-4BE3-A2BE-8265FA47DB79
Substation - Performance and Capacity
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Substation—Performance and Capacity and
agree with the approach it presents. Significant changes to this will be coordinated with and approved
by the undersigned or their designated representatives.
DocuSigned by:
Signature: Date: May-03-2024 1 8:57 AM PDT
Print Name: c4012gpf�jf�elh.ain
Title: Manager, Substation Engineering
Role: Business Case Owner
DocuSigned by:
Signature: U�,VIn, ws� Date: May-03-2024 1 2:06 PM PDT
Print Name: 06c4FV fft..1ensky
Title: Director, Electrical Engineering
Role: Business Case Sponsor
DocuSigned by:
Signature: Date: May-03-2024 1 8:52 AM PDT
Print Name: 0304i3RAgffl6vlandenburg
Title: Manager, Engineering Projects
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2024 Page 15 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 149 of 535

DocuSign Envelope ID:4F15503D-7BE4-412E-B384-4043D60CC76D
Substation - Failed Plant
EXECUTIVE SUMMARY
The Substation — Failed Plant Business Case is focused on restoring Avista's substation systems into
serviceable condition after equipment fails due to animal `contact', lightning, or other sudden equipment
failure. These equipment failure events are random and cannot be planned. This business case is to fund
a rapid response to unexpected damage, so customer outages are minimized. In the past, these
replacements were completed under the Substation—Asset Condition Business Case, but better overview
and tracking is desired by Electrical Engineering and the decision to create a separate business case to
encourage better knowledge of how many substation equipment failures occur and any possible equipment
manufacturer/model issues. Future maintenance practices and programs will also be reviewed in light of
these equipment failures. The importance of quickly replacing damaged equipment is vital to supplying
reliable service to our customer. This affects electrical customers in Washington, Idaho and Montana.
The annual budget amount is determined based on the historical average of capital substation equipment
replacements. For the first three years, this rate will include non-failure projects since all replacements are
under the Asset Management ER in the Substation — Asset Condition Business Case. Budget requests
include all substation equipment types except Auto and Power Transformers. Large transformer failures
are rare and when they occur, special budget requests will be made to the Capital Project Group.
These emergency projects were previously funded through the Substation—Asset Condition business case.
VERSION HISTORY
Version Author Description Date
1.0 K Kusel/ Initial draft of original business case 0412024
B Chain
DS
BCRT Steve Carrozzo Has been reviewed by BCRT and meets necessary requirements
Business Case Justification Narrative Template Version: February 2024 Page 1 of 7
Exhibit No. 10
Case Nos.AW-E-25-01iAVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 150 of 535

DocuSign Envelope ID:4F15503D-7BE4-412E-B384-4043D60CC76D
Substation - Failed Plant
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT($)
2025 $2,000,000 $2,000,000
2026 $2,000,000 $2,000,000
2027 $2,000,000 $2,000,000
2028 $2,000,000 $2,000,000
2029 $2,000,000 $2,000,000
Project Life Span Ongoing
Requesting Organization/Department Substation Engineering
Business Case Owner Sponsor Brian Chain Vern Malensky
Sponsor Organization/Department Electrical Engineering
Phase Execution
Category Program
Driver Failed Plant& Operations
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
This Business Case is focused on restoring Avista's substation system into serviceable
condition when sudden equipment failures occur. These events are random and cannot be
planned. This business case funds a rapid response to unexpected damages so customer
outages are minimized. This business case provides funds for replacing air switches, circuit
breakers, voltage regulators, transformers, station batteries, bushings, relays and other defined
substation retirement units. Equipment failures can be caused by lightning strikes, animal
`interference' and operational failure.
1.2 Discuss the major drivers of the business case.
The primary driver for this business case is Failed Plant and Operations. The work is a key
component to minimizing customer outage times and contributes to Avista's reliability.
In the past,failed substation equipment replacements were funded under the Substation—Asset
Condition business case (under ER 2215) which included all small substation projects (i.e.,
voltage regulator upgrades, low voltage breaker upgrades). With the shift of creating business
cases that focused on primary drivers, it made sense to break out Failed Plant capital projects
to their own business case. This move will provide clarity to see how many emergency/failed
plant projects are completed annually and separate this work from other projects. This
information could provide information for better equipment maintenance programs.
Business Case Justification Narrative Template Version: February 2024 Page 2 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 151 of 535

DocuSign Envelope ID:4F15503D-7BE4-412E-B384-4043D60CC76D
Substation - Failed Plant
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
This program business case is needed to provide quick replacement of failed substation
equipment. If this work is not approved or deferred,the cost of replacement will be absorbed by
another business case. The needed work will continue to occur, it will simply be hidden within
other types of substation work.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization.
This business case focuses on `Our Customers' and `Perform' focus areas. While we cannot
completely avoid customer outages, this business case supplies immediate funding to allow for
quicker equipment replacements and shorter customer outages. Being able to study substation
equipment failures and finding better ways to design and maintain substations in the future is
key to better performance.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
Funding requests are based on average failure costs across all substation equipment types
excluding power and auto transformers. Large substation transformer failures are rare and
expensive, a capital budget request will be completed if a transformer fails. As it's not possible
to completely predict when a substation asset will fail, funding requirements could change and
may result in an increase or decrease in annual funding amounts.
Substation Equipment Replacements
$8,000,000
$7,000,000
$6,000,000
$5,000,000
$4,000,000
$3,000,000
$2,000,000
$1,000,000
$0
2014 2015 2016 2017 2015 2019 2020 2021 2022
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2024 Page 3 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 152 of 535

DocuSign Envelope ID:4F15503D-7BE4-412E-B384-4043D60CC76D
Substation - Failed Plant
The above figure includes dollars spent annually to replace all types of substation equipmnet.
This includes the North Lewiston Auto Replacement project (2021-2022 and theMoscow Auto
Replacement project(2022-2023))both auto transformers failed in service and where replaced.
Substation Equipment Replacements
$2,500,000
$2,000,000
$1,500,000
$1,000,000
$500,000
S,,
2014 2015 2016 2017 d01, 2019 2020 2021 2022 ._._
The above figure shows the total dollars spent per year for all types of substation equipment
except auto transformer. This shows a more true year over year cost of substation equipment
failure dollars spent.
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
This Business Case is focused on restoring Avista's substation system into serviceable
condition when sudden equipment failures occur. These events are random and cannot be
planned. This business case funds a rapid response to unexpected damages so customer
outages are minimized. This business case provides funds for replacing air switches, circuit
breakers, voltage regulators, transformers, station batteries, bushings, relays and other defined
substation retirement units. Equipment failures can be caused by lightning strikes, animal
`interference'and operational failure.
Business Case Justification Narrative Template Version: February 2024 Page 4 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 153 of 535

DocuSign Envelope ID:4F15503D-7BE4-412E-B384-4043D60CC76D
Substation - Failed Plant
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
The annual budget amount is determined based on the historical 5-year average costs of failed
substation equipment. If more or less dollars are needed during a fiscal year, a mid-year budget
request or giveback will be requested.
For this initial funding, data from 2014 through 2023 was reviewed and $2,000,000 was decided
as a good first year budget.
2.3 Summarize in the table and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital N/A N/A N/A N/A N/A N/A
O&M N/A N/A N/A N/A N/A N/A
There is no direct offset in this business case. Not funding failed equipment replacement would
result in the replacement being funded from a different business case.
2.4 Summarize in the table and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital N/A $ $ $ $ $
O&M N/A $ $ $ $ $
There are no offsets to O&M. All substation failed plant work are like kind replacements and
cause no change to O&M costs.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2024 Page 5 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 154 of 535

DocuSign Envelope ID:4F15503D-7BE4-412E-B384-4043D60CC76D
Substation - Failed Plant
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, which were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
The alternative to this business case request is not funding.The costs associated with replacing
failed substation equipment would be covered through a different business case. Failed
equipment has to be repaired, regardless of which business case they are funded from.
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
This business case is created to align with Avista's style of primary drivers. Knowledge of small
substation equipment projects vs other primary drivers (performance & capacity, mandatory &
compliance, etc.)will show the need (or lack of)for asset management programs.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
This business case is a program that transfers to plant as each project is completed. This varies
from 1 month to several months depending on the equipment type. The Substation Engineering
Manager will review the costs monthly to decide if budget adjustments are needed.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
Substation Engineering Manager: Owner of Substation — Failed Plant business case. Reviews
monthly spend and makes budget decisions.
Electrical Engineering Director: Owner of Expected Spend meeting held monthly. Reviews the
monthly spend of all business cases sponsored by the EE department.
Business Case Justification Narrative Template Version: February 2024 Page 6 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 155 of 535

DocuSign Envelope ID:4F15503D-7BE4-412E-B384-4043D60CC76D
Substation - Failed Plant
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Substation - Failed Plant business case and
agree with the approach it presents. Significant changes to this will be coordinated with and approved
by the undersigned or their designated representatives.
DocuSigned by:
Signature: Date: May-02-2024 1 7:15 AM PDT
Print Name: c4012FS 4Chain
Title: Manager, Substation Engineering
Role: Business Case Owner
DocuSigned by:
Signature: �ra�.cG�� Date: May-03-2024 1 1:45 PM PDT[t�nA.
Print Name: 06c4FF@4a,4alensky
Title: Director, Electrical Engineering
Role: Business Case Sponsor
Business Case Justification Narrative Template Version: February 2024 Page 7 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 156 of 535

Wood Pole Management
EXECUTIVE SUMMARY
Asset Management and Distribution Engineering provided the analysis of Avista's distribution
assets and their condition. This analysis is used to direct the Wood Pole Management (WPM)
work that includes inspecting and maintaining Avista's poles, hardware, and equipment on a
twenty-year cycle. This analysis is documented in the 2017 Wood Pole Management Program
Review and Recommendations. It is reiterated in the Avista Utilities Electric Distribution
Infrastructure Plan June 2017, and the 2021 Wood Pole Management (Distribution) Inspection
Cycle Analysis. The reports are in the Qc01 m570) drive under Wood Pole Management. In 2021
WPM changed the cycle for feeders in high fire risk areas to seventeen- years for the next ten-
years to help ensure poles are inspected and failed assets replaced before Grid Hardening
Programmatic work occurs. The seventeen-year cycle analysis is discussed in the Wood Pole
Management (Distribution) Inspection Cycle Analysis. Asset Maintenance manages and tracks
the work, budget, and schedule. The major drivers for the program are system reliability, improved
cost performance, and increasing customer reliability. These drivers are achieved by replacing
defective poles, associated hardware, and equipment when the condition of the asset requires
replacement. The National Electric Safety Code (NESC) is adopted as Washington Law under
WAC 296-45-045. Part 013C of this code describes the application, Part 121 defines the
inspection interval, and Part 214 details documentation and correction of the pole inspection
results. We have also communicated to our insurance carrier Aegis that we are committed to
staying on cycle and completing the work in a timely manner.
WPM work encompasses Avista's electric distribution overhead facilities in Washington, Idaho,
and Montana. In order to maintain a seventeen-year cycle for the next ten years, approximately
13,000 poles need to be inspected and follow-up work completed annually. The work plan was
developed to complete 66% of the poles in the State of Washington and 34% of the poles in the
State of Idaho each year. The average cost to replace defective poles, crossarms, equipment,
and hardware is $1334/pole on a feeder basis, whether work is required or not. To stay on a
seventeen-year cycle requires $17,342,000 per year which also benefits the Grid Hardening
efforts by replacing identified defective assets before they complete their work. A portion of the
funding is under the WPM-GH Make Ready budget. The combined WPM and WPM-GH Make
Ready budget for 2024 is $16,000,000. Our customers benefit from this combined program by
reducing unplanned outages, replacing assets under capital funding, and increasing safety for our
line workers and the public. The risk of not approving this Business Case means we will run our
facilities in a run-to-failure mode as identified rejected assets are not replaced in a timely manner,
safety for our line hands and the public would decrease, and our Operating and Maintenance
Costs would increase.
Business Case Justification Narrative Template Version: February 2023 Page 1 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 157 of 535

Wood Pole Management
VERSION HISTORY
Version Author Description Date
1.0 Mark Gabert Final Draft of opi onal business case 7/31/2020
2.0 Mark Gabert Business Case Refresh 8/31/2022
3.0 Mark Gabert Business Case Refresh 4/14/2023
4.0 Mark Gabert Business Case Refresh 4/5/2024
BCRT Team Member
BCRT _Katie Snyder Has been reviewed by BCRT and meets necessary requirements 04/21/2023
BCRT Team Member
BCRT —Katie Snyder Has been reviewed by BCRT and meets necessary requirements 0510812024
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2024 $13,000,000 $13,000,000
2025 $13,000,000 $13,000,000
2026 $17,342,000 $17,342,000
2027 $18,902,780 $18,902,780
2028 $19,469,863 $19,469,863
2029 $20,053,958 $20,053,958
Project Life Span Ongoing
Requesting Organization/Department M51
Business Case Owner I Sponsor Mark Gabert-Heather Webster- Paul Good
Sponsor Organization/Department Operations
Phase Execution
Category Program
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
The Wood Pole Management (WPM) program historically inspected and maintained the
distribution wood poles on a twenty-year cycle and the transmission poles on a fifteen-year
cycle. In 2021 we moved the distribution inspection cycle for feeders in high fire risk areas
Business Case Justification Narrative Template Version: February 2023 Page 2 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 158 of 535

Wood Pole Management
to a seventeen-year cycle to support the Grid Hardening work plan. Avista has
approximately 227,000 distribution poles, and to meet the seventeen-year cycle,
approximately 13,000 poles need to be inspected annually, including associated
replacement work. Approximately 26 percent of the poles are older than 60 years of age
which will increase over time. The Mean Time to Failure (MTTF)for wood poles is seventy-
nine years, but Distribution Engineering recommends replacement at sixty years of age due
to the time element of the next cycle and the above-groundline decay characteristics of butt-
treated wood poles. Because our poles are not full length treated, they are more susceptible
to pole top decay. Currently, we only replace poles that fail the inspection process and do
not use age as the criteria for replacing poles under the Wood Pole Management budget. If
we used age and pole failure as a guideline it would require a significant increase in
budgeted funding.
Along with inspecting poles, WPM visually inspects distribution transformers, cutouts,
insulators, wildlife guards, lightning arrestors, cross arms, guying, and pole grounds. The
average asset life of this equipment is fifty-five years and requires replacement along with
the pole work. The inspections document the asset condition and indicate what assets
should be replaced. The asset condition is observed and documented during the pole
inspection process as described in S-622 Specification for the Inspection of Poles. This
document can be found in the (\\c01 m570) drive under Wood Pole Management. Designs
and work plans are then created to replace the assets that fail the inspection process. The
construction work to replace the assets is also part of this program.
1.1 What is the current or potential problem that is being addressed?
Across Avista's service territory, wood poles are exposed to a variety of environmental
conditions which impact their condition. Over time, these poles deteriorate at different rates.
In order to maintain safe and reliable operation of the system, these poles need to be
periodically tested to determine if they should be replaced or can remain in service. The
Wood Pole Management program was developed to mitigate this. The program addresses
and reduces issues such as outages, safety risks, and unplanned maintenance by
proactively maintaining the wood poles that are at the end of their useful life. This is
accomplished by inspecting, documenting, and maintaining our overhead facilities in a
useful condition on a twenty-year cycle. This also keeps our poles, equipment, and hardware
safe for employees and the general public while maintaining a high level of customer service
and reliability. To aid in Grid Hardening efforts, Wood Pole Management changed feeders
in high fire risk areas to a seventeen-year reinspection cycle. The decreased inspection
cycle enables Grid Hardening to complete its work by replacing poles with the potential for
failure ahead of Grid Hardening construction, which is more efficient. However, if Wood
Pole Management is underfunded, it will push some feeders past the seventeen-year cycle
which may impact the Grid Hardening Program. In addition, if Wood Pole Management is
not adequately funded, the company will move toward managing the overhead distribution
assets as they fail, which increases both safety and reliability risks.
1.2 Discuss the major drivers of the business case.
From an asset condition perspective, the major drivers for the Wood Pole Management
Program include safety, system reliability, improved cost performance, reduced customer
outages/increased reliability, and decreased fire risk. This program also has a mandatory
Business Case Justification Narrative Template Version: February 2023 Page 3 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 159 of 535

Wood Pole Management
and compliance component to it because the National Electrical Safety Code (NESC) is
adopted as Washington Law under WAC 296-45-045. Part 013C of the code describes the
application, Part 121 defines the inspection interval, and Part 214A details documentation
and correction of the pole inspection results.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The work is required now to keep pace with Avista's aging critical assets and expected
failure rates as our infrastructure gets older.
Approximately 26 percent of Avista's poles are older than 60 years of age, which is
continually increasing over time. The Mean Time to Failure (MTTF) for wood poles is
seventy-nine years, but Distribution Engineering recommends that poles should be
considered for replacement at sixty years of age due to the time element of the next cycle
as well as the above groundline decay characteristics of butt-treated wood poles. Figure 1
below shows the increased rate at which the poles are reaching the seventy-nine-year end
of life. If this work is not maintained, this aging infrastructure will cause an increasing number
of failures, leading to increased outages and higher construction costs. It is much more
expensive to respond to an asset failure than replacing it under a planned capital program.
In addition to the risks of fires, outages, and failures with the aging equipment, the additional
risks associated with this program pertain to the following:
Environmental: Risks include potential large volume transformer oil spills, difficult and
expensive hazardous waste cleanup, impact to waterways, and repeated or moderate air
emission exceedance. According to the 2017 Wood Pole Management Review and
Recommendations, if the program is unfunded the potential occurrence is greater than four
spills per year. If funded, the potential occurrence is projected at less than one in fifty years.
Public Safety and Health: Risks include the potential for serious injury for crews or the
public, significant damage to equipment, property of businesses, and public health
infrastructure impacts of up to forty-eight hours. If the program is unfunded, the potential
occurrence is projected at less than one per ten years. If funded, the potential occurrence
is projected at less than one in fifty years.
Figure 1.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 160 of 535

Wood Pole Management
Avista Distribution Wood Pole Percentage by Age
1901-2023
3.0%
c
2.5%
M
a
CO 2.0%
v
00 1.5%
4-
0
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t-I Ol m rl a r- 0 M tD M N N W H It r- 0 M 0 M N 0 W H It r- 0 M 0 M N 0 W H
o e•i N N m m m It v a It 0 N 0 0 0 0 N n r- n w W W M M M 0 0 0 0 H H H N
m m m m m m m m m m m m rn m m m m m m m m rn m m m m m 0 0 0 0 0 0 0 0
t-1 e•i rl rl rl rl ci c-I rl ei c-I rl ei rl ei rl rl e-I t-I rl c-I t-1 e•i c-I t-1 c-I t-1 N N N N N N N N
Year of Installation
Figure 1: Avista Distribution Wood Pole Percentage by Age
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization.
The link below shows Avista's strategic goals (current at the time of finalizing this version
of the business case.
Avista Strategic Goals
This investment replaces end of life assets before they fail, which reduces outages and
improves safety and reliability. By delivering safe reliable electric service, we improve the
lives of our customers by avoiding unnecessary interruptions in their daily lives. The Wood
Pole Management Program most closely aligns with Avista's focus area "Our Customers"
as it focuses on improving reliability and keeping rates affordable to our customers.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
The Outage Management Tool (OMT) is used to track asset condition and show trends of
failure for specific equipment that should be targeted for replacement. This information is
also used to track key program performance as shown in Table 1 below. The number of
outage-type events has been reduced by 37% from 2009 to 2023. This reduction in outage
events results in significant customer benefit. The reduction also demonstrates increased
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 161 of 535

Wood Pole Management
reliability and safety along with a reduction in outages. The original goal for this program
was to stay below the number of events averaged over 2005-2009 for WPM Related OMT
events (1460). This goal will be re-evaluated by Asset Management in the future.
WPM Goal Related
. •. •.
"' 1460 1118 11,400 11,548
1460 799 11,400 12,010
1460 804 11,400 10,461
1460 817 11,400 14,530
1460 628 11,400 10,763
1460 727 11,400 10,588
1460 863 11,400 12,018
1460 579 11,400 13,244
1460 714 11,400 12,996
1460 632 11,400 11,532
1460 623 11,400 10,902
1460 577 11,400 8,694
1460 731 13,116 11,404
1460 706 13,116 10,000
1460 701 13,116 11,775
Table 1: Outage event summary from OMT
The type of OMT events are broken down into more detail in Figure 2. Note there are
significant improvements to some events, such as squirrels, reducing on average from 672
in 2009 to 325 events in 2023. This improvement has been realized by adding wildlife
guards to the top of the transformer bushings to prevent squirrels from touching exposed
power connections which can result in outages. Transformer events have been reduced by
50% and cut out/fuse related events are also down about 30% since WPM began due to
the replacement of aged equipment. Approximately twelve years ago Avista moved to using
fiberglass cross arms which is beginning to reduce the average annual number of pole top
fires. This reduction should accelerate as Grid Hardening began replacing wood cross arms
with fiberglass cross arms in high-risk WUI areas in the second half of 2019. As an indication
of the effectiveness of this action, pole fires are down about 30%.
In 2017 the calculated cost to customers for a pole failure was$24,400 based on an average
duration of 4.8 hours for 80 customers. The combined cost impact to customers in 2015
alone for those events was $2,265,600.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 162 of 535

Wood Pole Management
Wood Pole Management Events
350
300
250 —
o 200 —
0
v 150
100
z
50 I Ii, `. ■
0
ey,ec e� QJ�e oc tQ\� Fite e� `t�eXX
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■2019 2020 2021 2022 2023
Figure 2: Break down of Wood Pole Management Impacted OMT events
Ultimately the impact of this Program can be associated with our Electric Systems Reliability
metrics. The System Average Interruption Frequency Index (SAIFI) represents the average
number of sustained interruptions per customer for the year across Avista's entire system.
Avista reported a SAIFI score of .79 for the year 2022. The Asset Management group
created Figure 3 below to show the impact of this Program to our overall SAIFI score. The
predicted contribution is about 0.211, which has a significant impact on the customer,
whereas the contribution to SAIFI would be 0.57. This means the customer would
experience 0.36 more outages per year without WPM. Without WPM, the contribution to
SAIFI would be 1.27 (hours).
Business Case Justification Narrative Template Version: February 2023 Page 7 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 163 of 535

Wood Pole Management
OMT-Related Outages Over Time
30%
25%
20%
15%
Trend/in,
100/0
5%
0%
2005 2007 2009 2011 2013 2015 2017 2019 2021 2023
Figure 3:Wood Pole Management impact to SAIFI score
WPM is an ongoing cyclical program that proactively replaces assets identified for
replacement during the inspection process. By replacing assets before they fail, outages
are reduced, and replacement costs are reduced through planned versus emergency work.
Investing in our infrastructure increases life-cycle performance and is cost-effective using
unit-based pricing. Figure 4 below shows the significant improvement in "events per mile
of feeder" resulting from this program before and after WPM work. The peak of events per
mile shown in the graph is from 2011 when there were nearly .3 events per mile. The results
after the program show performance as low as .1 events per mile of feeder, a significant
improvement.
If funding were to be reduced, expected outages would increase. The team would then need
to prioritize which components would be replaced and which would be left as run-to-fail.
This would increase the likelihood that crews would need to visit the same pole later if a
remaining component were to fail, thereby increasing operating expenses.
The program's documentation and analysis are in several published documents. The
documents are the 2017 Wood Pole Management Program and Review, The Electric
Distribution Infrastructure Plan June 2017, Structure Specific Distribution Feeder
Management Plan, and the Wood Pole Management (Distribution) Inspection Cycle
Analysis January 2021, which are located on the (\\c01 m570) drive and available upon
request.
Business Case Justification Narrative Template Version: February 2023 Page 8 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 164 of 535

Wood Pole Management
Average WPM Related Sustained Outage Events per Mile Before and After
WPM Work Completed
v
v
w �Year WPM LL • completed
0 0.300
0.250
a
r
v 0.200 p
W
o
m g 0.150 �+
3
w 0.100
.Y
(A 0.050 0 '
w 7C
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- = 10
Number • • •
aNumber of ' Work
3 Completed
Average WPM Related Event per Mile
Figure 4: Sustainted outage events per mile before and after Wood Pole Management
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The proposed solution is a Wood Pole Management program with the goal of identifying
defective overhead facilities in need of replacement before they fail to maintain our
facilities in a safe, responsible, effective, and reliable manner. The proposed solution
is to inspect and address poles on a 20-year cycle except for Grid Hardening feeders
which are on a seventeen year cycle until approximately 2030.
The current twenty-year cycle delivers the best life cycle value for the funding level.
More work on a shorter schedule would increase the cost of this program, less work
would lead to increased failures and resulting outages.
Business Case Justification Narrative Template Version: February 2023 Page 9 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 165 of 535

Wood Pole Management
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits, or risk estimates; description of how
benefits to customers are being measured; metrics such as comparison
of cost ($) to benefit (value), or evidence of spend amount to anticipated
return).2
This information/analysis is documented in the "2017 Wood Pole Management
Program Review and Recommendations" located on the (\\c01 m570) drive.
In summary, the Asset Management analysis recommended continuing with the twenty
-year cycle for the Wood Pole Management Program. They did examine several
different alternatives and some do provide a little more value, but they would potentially
require very significant capital costs well beyond current budget levels.
The Wood Pole Management program supports our Safe & Reliable Infrastructure
strategy. Specifically, Wood Pole Management strives to invest in our infrastructure to
achieve optimum life-cycle performance safely, reliably, and at a fair price. The program
meets the objective by providing the best customer internal rate of return that will fit
within our Capital and Operations and Maintenance budget constraints.
2.3 Summarize in the table and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M Quantified Direct $1,284,500 $1,284,500 $1,284,500 $1,284,500 $1,284,500
Savings
Between 2005-2009 the average number of OMT events related to Wood Pole
Management was 1460 per year. Between 2018 and 2023 the average number of OMT
events has been reduced to 734 per year. This is an average reduction of 726 OMT
events per year related to WPM work. The average OMT event takes 3.5 hours to
restore at a straight time cost of$500 per hour for a total of$1750 per event. Based on
this information the annual labor to complete the restoration work is $1,284,500. This
does not include the material or any overtime costs. It is anticipated that the 5-year
average OMT event will continue to be reduced as feeders are completed and there
are no funding or resource delays.
This program has no identifiable direct capital cost savings. This work is required by
law or rule. The National Electrical Safety Code (NESC) is adopted as Washington Law
under WAC296-45-045. Part 013C of this code describes the application, Part 121
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2023 Page 10 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 166 of 535

Wood Pole Management
defines the inspection interval, and Part 214A details documentation and correction of
the pole inspection results.
2.4 Summarize in the table and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M Indirect Savings $13.2MM $13.2MM $13.2MM $13.2MM $13.2MM
Based on the ICE calculator (Interruption Cost Estimate) total hours per incident is
157.5 hours (# of customers impacted (45) * average outage time (3.5). The ICE is
$116.15. Therefore, your indirect benefit per incident is $18,294. Wood Pole
Management work avoids 726 OMT events per year on average therefore the indirect
benefit is $13,281,444.
This program has no identifiable indirect capital cost savings. This work is required by
law or rule. The National Electrical Safety Code (NESC) is adopted as Washington Law
under WAC296-45-045. Part 013C of this code describes the application, Part 121
defines the inspection interval, and Part 214A details documentation and correction of
the pole inspection results.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
For perspective, the industry average for inspecting and maintaining distribution assets
is ten years. In 2021 Asset Management's "Wood Pole Management (Distribution)
Inspect Cycle Analysis" compared the Avista utility peer group, shown below, which
indicates that Avista is a more rural utility and therefore has far fewer customers per
pole (approximately 1.5 vs. 10), making it economically feasible for the peer group to
inspect poles more frequently as compared to what makes sense for Avista. The ten-
year cycle delivers a better rate of return, but any reduction in cycle time requires an
increase in expenses to pay for the increased number of poles inspected each year,
and a corresponding increase in requirements for capital replacements. Asset
Management and Distribution Engineering monitor system reliability to determine if
adjustments in the scope of work are needed in the future. They also determine the
funding level required to make those adjustments so Asset Maintenance can document
those changes as a new alternative in the Business Case for funding approval by the
Capital Planning Group. If the Capital Planning Group does not approve a new
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allow
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 11 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 167 of 535

Wood Pole Management
alternative, it is not incorporated until funding is approved. Therefore the recommended
solution in 2.1 is the preferred alternative at this time.
DISTRIBUTION - WOOD POLE
CUSTOMERS/POLE INSPECTION INSPECTION CYCLE
(IN YEAR)
Avista 1.54 Contractor 20
BC Hydro 2.21 Contractor 10
ENMAX 10.65 Contractor 10
PGE 4.15 Contractor 10
PSE 3.67 Contractor 10
SMUD 4.80 Internal S
SRP 9.33 Both 10
Alternative 1:
The five-year cycle provided the highest CIRR but this alternative would quadruple the
capital and expense costs to execute the plan. In 2024 the cost would be $69,368,000
for capital and $3,400,000 for O&M. The risk of choosing this alternative isn't feasible
given the company's many other infrastructure needs in addition to the cost impacts to
our customers
Alternative 2:
The ten-year cycle is the industry average for inspection cycle times but
this alternative would double the costs to execute. The 2024 capital cost would be
$34,684,000 and the O&M cost would be $1,700,000. The risk of choosing this
alternative isn't feasible given the company's many other infrastructure needs which
would increase risks in other areas of the company. There are also the cost impacts to
our customers.
Alternative 3:
There is no feasible third alternative.
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
Success is measured by staying on cycle and the improvement in the metrics described
In section 1.5 of this business case. We track the annual and historic cycle performance
on a monthly basis in the Wood Pole Management One Pager.
Business Case Justification Narrative Template Version: February 2023 Page 12 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 168 of 535

Wood Pole Management
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
WPM is an ongoing program. The work is the continuous process of inspecting Avista's
poles by feeder.Once a feeder is inspected it will be re-inspected twenty years from
completion. Each feeder represents a project within the program. There are several
phases to complete each feeder including inspecting, designing, and the capital follow-up
work. We currently utilize in-house and contract crews year-round to complete this work.
The completed work is transferred to plant on a monthly basis.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
Distribution Engineering provides ongoing analysis of distribution asset conditions. This
analysis is used to direct the WPM work that includes inspecting a maintaining Avista's
poles, hardware, and equipment on a twenty-year cycle. The twenty-year cycle is
documented in the 2017 Wood Pole Management Review and Recommendations. The
operating guidelines in the recommended solution are documented in the DFMP-
Distribution Feeder Management Plan-Design Criteria Manual-Applicable to Wood Pole
Management. The governance process is a collaborative process that includes leadership
from Distribution Engineering, Director of Operations, Asset Maintenance Manager, and
WPM Program Manager. Status updates on progress towards yearly goals are documented
and updated on the monthly Wood Pole Management one-pager.
Business Case Justification Narrative Template Version: February 2023 Page 13 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 169 of 535

Wood Pole Management
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Wood Pole Management Business
Case and agree with the approach it presents. Significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Signature: Date: 5/8/2024
Print Name: Mark S. Gabert
Title: WPM Program Manager
Role: Business Case Owner
Signature: TU 6000( Date: 5/15/2024
Print Name: Paul Good
Title: Director Of Operations
Role: Business Case Sponsor
Signature: Date: 5/8/2024
Print Name: Heather Webster
Title: Asset Maintenance Manager
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 14 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 170 of 535

Ambient-Adjusted Transmission Line Ratings
EXECUTIVE SUMMARY
The Company is subject to the authority of the Federal Energy Regulatory Commission ("FERC"). FERC
issued Order 881 was issued December 16, 2021 giving a three+ year implementation period for
transmission providers to implement and use ambient-adjusted ratings for transmission lines used in
providing transmission service by July 2025. This business case provides for engineering and deployment
of new applications and technology as required to address those requirements. The Company will need
to provide upgrades to existing electric control center computing systems to meet the performance
requirements of FERC Order 881.
The total project costs under this new business case are estimated to be $2.6M over three years, 2023,
2024, and 2025. The FERC Order 881 capital project costs under the SCADA business case expended
already in 2023 through Q2 2024 are to be moved out from under SCADA's Business Case to this new
FERC ORDER 881 Business Case. The estimated capital project costs for the upcoming five years are
$1.2M in 2025 only. The 2025 amount requested is based upon a second five-year term GE Dynamic
Line Rating Forecasting application license purchase, a calculation engine to determine updated
scheduling path ratings, an OATI application license purchase, estimated labor hours for engineering
FERC Order 881 required equipment rating methodologies, and labor to apply the updated equipment
limits and associated relay settings.
There is compliance risk if this business case is not adequately funded as the effective date for FERC
Order 881 is July 12, 2025. The software applications, newly engineered equipment ratings, and new
relay settings provide the capabilities required to achieve compliance with FERC Order 881. Mandatory
compliance is necessary, as a violation of the Tariff and FERC rules and regulations may subject the
Company to incur compliance penalties of up to $1 million per day (Energy Policy Act of 2005). Failure to
provide design and construction funding for these projects would be inconsistent with the Ethical Decision
Making policy under the Company's Code of Conduct.
The benefits to all electric customers and to the Business for the necessary expenditure of these funds is
the ability to operate Avista's electric systems in a more efficient, accurate, safe, reliable, and compliant
manner gaining as much capacity as possible out of Avista existing transmission assets. Financial risk is
also reduced to the Business and all customers by avoiding any potential financial penalties associated
with non-compliance.
VERSION HISTORY
Version Author Description Date
0.5 Craig N Figart First version of 2024 business case-removed from SCADA BC 05.03.2024
David Nichols
1.0 Steve Carrozzo BCRT Member Review 05.03.2024
1.1 David Nichols Corrected costs to reflect calculation engine and OATI software 05.06.2024
Business Case Justification Narrative Template Version: February 2023 Page 1 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 171 of 535

Ambient-Adjusted Transmission Line Ratings
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2025 $1.2M $2.6M
2026 $0 $0
2027 $0 $0
2028 $0 $0
2029 $0 $0
Project Life Span 5years
Requesting Organization/Department FERC Policy&Transmission Services
Business Case Owner I Sponsor Kenny Dillon I Michael Magruder
Sponsor Organization/Department Energy Delivery
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
This business case provides for engineering and deployment of new applications and technology
as required to address FERC Order 881 regulatory and business requirements. FERC Order 881,
issued on December 16, 2021, requires transmission providers to implement and use ambient-
adjusted ratings (AARs)for transmission lines used in providing transmission service by 2025.
These AARs ensure that line ratings align closely with actual operating conditions. The goal is to
more efficiently utilize the transmission grid and lower costs for consumers by improving the
accuracy and transparency of line ratings. Transmission providers were required to submit
compliance filings within 120 days of the effective date of the rule, and all requirements in this rule
were to be implemented no more than three years from the compliance filing due date.
Pursuant to the Order, the Company submitted Attachment M to its Open Access Transmission
Tariff which identifies Company implementation of the Order by July 12, 2025.
1.2 Discuss the major drivers of the business case.
This business case is crucial in a key aspect of Avista's Perform strategy to, "...affordably operate
and maintain safe, clean, reliable generation and energy delivery infrastructure", and is the major
driver of the business case. It is essential in providing sufficient control center technology tools,
situational awareness, and monitor/control capabilities to achieve reliable energy service. Dynamic
Line Rating application software to be deployed per FERC Order 881 will allow Avista to safely and
reliably operate its transmission assets to their maximum capacity given additional variable
considerations such as time of day, wind speed, temperature, etc.
Business Case Justification Narrative Template Version: February 2023 Page 2 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 172 of 535

Ambient-Adjusted Transmission Line Ratings
The other driver centers around achieving state financial objectives by minimizing financial risks to
our Customers and to the Business by adhering to FERC Order regulatory requirements.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
Failure by the Company to provide design and construction funding for these projects would be a
violation of the Tariff and FERC rules and regulations pursuant to which the Company could incur
compliance penalties of up to$1 million per day. Failure to provide design and construction funding
for these projects would be inconsistent with the Ethical Decision Making policy under the Company's
Code of Conduct.
New Dynamic Line Ratings and other software and associated engineering is required to provide the
capabilities required to achieve compliance with FERC Order 881. The expenditure of these funds
is necessary to operate Avista's electric transmission systems in a safe, reliable, and compliant
manner.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
Business Case investment upholds the Company's Ethical Decision Making policy under the Code
of Conduct The proposed funding of this Business Case also aligns with the following strategic vision,
goals, objectives, and mission statement of Avista as follows:
Avista's Focus:
- Our Customers: Avista's electric customers are benefited by the safe and reliable operation of
our energy management systems in the control and protection of our electric transmission
infrastructure assets serving all of our electric customers, as well as maximizing the operating
capacity of our existing assets to minimize or defer future expenses. This effort also allows
mechanisms to arrange maximized transmission sales on our system to offset other system
costs.
- Our People: Avista's employees benefit from implementing and operating the latest control
center technologies for Dynamic Line Ratings applications and increased morale in the
opportunity to participate in the installation, maintenance, and ownership of these systems.
- Perform: Control Center technologies supported by this Business Case are required to
affordably operate and maintain safe, clean, reliable generation and energy delivery
infrastructure. This effort provides for operation of our transmission system at its full capacity
based on ambient conditions, often resulting in enhanced capacity overall.
Avista's Values:
- Trustworthy: By funding the secure operation of Avista's electric energy management systems,
customer trust is maintained when electric service is extended affordably by deferment of
transmission system upgrades assuming better maximization of transmission system capacity
utilization.
- Collaborative: Avista's control center staff also collaborate with other utility experts in deploying
the latest and company standard technologies to align in strategically meeting FERC Order 881
requirements. For example, we have been in contact with Arizona Public Service regarding new
GE application software and line ratings methodologies.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 173 of 535

Ambient-Adjusted Transmission Line Ratings
It is essential in providing sufficient control center technology tools, situational awareness, and
monitor/control capabilities to achieve reliable energy service.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation, photographic
evidence, or other materials that explain the problem this business case will
resolve.'
FERC approved a final rule that will more efficiently utilize our nation's transmission grid and help
lower costs for consumers by improving both the accuracy and transparency of transmission line
ratings.
Transmission line ratings represent the maximum transfer capability of each transmission line and
can change based on weather conditions. This final rule requires all transmission providers, both
inside and outside of organized markets, to use ambient-adjusted ratings as the basis for evaluating
near-term transmission service to increase the accuracy of near-term line ratings. Typically, line
ratings are based on conservative assumptions about worst case, long-term air temperature and
other weather conditions that can lead to underutilization of our transmission grid.
"If we are going to meet the needs of the grid of the future while keeping customer rates just and
reasonable and maintaining grid reliability, we need to squeeze everything out of our existing grid,"
Chairman Glick said. "Today's final rule is huge step forward in making more efficient use of our
transmission system and saving money for customers. But our work isn't done. I look forward to
working with my colleagues to explore the adoption of dynamic line ratings to further increase the
efficiency of our grid."
While the final rule does not mandate the adoption of dynamic line ratings— ratings that account for
other factors like wind speed —the rule does require that organized market operators establish and
maintain systems and procedures necessary to allow transmission owners that would like to use
dynamic line ratings the ability to do so.The rule acknowledges that dynamic line ratings may deliver
incremental benefits and announces that the Commission is opening a proceeding in AD22-5-000 to
continue to build the record and explore the potential for further action on dynamic line ratings.
Transmission providers must submit compliance filings within 120 days of the effective date of the
rule.All requirements in this rule must be implemented no more than three years from the compliance
filing due date.
2. PROPOSAL AND RECOMMENDED SOLUTION - Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The proposed Business Case solution addresses FERC Order 881 regulatory and business
requirements to provide for ambient-adjusted ratings to Avista transmission lines, as well as for
deployment of new applications and technology as required.
Avista's Engineering Departments will provide engineering for the development of new tables of line
ratings based on the range of ambient conditions specified in the Order. These expanded rating
tables will be fed into the new GE Dynamic Line Rating software in SCADA to be used in calculations
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 174 of 535

Ambient-Adjusted Transmission Line Ratings
for system power flow limits. The GE software will also incorporate ambient temperature conditions
to select the appropriate AARs for the next 240 hours as required by the Order. This work will be
repeated at least hourly. These AARs will be supplied to the Reliability Coordinator, RC West, for
incorporation into the Western Interconnection model and associated power flow studies via an
OATI-hosted application to be purchased under this business case as well. This effort is expected
to cost $0.5M from 2023 to Q2 2024, plus $0.9M for the remainder of 2024, plus $0.6M in 2025, for
a total SCADA-related cost of$2.OM.
System topology, generation dispatch, and area load will be then fed into a calculation engine, such
as PowerWorld Cruncher or other in-house developed software,to determine total transfer capability
(TTC)for each of our transmission scheduling paths for the next 240 hours. This effort is expected
to have a $50k up-front software cost. To implement, three in-house employees working for
approximately six months is estimated at 800 labor hours ('/2 year) x 3 employees x $180 loaded
labor rate = $432k in labor for 2025. This amounts to a cost of$0.48M in 2025.
Finally, an application such as OATI's webLinerR, or other in-house developed resource, will post
the new TTC values to the Open-Access Same-Time Information System (OASIS)for public access,
as required by the Order. This system will also archive the hourly AARs as required by the Order.
The up-front software cost for this effort is expected to be $0.12M in 2025.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other information
that was considered when preparing this business case (i.e., samples of
savings, benefits or risk avoidance estimates; description of how tare being
measured; metrics such as comparison of cost ($) to benefit (value), or
evidence of spend amount to anticipated return).'
As a Mandatory and Compliance driven project, a violation of the Tariff and FERC rules
and regulations pursuant to which the Company could incur compliance penalties of up
to $1 million per day. Meeting Avista's obligations under the Federal Power Act would
be consistent with the Ethical Decision Making policy under the Company's Code of
Conduct and remove the risk compliance penalties.
With possible enhanced transmission capacity as a side benefit of complying with the
Order, a hypothetical 10 MW increase in transmission sales across our system would
result in $32.98/kW-yr * 10,000kW = $329,800 per year in revenue. Transmission
service revenue is accounted for in FERC account 456, which flows through the ERM,
and ultimately offsets retail customer rate.
3 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 175 of 535

Ambient-Adjusted Transmission Line Ratings
2.3 Summarize in the table, and describe below the 4oB�, or savings (Capital
and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital
0&M
There are no known direct offset or savings associated with capital investments in this
Business Case.
2.4 Summarize in the table, and describe below the 5INDIRECT offsets6
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
There are no indirect offset or savings associated with capital investments in this
Business Case. There may be enhanced line capacity due to use of Dynamic Line
Ratings or AARs during certain weather conditions, typically cold weather, when our
system load is high. This would provide added margin for reliability operations. However,
the indirect cost savings of deferring new line construction are not readily quantifiable.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Thus far, there is only one capital project expected to be included under this business
case. It includes the following components:
o Purchase of 5yr term licensing for GE's new Dynamic Line Ratings (DLR)
application software
o GE Statement of Work to back-port DLR code to Avista's current EMS
application version
o Purchase of 5yr term licensing for GE's new DLR Forecasting application
software
4 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
6 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 176 of 535

Ambient-Adjusted Transmission Line Ratings
o Purchase of licensing for use of OATI's new application software to receive,
store, and transmit forecasted equipment ratings to the Reliability Coordinator,
RC West.
o Engineering labor to develop new line and equipment ratings.
o PCM tech labor to deploy new relay settings required by newly rated equipment
o Implementation of a TTC calculation engine using PowerWorld Cruncher or
other in-house application
Alternative 1:
The only portions for alternative considerations in this project are in relation to
application software/vendor selections. In this case, Avista's package deal purchase
of five-year term licensing for EMS software included GE's new Dynamic Line Ratings
as part of the coinciding purchase of GE Advanced Distribution Management term
licensing. So there was no opportunity nor real reason to consider other vendors for
this solution. Otherwise, as we look to subsequent software purchases, i.e. OATI, we
can research other vendor options at that time.
As to labor alternatives, there really are no options.
Alternative 2:
There is certainly a "No Funding" option available for this Business Case. However,
failure by the Company to provide design and construction funding for this project would
be a violation of the Tariff and FERC rules and regulations pursuant to which the
Company could incur compliance penalties of up to $1 million per day. Failure to
provide design and construction funding for this project would be inconsistent with the
Ethical Decision Making policy under the Company's Code of Conduct.
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
Success can be measured with implementation of the work described herein and the
associated applications by tracking the posted values of AARs and TTCs over time. An
internal audit of the new rating methodology on a sample of lines and posted values can
demonstrate project success.
Success will be measured upon Avista successfully passing future audits for compliance
with FERC Order 881.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
This business case is comprised of a single FERC Order 881 capital project that was
opened in late 2023. The project will be transferred to plant upon FERC Order 881's
effective date of July 2025, with trailing go-live support costs through the subsequent
months in 2025.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 177 of 535

Ambient-Adjusted Transmission Line Ratings
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
The steering committee/advisory group for initial and ongoing vetting and department
prioritization process includes the members from the entire SCADA team as needed,
but more notably the following:
- Director of System Operations and Planning
- Sr Manager of FERC Policy and Transmission Services
- Manager, SCADA/Energy Management Systems
- Transmission Contracts Engineer— acting Project Manager
Individual projects are governed by the Transmission Services member assigned to the
project as project lead who is tasked with scheduling and coordinating all the work
associated with the project.
Project oversight is provided by the Sr manager of FERC Policy and Transmission
Services and also by the SCADA/EMS manager, but also to the assigned project
lead.
The steering committee provides governance and oversight of this business case.
The Project Manager has periodic check-in meetings scheduled with multiple
groups including SCADA, Substation Engineering, Protection Engineering, System
Planning, PCM Shop, etc., during which to track progress of this large capital project
that comprises the total business case.
Decision-making, prioritization, and change requests at the individual capital project
level are taken care of within the Transmission Services and SCADA groups under
manager supervision.
Any need for substantial change requests to capital projects that would deviate from
the original Capital Project Request (CPR) are documented and submitted to Project
Accounting as a revised CPR. Change requests and resulting decisions that lead to
significant changes in project scope are documented in the project charter
documentation and revisions to the original version and stored in SCADA's SharePoint
site and/or the "FERC Order 881 Implementation" Teams site.
Prioritization for each individual project and/or aspect of a project within this business
case is performed by the Transmission Services. If the sum total of all aspects of the
FERC Order 881 capital project is expected to exceed the approved Business Case
funding, then a Business Case Change Request must be approved by the Steering
Committee and submitted to Project Accounting.
Business Case Justification Narrative Template Version: February 2023 Page 8 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 178 of 535

Ambient-Adjusted Transmission Line Ratings
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the FERC ORDER 881 Business Case
and agree with the approach it presents. Significant changes to this will be coordinated with
and approved by the undersigned or their designated representatives.
Signature: �� �.R Date: 5/6/2024
Print Name: Michael A. Magruder
Title: Director, System Operations &
Planning
Role: Business Case Sponsor
Signature: Ke';Z� z— Date: 5/6/2024
Print Name: Kenny Dillon
Title: Sr Mgr FERC Policy &
Transmission Services
Role: Business Case Owner
Signature: Date:
Print Name: Craig N. Figart
Title: Mgr Energy Mgmt Systems
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 9 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 179 of 535

Coistrip Transmission
EXECUTIVE SUMMARY
Avista is a joint owner in the 500kV Colstrip Transmission System and party to the Colstrip Project
Transmission Agreement ("Agreement"). Avista and the joint owners are obligated to fund their respective
shares of the Colstrip Transmission System construction and maintenance budgets, as approved by the
Colstrip Transmission Committee, which consists of representatives of each of the parties to the Agreement.
The Colstrip Transmission Committee reviews and approves, on an annual basis, the capital and 0&M
expense program proposed by NorthWestern Energy ("NWE") (the designated Transmission Operator under
the Agreement). Pursuant to Section 22 of the Agreement,Avista provides annual input to, and approval for,
the Colstrip Transmission System capital and 0&M expense program commensurate with its ownership
shares in the Colstrip Transmission System.' Failure to fund Colstrip Transmission expenditures would be a
breach of the Company's obligations under the Agreement.
In conjunction with the Company's ownership interest in Colstrip Project Units 3 and 4, the Colstrip
Transmission System has benefited the Company's retail native load customers since the early 1980's. To
continue to reliably integrate the Company's Colstrip Project resources to native load and to meet applicable
NERC transmission planning and operational reliability standards, the Colstrip Transmission System must
be maintained. Examples of recent and pending capital expenditures in the Colstrip Transmission System
include end-of-life replacement of 500kV power circuit breakers at the Colstrip 500/230kV Station and 500kV
structure relocation to mitigate erosion risk caused by high runoff in the Little Big Horn River. At such time
as the Company may no longer attain output from Colstrip Project Units 3 and 4, the Company's ownership
in the Colstrip Transmission System may facilitate access to new resource acquisition opportunities in the
state of Montana. In recent years there has been a tremendous increase in the demand for long-term
transmission rights, including on the Colstrip Transmission System. Maintaining ownership of Avista's portion
of the Colstrip Transmission System will enable Avista to maintain resource adequacy and comply with
applicable clean enery mandates, while simultanesouly selling any excess transmission capacity to benefit
our retail customers.
Colstrip Transmission program capital expenditures have averaged $350,000 over the ten-year period from
2012-2021. Each year NWE develops a five-year capital plan for necessary capital improvements, renewals
and replacements for the Colstrip Transmission System; future program requirements can fluctuate year-
over-year and the new five-year average is expected to be roughly double the previous five-year average
due to the more costly projectS2 planned during 2025 and 2026. The 5-year average is projected to decrease
upon the completion of these capital intensive projects.
Avista owns a 10.2% share in the Colstrip-Broadview segment and a 12.1% share in the Broadview-Townsend
segment.
2 There are two major projects in 2025 and 2026 to complete a series cap bank replacement and purchase a new
spare circuit switcher for the CTS.These two projects are forecasted to cost approximately$21 million total,and Avista
will only be responsible for it's allocated share according to the Company's ownership percentage of the CTS
(approximately$2 million).
Business Case Justification Narrative Template Version: February 2023 Page 1 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 180 of 535

Coistrip Transmission
VERSION HISTORY
Version Author Description Date
2.0 Jeff Schlect Initial narrative drafted frompre-existing approved case 7/28/2020
2.1 Jeff Schlect Business Case refresh 5/26/2022
3.0 Randy Gnaedin er Business Case refresh to new template 1011112023
4.0 Garrett Brown Business Case refresh 412512024
BCRT BCRT Team Has been reviewed by BCRT and meets necessary requirements Steve 51112024
Memember Carrozzo
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT($)
2025 $1,457,000 $1,457,000
2026 $854,000 $854,000
2027 $412,000 $412,000
2028 $363,000 $363,000
2029 $450,000 $450,000
Project Life Span Ongoing Annual Program
Requesting Organization/Department Energy Delivery/Transmission Services
Business Case Owner I Sponsor Kenneth Dillon I Josh DiLuciano/Mike Magruder
Sponsor Organization/Department Energy Delivery/Transmission Services
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
Business Case Justification Narrative Template Version: February 2023 Page 2 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 181 of 535

Coistrip Transmission
�. BUSINESS PROBLEM
As part of the construction and integration of Colstrip Units 3 and 4 in the early 1980s for the benefit of
the Company's native load retail customers, the Colstrip project participants constructed the Colstrip
Transmission System, approximately 250 miles of double circuit 500kV transmission facilities
extending from the Colstrip Project westward to the Broadview 500kV Substation and the Townsend
point of interconnection between the Colstrip Transmission System and the Bonneville Power
Administration's Eastern Intertie 500kV facilities.
COLSTRIP TRANSMISSION SYSTEM
Colstrip-Townsend—250 miles
ARRISO BRO.DVIEW .OLSTRIP
TOW
A VISTA Colstrip Generation
15%ownership in Units 3 and 4
Capacity: 225MW
Avista owns a 15% share of Colstrip Units 3 and 4 (approximately 225MW). Reliable operation of the
Colstrip Transmission System is necessary to transfer Colstrip output and prospective renewables to
the respective systems of each joint project owner, including Avista (other project owners are:
NorthWestern Energy, PacifiCorp, Portland General Electric and Puget Sound Energy). Avista and
the other joint project owners are party to the Colstrip Project Transmission Agreement which, among
other things, obligates Avista to fund its commensurate share of all construction and maintenance
expenses for the ongoing operation, maintenance, renewal and replacement of the jointly owned
Colstrip Transmission System facilities.
Examples of recent expenditures in the Colstrip Transmission System are noted in Section 2.2 below.
As NERC transmission planning and operational reliability standards3 evolve, compliance with both
operational and planning standards may require replacement of,or upgrades to, Colstrip Transmission
System facilities.
3 Among its other provisions, the U.S. Energy Policy Act of 2005 provided for the establishment of mandatory
reliability standards and authorized the Federal Energy Regulatory Commission (FERC)to assess penalties of
up to $1 million per day per violation for non-compliance with these standards and other FERC regulations.
FERC has certified the North American Electric Reliability Organization (NERC)to establish and enforce these
reliability standards. The Company has a statutory obligation to plan, improve, upgrade, and operate its
transmission system, including the Colstrip Transmission System,to maintain compliance with these standards
and is required to self-certify its compliance with these standards on an annual basis.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 182 of 535

Coistrip Transmission
1.1 What is the current or potential problem that is being addressed?
Pursuant to the Agreement, the Company must fund its applicable ownership share of capital
improvements to the jointly owned Colstrip Transmission System.
1.2 Discuss the major drivers of the business case.
The Company's capital investment in the Colstrip Transmission System is driven by its contractual
obligations under the Agreement (Mandatory & Compliance). Related drivers include Asset
Condition and Failed Plant& Operations.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
Failure to fund its allocated share of costs under the Agreement will put the Company into default
and would eliminate the Company's right to use the Colstrip Transmission System to integrate its
resources for service to its bundled retail native load customers.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
Program investment upholds the Company's Code of Conduct and is consistent with its lasting
values. Colstrip Transmission System investment maintains the Company's ability to integrate its
Colstrip generation assets for service to bundled retail native load customers and provides the
Company with a future transmission alternative to integrate prospective renewable resources
located in Montana.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.4
Not applicable
4 Please do not attach any requested items to the business case, rather be sure to have ready access to such
information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 183 of 535

Coistrip Transmission
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The Company must fund its allocated share of capital improvements under the Colstrip
Transmission Agreement.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).5
Not applicable
2.3 Summarize in the table, and describe below the DIRECT offsetss or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
0&M $ $ $ $ $
Not applicable
2.4 Summarize in the table, and describe below the INDIRECT offsets? (Capital
and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
0&M $ $ $ $ $
Not applicable
5 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
6 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 184 of 535

Colstrip Transmission
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternative 1:
Not applicable (only alternative is to not fund and default on contract)
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
Not applicable (only alternative is to not fund and default on contract)
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Capital amounts are used for improvements, renewals and replacements of Colstrip
Transmission System assets. Examples of recent expenditures in the Colstrip Transmission
System include:
Past Projects:
• 500kV Broadview Cap Bank Battery
• 500kV Colstrip Ground Switch
• Comm Snowcat
Ongoing and Future Projects:
• Broadview-Colstrip series cap bank replacement (multi-year project)
• Microwave communications equipment upgrade (multi-year project)
• Broadview spare circuit switcher purchase (multi-year project)
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight
of the business case, and how such oversight will occur.
Pursuant to Section 22 of the Agreement, Avista provides annual input to, and approval for, the
Colstrip Transmission System capital and 0&M expense program commensurate with its
ownership shares in the Colstrip Transmission System. The Colstrip Transmission Committee,
of which the Company is a member, meets periodically to review, and provide
recommendations for, the annual capital program administered by NWE. The Colstrip
Transmission Committee provides approval for each year's capital program.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 185 of 535

Coistrip Transmission
Also pursuant to Section 22 of the Agreement, the Colstrip Transmission Committee is
established to facilitate cooperation, interchange of information and efficient management of
the Colstrip Transmission System. The Colstrip Transmission Committee consists of five
members, each designated by one of the parties to the Agreement. Each committee member
has the right to vote their party's ownership share in the Colstrip Transmission System. Section
22(f)of the Agreement outlines all matters that shall be submitted to the committee by NWE for
approval, including Colstrip Transmission System construction and operating budgets.
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Colstrip Transmission Business Case
and agree with the approach it presents. Significant changes to this will be coordinated with
and approved by the undersigned or their designated representatives.
Signature: Kenneth L Dillon Digitally signed by Kenneth L Dillon Date: 5-1-2024
Date:2024.05.01 15:35:34-07'00'
Print Name: Kenneth Dillon
Title: Senior Manager, FERC Policy and
Transmission Services
Role: Business Case Owner
Signature: Michael A. Magruder Digitally signed by Michael A.Magruder g g Date:2024.05.02 08:25:24-07'00' Date: 5-2-2024
Print Name: Mike Magruder
Title: Director, Transmission Operations
and System Planning
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 7 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 186 of 535

DocuSign Envelope ID:B852F7EA-84B2-437C-8164-70D90409E5D4
Electric Storm
EXECUTIVE SUMMARY
The Electric Storm Business Case is focused on restoring Avista's transmission,
substation, communications, and distribution systems (damaged plant) into serviceable
condition during a weather storm event or other natural disaster where assets are
damaged. These storm events are random and often occur with short notice. This
business case is to fund a rapid response to unexpected damages and outages, so
customer outages are minimized. The business case provides funds for replacing poles,
cross arms, conductor, transformers, and all other defined retirement units damaged
during weather storm events. The damage can be due to high winds, heavy ice and snow
loads, lightning strikes, flooding, or wildfires as an example. The importance of quickly
replacing damaged facilities is vital to providing reliable service to our customers. This
impacts customers in WA and ID.
The annual budget amount is determined based on the historical average rate of capital
restoration work including restoration activity related to major event days (MEDs) of
relativity minor restoration impact. Request excludes costs related to very large MEDs. If
not funded, the work will still occur as needed for outages caused by weather storm
events or other natural disasters and would be absorbed through other business cases.
VERSION HISTORY
Version Author Description Date
1.0 Joe Wright Initial draft of original business case 12/12/23
Business Case Justification Narrative Template Version: February 2023 Page 1 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 187 of 535

DocuSign Envelope ID:B852F7EA-84B2-437C-8164-70D90409E5D4
Electric Storm
BCRT Team
BCRT N>rear Has been revievvedbyBCRTand meets necessaryrequirements
mem
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2024 $5,000,000 $5,000,000
2025 $5,000,000 $5,000,000
2026 $5,000,000 $5,000,000
2027 $5,000,000 $5,000,000
2028 $5,000,000 $5,000,000
Project Life Span Annual Program
Requesting Organization/Department Operations
Business Case Owner I Sponsor Paul Good Josh DiLuciano
Sponsor Organization/Department Operations
Phase Execution
Category Program
Driver Failed Plant&Operations
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
Business Case Justification Narrative Template Version: February 2023 Page 2 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 188 of 535

DocuSign Envelope ID:B852F7EA-84B2-437C-8164-70D90409E5D4
Electric Storm
i. BUSINESS PROBLEM - This section must provide the overallbusiness case information
conveying the benefit to the customer,what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
The Electric Storm Business Case (BC) is focused on restoring Avista's
transmission, substation, communications, and distribution systems (damaged
plant) into serviceable condition during a weather storm event or other natural
disasters where assets are damaged. These events are random and often occur
with short notice. This business case funds a rapid response to unexpected
damages, so customer outages are minimized. The business case provides
funds for replacing poles, cross arms, conductor, transformers, and other
defined retirement units damaged during storm events. The damage can be due
to high winds, heavy ice and snow loads, lightning strikes, flooding, or wildfires.
The importance of quickly replacing damaged facilities is vital to providing
reliable service to our customers.
1.2 Discuss the major drivers of the business case.
The primary driver for the Electric Storm BC is Failed Plant and Operations. The
work is a key component to minimizing customer outage times and contributes
to Avista's reliability indices like System Average Interruption Frequency Index
(SAIFI) and Customer Average Interruption Duration Index (CAIDI). The
secondary driver for this business case is Customer Service Quality and
Reliability
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The importance of quickly replacing damaged facilities is vital to providing
reliable service to our customers. The Electric Storm BC is to fund a rapid
response to unexpected damages and outages, so customer outages are
minimized. If this business case is not funded the costs to restoring power to our
customers will be absorbed by another business case. The needed work will
continue to occur.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
The Electric Storm business case aligns with the company's strategic goal of
Safe and Reliable Infrastructure. The work is a key component to minimizing
customer outage times and thus contributes to Avista's reliability indices like
SAIFI and CAIDI.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 189 of 535

DocuSign Envelope ID:B852F7EA-84B2-437C-8164-70D90409E5D4
Electric Storm
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
N/A
2. PROPOSAL AND RECOMMENDED SOLUTION -ascnbetheproposedsolutionto
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The Electric Storm Business Case (BC) is focused on restoring Avista's
transmission, substation, communications, and distribution systems (damaged
plant) into serviceable condition during a weather storm event or other natural
disasters where assets are damaged. These events are random and often occur
with short notice. This business case funds a rapid response to unexpected
damages, so customer outages are minimized. The business case provides
funds for replacing poles, cross arms, conductor, transformers, and other
defined retirement units damaged during storm events.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).'
The annual budget amount is determined based on the historical average rate
of capital restoration work.
Figure 1 shows the historical costs (2017-2022) for the distribution/transmission
storm business case and YTD 2023 expenses through October. From 2017-
2022, the average annual cost for capital storm response was $8.6 million
dollars, with a range of$3.6MM (2018) to $14.6MM (2021). There were 7 MEDs
in 2020 and 4 in 2021. The majority of the MED costs in 2021, however, occurred
' Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 190 of 535

DocuSign Envelope ID:B852F7EA-84B2-437C-8164-70D90409E5D4
Electric Storm
in January, one $7.2MM storm. Consequently, 2020 results were excluded and
2021 results were adjusted downward to exclude the particularly large January
storm for determining the proposed funding level. The average spend for 2017-
2019/2021-2022 was $5.4MM. This includes some MED activity of
comparatively minor restoration impact during these years. Proposed funding
for 2024-2028 is $5M per year. Further funding for significant MEDs will be
requested as needed.
Sum of Transaction Amount
DX/TX Cap Storm Actuals
I Jan 2021
16,000,000
14,630,591 windstorm$7.2M
14,000,000 13,732,822
12,000,000
IQ000,000
8,000,000 6,815,294 599, ,6367
6,309,201 ■Total
6,000,000
4,000,000 3,574,683 3,926,511
2,000,000 ,
0
2017 2018 2019 202(1 2021 2022
Accounting Year .T
Figure 1:Storm Historical Costs
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset ascription 2024 2025 2026 2027 2028
Capital $ $ $ $ $
08M $ $ $ $ $
There are no offsets to O&M. There is no identified direct savings related to this
business case. This business case is completed to replace failed equipment due
to extreme weather events.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 191 of 535

DocuSign Envelope ID:B852F7EA-84B2-437C-8164-70D90409E5D4
Electric Storm
2.4 Summarize in the table, and describe below the INDIRECT offsets' (Capital
and O&M) that result by undertaking this investment.
Offsets Offset ascription 2024 2025 2026 2027 2028
Capital $ $ $ $ $
08M $ $ $ $ $
There are no offsets to O&M.
Current RCW standards obligate us to perform repair work following storm
damage. Therefore, an amount of capital is earmarked for a normal year of
weather events.
Although there are no financial offsets, an ICE (Interruption Cost Estimate)
may be calculated for determining an avoided indirect cost for having this
program.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
The alternative to this business case request is not funding. The costs
associated with repairing damages as a result of a weather storm event or a
natural disaster would be covered through a different business case. Damages
from these events must be repaired, regardless of funding.
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
The primary measure that will be used to determine success is outage duration
including other reliability measures such as Avista's reliability indices like SAM and
CAIDI. These measures will demonstrate the impact of the work charged to this
business case.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 192 of 535

DocuSign Envelope ID:B852F7EA-84B2-437C-8164-70D90409E5D4
Electric Storm
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Weather storm events or natural disasters are a continuous risk. Work will occur
as needed as a result of damaged facilities related to these events. Many times,
multiple events may occur within one year in different office areas. Past data shows
there has not been a year where a storm has not happened. Since this is often
emergency work, assets become used and useful and transferred to plant
immediately.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
The Electric Storm work is overseen by the local area operations engineers and
area construction managers. The work is unplanned and non-specific in nature
but occurs regularly. In the event of larger scale storms or natural disasters, like
the historical storm event in November 2015, a formal Incident Command
System (ICS) is created to manage the resources needed to respond. Other
large events are managed through an emergency operating plan (EOP) with the
Director of Operations.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 193 of 535

DocuSign Envelope ID:B852F7EA-84B2-437C-8164-70D90409E5D4
Electric Storm
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Electric Storm and agree with the
approach it presents. Significant changes to this will be coordinated with and approved by
the undersigned or their designated representatives.
DocoSignetl by:
Signature: Date: Dec-15-2023 112:28 PM PST
Pain, l eel,
SADIIAAIABSCAA9
Print Name: Paul Good
Title: Director of Electric Operations
Role: Business Case Owner
DSigned by:
Signature: 56Z v;�� Date: Dec-15-2023 1 8:35 AM PST
3�T1E7dF65
Print Name: 3oshua Di Luciano
Title: VP Energy Delivery
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 8 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 194 of 535

SCADA - SOO and BuCC
EXECUTIVE SUMMARY
This business case provides for replacement of existing technology, as well as for deployment of new
applications and technology as required to address expanding regulatory and business requirements. This
program(Supervisory Control and Data Acquisition-System Operations Office and Backup Control Center)
replaces and upgrades existing electric and gas control center telecommunications, networks, and
computing systems as they reach the end of their useful lives, require increased capacity, or cannot
accommodate necessary equipment upgrades due to existing constraints. Some system upgrades may be
necessitated by other requirements, including NERC reliability standards, TSA directives, FERC orders,
federal gas standards, system growth, and external projects(e.g. Smart Grid). The customers who benefit
from the reliable, safe and secure delivery of energy resources are all electric and gas residential,
commercial, and industrial customers (CD.AA).
The estimated capital costs for the upcoming five years are $8M. The amount requested is based upon
known upcoming major projects and the expected equipment and software upgrade/replacement cycles
and multi-year term license renewals,which are new in recent years beginning in 2022. For example, 2026
is expected to be a historical typical average $800k spending year accommodating such notable projects
as 1) GPS Clock replacements, 2) CIP Virtual Machine Host replacements, and Digi Terminal Server
replacements. The surrounding years, however, include a $400k effort replacing network and firewall
hardware including term license software, $400k effort in 2027 upgrading SCADA's Relational Database, a
$3.3M effort in 2027-2028 to upgrade our main Energy Management System also including term licensing.
Within the program's yearly authorized spend amount, specific budgetary items to be implemented are
determined based on asset condition, life-cycle management, technology enhancements, and requests by
affected stakeholders including System Operations, Distribution Operations, and Power Supply.
There are multiple risks if this program is not adequately funded. The clearest risk would be to public and
personnel safety. The control systems supported by this business case provide real-time visibility,
situational awareness, and control of Avista's electric and gas systems. Degradation of these capabilities
due to lack of capacity, capability, or aging systems would present increased safety risk.Additionally, there
is significant compliance risk. These control systems provide the capabilities required to achieve
compliance with numerous reliability standards and requirements. For the electrical system these include
the FERC orders, TSA directives, and NERC standards BAL, COM, CIP, EOP, INT, PER, PRC, TOP, and
VAR. For the gas system these include the PHMSA"Pipeline Safety: Control Room Management/Human
Factors" rule (49 CFR Parts 192 and 195.)
The benefits to all gas and electric customer and to the Business for the necessary expenditure of these
funds is the ability to operate Avista's electric and gas systems in a safe, reliable, and compliant manner.
Financial risk is also reduced to the Business and all customers by avoiding any potential financial penalties
associated with non-compliance.
The incremental Operations and Maintenance labor resource costs for the upcoming five years are
estimated to be $3.6M based on SCADA's staffing plan requiring nine additional staff additions in support
of this Business Case according to industry staffing benchmarks, new ADMS and security/compliance
support requirements. Note, however, that $845k for the 1st two positions in 2025 below are already
included as part of the ADMS staffing plan (5 years * $169k/yr= $845k).
Year SCADA labor Resource Addition(70/30) Qty O&M Cost/ea Cap Cost/ea O&M Annual Total O&M Cum Total
2025 SCADA/ADMS Containerized App Engr* 2 $84,567 $37,994 $169,133 $169,133
2025 SCADA Support/SCADA Sys Tech 2 $84,567 $37,994 $169,133 $338,267
2025 Security Compliance Engr 1 $87,527 $39,324 $87,527 $425,793
2026 SCADA/EMS Engr* 1 $90,590 $40,700 $90,590 $516,383
2027 SCADA/EMS Engr* 1 $93,761 $42,124 $93,761 $610,144
2028 SCADA/EMS Engr* 1 $97,042 $43,599 $97,042 $707,186
2029 SCADA/EMS Engr* 1 $100,439 $45,125 $100,439 $807,625
Total 2025-2029 BC Cap/O&M Funding Req't 9 $807,625 $3,574,532
*NOTE: Classified as SCADA/EMS/ADMS Engineering staff per industry benchmarks
Business Case Justification Narrative Template Version: February 2023 Page 1 of 13
Exhibit No. 10
Case Nos.AW-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 195 of 535

SCADA - SOO and BuCC
VERSION HISTORY
Version Author Description Date
0.2 Craig N Figart Draft version of 2020 business case 07.17.2020
1.0 Craig N Figart Final version of 2020 business case 09.21.2020
2.0 Jeremiah Webster formatting to keep the fonts consistent, removed some of the blue help 12.15.2020
text,and deleted the comments
3.0 Craig N Figart Updated per$350k capital funding increase for 2021 due to EMS upgrade 07.05.2021
Updated per$490k capital funding increase for 2021 due to EMS upgrade
4.0 Craig N Figart multi ear bud etin ,firewall refresh,file storage expansion 09.10.2021
5.0 Craig N Figart Updated version for 2022 business case 08.03.2022
6.0 Craig N Figart Updated version for 2023 business case 04.21.2023
Mike A Magruder
7.0 Craig N Figart Updated with indirect cost saving examples 04.28.2023
Craig N Figart Updated version for 2024 business case(2025-2029). Transfer FERC 04.30.2024
8.0 Order 881 capital project and funding to new business case.
Steve Carrozzo BCRT Team Member Review 05.03.2024
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2025 $0.8M $0.8M
2026 $0.8M $0.8M
2027 $2.OM $1.01M
2028 $3.2M $4.2M
2029 $1.2M $1.2M
Project Life Span 5 years
Requesting Organization/Department T&D— SCADA/EMS/ADMS—System Operations
Business Case Owner I Sponsor Craig N Figart I Michael Magruder
Sponsor Organization/Department Energy Delivery
Phase Execution
Category Program
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
Business Case Justification Narrative Template Version: February 2023 Page 2 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 196 of 535

SCADA - SOO and BuCC
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
In order to effectively operate the Transmission & Distribution (T&D) and Gas Telemetry Systems,
sufficient business and computing hardware and software is necessary. This business case provides
for replacement of existing technology in alignment with manufacturer product roadmaps for
application and technology Iifecycles, as well as for deployment of new applications and technology
as required to address expanding regulatory and business requirements. Technology continues to
change and T&D Systems continue to incorporate improved technology. Here is GE's LifeCycle
Roadmap:
Table 1 Grid Software Solutions Product Life Cycle
Transmission AEMS
Regular 5 years Extended Additional
MA
Distribution ADMS
Regular 3 years Extended Additional 2 years �Sustaining 5+Years
Accordingly, for example, the SCADA Front-End (SFE) servers installed in 2018 are scheduled for
replacement in 2025,just past the vendor's Extended Additional 2 years support schedule. The SFE
Operating System is already under Extended Windows Support as of January 2022, and the SFE
application itself will be past the End of Extended Support by July 2024, beyond which GE begins to
provide security update validation service on Time and Materials basis. The risk to Avista is
increased O&M exposure should Avista require GE to backport security-related updates; additional
O&M requirements could exceed over$200k. A recent 2024 quote listed hourly rates of$352/hr to
$671/hr for back-porting new GE application code to our current older EMS version totalling over
$200k just for GE's labor portion, not including additional labor Avista SCADA resources would be
required (i.e. estimate $25k to$50k???).
Another notable project is to upgrade the ICCP servers installed in 2018 as well due for refresh for
similar reasons. And the main Energy Management System applications released in 2020 and
installed in 2021 are due for refresh on or before May of 2027 after which Extended Support ends.
As noted above, the risk to Avista is increased O&M exposure should Avista require GE to backport
security-related updates; additional O&M requirements could exceed over$200k.
Additional labor resources, that typically run which typically run 30% capital and 70% Operations
and Maintenance, are also required in order to adequately support SCADA's capital business case
efforts and also operate the Transmission & Distribution (T&D) and gas telemetry and control
systems. According to SCADA's staffing plan, according to SCADA staffing industry benchmarks for
required staffing levels based on system point counts and other relative sizing, Avista should have
25 SCADA/EMS/ADMS engineering staff. Avista SCADA staff currently consists of only less than
10 EMS/ADMS support staff.
The total additional Operations and Maintenance costs to add the next nine of these additional staff
totals $3.6M over the next five years per the table below. Note, however, two of the positions are to
be funded in 2025 as part of the ADMS project staffing plan ($169k/year* 5 = $845k):
Business Case Justification Narrative Template Version: February 2023 Page 3 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 197 of 535

SCADA - SOO and BuCC
Year SCADA Labor Resource Addition(70/30) Qty O&M Cost/ea Cap Cost/ea O&M Annual Total O&M Cum Total
2025 SCADA/ADMS Containerized App Engr* 2 $84,567 $37,994 $169,133 $169,133
2025 SCADA Support/SCADA Sys Tech 2 $84,567 $37,994 $169,133 $338,267
2025 Security Compliance Engr 1 $87,527 $39,324 $87,527 $425,793
2026 SCADA/EMS Engr* 1 $90,590 $40,700 $90,590 $516,383
2027 SCADA/EMS Engr* 1 $93,761 $42,124 $93,761 $610,144
2028 SCADA/EMS Engr* 1 $97,042 $43,599 $97,042 $707,186
2029 SCADA/EMS Engr* 1 $100,439 $45,125 1 $100,439 1 $807,625
Total 2025-2029 BC Cap/O&M Funding Req't 9 $807,625 $3,574,532
*NOTE: Classified as SCADA/EMS/ADMS Engineering staff per industry benchmarks
Only six of the nine staff to be added over the next five years classify as EMS/ADMS support staff
per industry staffing benchmarks, which would bring the total EMS/ADMS support staff count up to
16, much closer to the required 25. The remaining three additional staff of the nine to be added are
for:
- One Security Operations/Compliance Support position to complement SCADA's sole security
engineering resource and also provide assistance meeting compliance requirements and
documentation responsibilities.
- Two positions (i.e. SCADA Systems Tech &Control Systems Specialist or two SCADA Systems
Techs)to provide operations support for the overdoubled infrastructure added in SCADA as part
of the ADMS project and also to meet Article 16 obligations.
1.2 Discuss the major drivers of the business case.
This business case is crucial in a key aspect of Avista's Perform strategy to, "...affordably operate
and maintain safe, clean, reliable generation and energy delivery infrastructure", and is the major
driver of the business case. It is essential in providing sufficient control center technology tools,
situational awareness, and monitor/control capabilities to achieve reliable energy service. The other
driver centers around achieving state financial objectives by minimizing financial risks to our
Customers and to the Business by adhering to NERC security compliance requirements associated
with operating energy management systems that are vendor supported and secured to meet security
and operational requirements.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
There are multiple risks if this program is not adequately funded. The clearest risk would be to public
and personnel safety, for example, if the integrity of Avista's protection systems are not adequately
monitored remotely for their ability to protect Avista electric and gas infrastructure and any potential
public contact with Avista gas and electric infrastructure. The control systems supported by this
business case provide real-time visibility, situational awareness, and control of Avista's electric and
gas systems. Degradation of these capabilities due to lack of capacity, capability, or aging systems
would present increased safety risk. Additionally there is significant compliance risk and legal
negligence liability risk from potential public lawsuits. For example, historic penalties for multiple
violations of a handful of requirements are around $300,000, however it varies, and can exceed
upwards of$2M for non-compliance with NERC CIP standards:
WECC2018019376 CIP-007-6 R5
WECC2018019192 CIP-010-2 R1
$378,000 WECC2017018484 CIP-010-2 M
WECC2017018485 CIP-010-2 R2
WECC2018019012 CIP-010-2 R2
Business Case Justification Narrative Template Version: February 2023 Page 4 of 13
Exhibit No. 10
Case Nos.AW-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 198 of 535

SCADA - SOO and BuCC
WECC20180194M CIP-007-1
WECC2017017880 CIP-007-1
WECC2017017881 CIP-007-1
$2,100,000 WECC2017017882 CIP-007-1
WECC2018019481 CIP-007-1
WECC2017017883 CIP-010-2
WECC2017017884 CIP-010-2
These control systems provide the capabilities required to achieve compliance with numerous
reliability standards and requirements. For the electrical system these include the NERC standards
BAL, COM, CIP, EOP, INT, PER, PRC, TOP, and VAR. For the gas system these include the
PHMSA "Pipeline Safety: Control Room Management/Human Factors" rule (49 CFR Parts 192 and
195.)
The expenditure of these funds is necessary to operate Avista's electric and gas systems in a safe,
reliable, and compliant manner.
In addition to the risks related to public and personnel safety, compliance risk would be increased
without this investment. Non-compliant operational capabilities and practices would result in
negative audit findings, significant financial penalties, and litigation expenses. Obsolete equipment
would remain in service until failure. Additional capacity for growth may or may not be suitable for
required expansions to meet other needs (e.g. Regulatory, Smart Grid.)
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
The proposed funding of this Business Case aligns with the following strategic vision, goals,
objectives, and mission statement of Avista as follows:
Avista's Focus:
- Our Customers: Avista's gas and electric customers are benefited by the safe and reliable
operation of our energy management systems in the control and protection of our electric and
gas infrastructure assets serving all of our electric and gas customers.
- Our People: Avista's employees benefit from implementing and operating the latest control
center technologies and increased morale in the opportunity to participate in the installation,
maintenance, and ownership of these systems.
- Perform: Control Center technologies supported by this Business Case are required to
affordably operate and maintain safe, clean, reliable generation and energy delivery
infrastructure.
- Invent: Control Center technologies deployed by this Business Case are based on the most up-
to-date and innovative vendor supplied systems available. For example,this Business Case will
soon support the operation of the next-generation Advanced Distribution Management System
that accommodates the integration of distribution control center operations and customer outage
management systems.
Avista's Values:
- Trustworthy: By funding the secure operation of Avista's electric and gas energy management
systems, customer trust is maintained when gas and electric service is not interrupted by cyber
security attacks.
- Innovative: Avista's control center staff are continually looking for opportunities to more safely
and efficiently operate and manage our control center systems within funding contstraints. One
example is the migration of more systems toward virtual machine environments that eliminate
hardware obsolence dependencies and the vulnerability to hardware failures.
- Collaborative: Avista's control center staff also collaborate with corporate experts in deploying
the latest and company standard technologies to synergize in support of new system
Business Case Justification Narrative Template Version: February 2023 Page 5 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 199 of 535

SCADA - SOO and BuCC
deployments. One example is our recent firewall replacement projects migrating to a common
platform that is used across the company. This also gains financial benefits by increasing our
vendor licensing footprints and ability to benefit from quantity discounts.
It is essential in providing sufficient control center technology tools, situational awareness, and
monitor/control capabilities to achieve reliable energy service.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
NERC reliability standards and TSA directives contain such requirements as the NERC CIP-007
Requirement R2 to track, evaluate, and apply cyber security patches or mitigation plans for electric
and gas SCADA control systems that are found to have a security vulnerability. If control system
hardware and application software is not replaced and/or upgraded on a frequent enough cycle, the
hardware and application software reaches end of vendor support, beyond which it gets more difficult
and costly for the vendors to provide for security support on these systems. This Business Case
meets these NERC and TSA directive security requirements by providing for system upgrades in a
timely enough cycle to keep the systems under vendor support to mitigate against security
vulnerabilities.
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The proposed Business Case solutions address expanding regulatory and business requirements to
provide for replacement of existing technology, as well as for deployment of new applications and
technology as required. Examples of previous work completed and how this work addressed these
requirements follow:
NERC CIP-012 project — In 2022, routers were replaced with AT&T supplied routers to meet
encryption requirements for the transmission of all Real-Time Monitoring and Real-Time Assessment
data that is exchanged between Balancing Authority Control Centers. CIP-012, as of the July 1,
2023 effective date, requires Avista to protect the transmission of this data. This was the only option
Avista had to choose from in that the new routers were pre-engineered by the Reliability Coordinator,
RCWEST, in coordination with AT&T, that has been deployed by all Balancing Authorities in the
WECC connecting to the WECC Wide Operational Network.
SCADA Switch Refresh project — In 2022, switches that are nearing end of support are being
replaced with the latest model. Updated hardware will provide better reliability for our Control Center
systems and better security adherence and postures to meet NERC CIP compliance requirements.
EMS Upgrade project — In 2021, the server hardware and applications for the main Energy
Management System were all upgraded to the latest supported vendor versions. These systems
were well past the end of Extended Support and very much in need of refresh since the last upgrade
in 2010. This upgrade also brought along with it the replacement of physical server hardware with a
new virtual machine environment for our NERC-CIP systems. This will allow us to replace physical
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 200 of 535

SCADA - SOO and BuCC
hardware on a more rigorous schedule without having to replacing the very complex SCADA/EMS
applications at the same time to better keep up with vendor supported hardware systems. While
maybe not the most least cost alternative to configure a new virtual machine environment, it is the
only solution to meet hardware obscesence constraints without impacting critical control system
application software and also to mitigate against pre-mature hardware failures.
Again per above, the risk to Avista for hardware/software operations beyond Extended Support
periods is increased O&M exposure, for example, should Avista require GE to backport security-
related updates; additional O&M requirements could exceed over$200k.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
This capital request was prepared based on typical yet ever-increasing annual $800k
to 1.2M costs required to meet the needs for this business case. Over$31M in additional
funding is included for 2027 and 2028 when we plan to again upgrade our main EMS
system recently upgraded in 2020 and 2021 per the spikes above typical costs as
shown below.
SCADA Capital Spend History
$2,000,000
$1,800,000
$1,600,000
$1,400,000
$1,200,000
$1,000,000
$800,000
$600,000
$400,000
$200 OW
$0
2005 2007 2009 2011 2013 2015 2017 2019 2021 2023
2022 came higher at almost$1 M as we took on several upgrade projects inclusive of the
following projects for example:
• SCADA Switch Refresh
• SCADA Internal Firewall Refresh
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 201 of 535

SCADA - SOO and BuCC
• SCADA External Firewall Refresh
• SCADA SOO NetApp Refresh — network storage device
• Operator Training Simulator
• CIP-012 Protections Project
2023 came in at$1.9M as we migrated our$300k annual O&M licensing and support paid
for GE's EMS software to a 5-year term license for $1.4M. In late 2023, our SCADA
vendor required Avista to move from a perpetual EMS licensing agreement (O&M costs)
to a five-year term license agreement that could be capitalized at an 80/20 split. Therefore,
an additional $1.4M in capital costs were incurred in 2023 than were typically expected
and originally planned for.
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and OW) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital EMS 5yr Term Licensing (80% $ $ $ $2M est $
cap)
0&M EMS 5yr Term-Perpetual diff -$311 k -$363k -$421 k -$560k -$643K
Typically, there are no direct offset or savings associated with capital investments in this
Business Case other than reduced overtime and O&M labor associated with the
increased need for repair and maintenance on hardware that is operated into and beyond
its Extended Support dates.
Direct offset or savings in O&M software support costs are expected as a result of this
business case's funding for the 2028 renewal of this five year term EMS licensing for
approximately $2M. Similar to the original five year term EMS licensing purchase, per
Section 1.1.4 in the 2023 CPG funds change request for GE EMS licensing, annually
escalating costs of$358k in perpetual licensing renewals will be reduced to$92k annually
for EMS 5-year term licensing. In summary, assuming a 12.75% escalation of former
annual perpetual licensing renewals, 5yr term licensing provides a break-even over five
years.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital EMS Upgrade Project $ $ $1M est $0.3M est $
0&M GE security update back-port $250k $250k
Other direct offset or savings associated with the $1.3M labor portion of the 2027-2028
EMS Upgrade project. If this project is not completed, Avista's faces increased risk to
additional O&M cost exposure should Avista require GE to backport security-related
updates to out-of-support EMS software; additional O&M requirements to fund this effort
could exceed over $200k. A recent 2024 quote listed hourly rates of $352/hr to $671/hr
for back-porting new GE application code to our current older EMS version totalling over
$200k just for GE's labor portion, not including additional labor Avista SCADA resources
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2023 Page 8 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 202 of 535

SCADA - SOO and BuCC
would be required (i.e. estimate $25k to $50k???). In theory, this could occur every year
past End-of-Support after 2027.
2.4 Summarize in the table and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
There are no indirect offset or savings associated with capital investments in this
Business Case other than reduced overtime and O&M labor associated with the
increased need for repair and maintenance on hardware that is operated into and beyond
its Extended Support dates. This labor savings will indirectly allow Avista's labor
resources to be directed toward other important Business Case objectives.
An example indirect offset can be shown for a capital project, "SCADA Hardware
Refresh", typically used to replace aging and end-of-support server and workstation
hardware in a timely fashion before end-of-support. This mitigates against diverting labor
resources away from capital projects and towards emergency troubleshooting and repair
activities. A recent server failure resulted in SCADA resources spending over three days
of labor replacing a failed server on overtime for a total cost of about $5,000 in O&M
dollars (25 hr* 1.5 * $180/hr— $7,000). In 2024, for example, we will need to replace two
virtual machine host servers costing about $50,000. An alternative could be to defer this
replacement taking on risk of failure/recovery labor and an unquantifiable risk to the
reliable operation of the Bulk Electric System. Upon failure, we would also be faced with
loss of redundancy for the EMS systems while new hardware is either repaired or
replaced and worse yet, further subjected to supply chain delays.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
The following is a list of example projects to be funded under this five year business
case that are all driven by a need to replace equipment and software reaching the end
of life
o SCADA Front-End upgrades,
o Inter-Control Center Communication server upgrades
o Energy Management System upgrade.
Alternative 1:
The above example projects involve replacing hardware and SCADA vendor-provided
software. The alternatives that are considered in these projects are changing SCADA
vendors, changing server hardware manufacturers, or changing the server hardware
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 9 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 203 of 535

SCADA - SOO and BuCC
platforms. Changing SCADA vendors is not a feasible consideration given that multiple
systems would need to be changed all at once requiring a large capital project endeavor
on the order of$5 to $20M. Changing server hardware manufacturers is a feasible and
likely net-zero cost consideration, however, it would not line up with Avista's corporate
IT model that has a particular server manufacturer in portfolio and under existing
support contracts.
One alternative, however, that we have considered as part of these system upgrades
over that past several years is moving from physical to virtual server hardware
platforms. These virtual platforms have had sufficient time to prove their reliability and
SCADA vendors have given their blessing on implementation and this alternative
naturally lines up with Avista's corporate IT model for server hardware platforms. The
benefit of virtual hardware gains Avista independence from hardware obsolescence in
that we no longer have to upgrade an entire EMS system when hardware reaches end
of life. We can simply replace the underlying virtual server hardware host for around
$25k/each running the same virtual EMS software, thus deferring the physical
hardware failure driven need for a major $2M capital project to also upgrade the entire
EMS application software suite.
Alternative 2:
There is certainly a "No Funding" option available for any one of the individual projects
under this Business Case. However, it needs to be recognized that there will be
increased risk to the reliability and operational costs to the business. For example,
funding was denied for the refresh and expansion of our backup storage system at the
end of 2021. Risk therefore was increased of running out of sufficient disk space to
keep SCADA server systems operational and the backups of those systems up-to-date
in case of failure and the need for system recovery. Without a system backup to recover
from, rather than taking four hours of one labor resource, it would require maybe 40
hours of SCADA engineering and possibly additional consultant assistance to rebuild
an EMS server, for example, from the ground up. 40 hours at $280 per hour would
come to $11,200.
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
A metric that could be used to demonstrate how the investment delivered on remedying the
obsolescence of hardware and software is SCADA's one-pager downtime log. SCADA's
reliability target for keeping Avista's energy management systems running is 99.98% of the
time. If we fail to meet this annual target specifically due to hardware and software failures
or security breaches, this could be an indication the investment may not be meeting
Business Case objectives. In 2023, for example, we met a year-to-date SCADA uptime
target of 99.995%, well above the 99.98% objective.
Business Case Justification Narrative Template Version: February 2023 Page 10 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 204 of 535

SCADA - SOO and BuCC
YTD SCADA Uptime
100.000%
99.99590
99.990%
99.98590
99.98090
99.975%
99.9700)0
99.965%
99.96090
99.955%
99.950%
069 �eF � '
del
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
This business case is comprised of multiple individual capital projects that all close upon
completion over the course of the next five years, at which time they are transferred to plant
and become used-and-useful. For example, here are some around multi-year projects that
cause abnormal delays in transfer-to-plant above SCADA's normal $800k-$1.2M annually.
2025
- $3.3M EMS Upgrade project is expected to start in 2027 and complete by the end of
2028.
There are two "revolving" projects, however, SCADA Hardware Refresh and SCADA
Expansion, that are for minor refresh and expansion items like computer servers, desktop
pcs, monitors, etc. These projects are placed into service immediately and become used-
and-useful right as they are purchased and deployed.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
The steering committee/advisory group for initial and ongoing vetting and department
priorization process includes the members from the entire SCADA team as needed, but
more notably the following:
- Director of System Operations and Planning
- Manager of Energy Management Systems (EMS/ADMS)
- Sr. Security Engineer
Business Case Justification Narrative Template Version: February 2023 Page 11 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 205 of 535

SCADA - SOO and BuCC
Individual projects are governed by the SCADA team member assigned to the project
as project lead who is tasked with scheduling and coordinating all the work associated
with the project.
Project oversight is provided by the SCADA manager primarily, but also to the
assigned project lead.
The steering committee provides governance and oversight of this business case.
The Manager of EMS/ADMS has multiple check-in meetings per week scheduled
within the Energy Management Systems group during which to track progress of
the various capital projects that comprise the total business case.
Decision-making, prioritization, and change requests at the individual capital project
level are taken care of within the Energy Management Systems group under manager
supervision.
Any need for substantial change requests to capital projects that would deviate from
the original Capital Project Request (CPR) are documented and submitted to Project
Accounting as a revised CPR. Change requests and resulting decisions that lead to
significant changes in project scope are documented in the project charter
documentation and revisions to the original version and stored in SCADA's SharePoint
site.
Prioritization for each individual project within this business case is performed by the
SCADA manager as part of the on-going updates to SCADA's annual capital budget
spreadsheet. If the sum total of all SCADA capital projects is expected to exceed the
approved Business Case funding, then a Business Case Change Request must be
approved by the Steering Committee and submitted to Project Accounting.
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the SCADA —SOO and BuCC Business
Case and agree with the approach it presents. Significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Signature: /t/) Date: May 3, 2024
Print Name: Craig N. Figart
Title: Mgr Energy Mgmt Systems
Role: Business Case Owner
Signature: ,4 Date: May 3, 2024
Print Name: Michael A. Magruder
Title: Director, System Operations &
Planning
Business Case Justification Narrative Template Version: February 2023 Page 12 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 206 of 535

SCADA - SOO and BuCC
Role: Business Case Sponsor
Signature: Date: May 3, 2024
Print Name: Craig N. Figart
Title: Mgr Energy Mgmt Systems
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 13 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 207 of 535

DocuSign Envelope ID:5697FOBB-C658-4212-801D-35AF9709388B
Substation - West Plains System Reinforcement<Project
Name>
EXECUTIVE SUMMARY
The West Plains area load has increased in the past few years and continues to grow at a rate outpacing
Avista's average service territory load growth rate. Between 2018-2022, a 3 - 3 '/z% growth rate has been
observed and is forecasted to continue for the next 5-10 years. The growth has strained the transmission
system to the extent that system reliability cannot be maintained while accommodating system outages as
required under applicable operational performance requirements and NERC TPL-001-5. Government,
tribal, public, and private entities have invested significant time and money in the area and are working to
establish area backbone infrastructure. Avista is being asked to join these efforts by readying and fortifying
the electric grid to accommodate future expanding economic development.
The West Plains area requires a new 230kV source into the area to support the system and improve
reliability and operability while offloading existing 230/115kV transformers in Spokane. The new 230kV
source will improve contingency situation results and give increased ability to meet existing and future
customer demand. The project will reduce the potential of customer outages under heavy summer loading
scenarios. Without the project, customers may have power turned off under certain outage combination
conditions.
The scope of the project includes a new 230/115kV station near the West Plains at Garden Springs, new
230kV station to interconnect with the Bonneville Power Administration called Bluebird, and a new 12-mile
230kV transmission line. The new infrastructure is major investment in the transmission system which is
needed to serve our customers.The total project cost of all aspects of West Plains is estimated to be almost
$80M and will take over four years to engineer and construct.
The new 230kV source is critical to meet anticipated load growth in the area. The timing for completion is
sensitive as operational performance have been observed in the operations time-horizon and performance
is expected to worsen as new load connects to the system.
VERSION HISTORY
Version Author Description Date
Karen Kusel/
1.0 Glenn Madden/ Initial draft of original business case May 2023
John Gross
BCRT Team Has been reviewed by BCRT and meets necessary requirements
BCRT Member Steve Carrozzo 05/12/2023
Business Case Justification Narrative Template Version: February 2023 taMgit1Wf la
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 208 of 535

DocuSign Envelope ID:5697FOBB-C658-4212-801D-35AF9709388B
Substation - West Plains System Reinforcement<Project
Name>
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT($) PLANNED TRANSFER TO PLANT ($)
2024 $6,110,000
2025 $23,150,000
$25,800,000 $5,000,000
2026 (HV Breakers and Power
Transformers)
2027 $18,600,000 $37,100,000
2028 $0
Project Life Span 10 years
Requesting Organ lization/De artment Substation Engineering
Business Case Owner I Sponsor Glenn Madden Vern Malensk
Sponsor Organ lization/De artment M08
Phase Planning
Category Project
Driver Performance & Capacity
Definitions for the Category and Driver can be found on the Business Case Review Team Team's
site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case
information conveying the benefit to the customer, what the project will do and current
problem statement.
1.1. What is the current or potential problem that is being addressed?
The West Plains area is located west of the City of Spokane consisting of the City of Airway Heights,
Medical Lake, City of Cheney, Fairchild Air Force Base, and the Spokane International Airport.
Distribution service in the area is provided by Inland Power& Light as well as Avista. Avista is the only
Transmission Service Provider, Transmission Operator, Transmission Planner, and Planning
Coordinator in the area.
The transmission system in the West Plains area has several constraints due to lack of necessary
transmission infrastructure serving the existing and future loads. The West Plains Study and
Reinforcement Plan identifies projects mitigating transmission system performance issues in the West
Plains Area related to transferring power from the existing 230 kV system to load located in the West
Plains.
The West Plains Study and Reinforcement Plan is intended to be a long term and comprehensive plan.
The plan includes projects improving transmission system performance issues, and addresses issues
forecasted to occur in the planning horizon from a single utility approach.
The West Plains system is electrically supported through three stations: Westside, Sunset, and Devil's
Gap Substations. The Westside Substation is located north of the West Plains and offers a strong
230kV source supported primarily from the Bonneville Power Administration (BPA)'s transmission
system. Sunset Substation is located east of West Plains and brings energy to the West Plains through
Business Case Justification Narrative Template Version: February 2023 tx`MgiM1 as
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 209 of 535

DocuSign Envelope ID:5697FOBB-C658-4212-801D-35AF9709388B
Substation - West Plains System Reinforcement<Project
Name>
the downtown Spokane area, linking the reliability of these two strategic areas. Devil's Gap Substation
is located northwest of West Plains and provides a sturdy source supported primarily from the Little
Falls/Long Lake generation within Avista's system. The figure below provides a one line identifying the
electrical transmission system supporting the West Plains.
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Load growth in Avista's service territory has been approximately 0.5% between 2010 and 2022. The
West Plains area represents one of our fastest load growth areas. Between 2018-2022, a 3 - 3 '/2%
growth rate has been observed and is forecasted to continue for the next 5-10 years. This rate has
been corroborated with the following local electric utilities in the area: the Bonneville Power
Administration,the City of Cheney, and Inland Power&Light Co. Specific customer large load additions
have been identified and are illustrated on the following map. Shaded polygons on the map represent
a specific customer interconnection request.
Business Case Justification Narrative Template Version: February 2023 tx`Mgit3lof as
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 210 of 535

DocuSign Envelope ID:5697FOBB-C658-4212-801D-35AF9709388B
Substation - West Plains System Reinforcement<Project
Name>
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Ga9or Ne1gMt
The growth in the West Plains area has accelerated by a concerted effort toward economic
development and expansion. Government, tribal, public, and private entities have invested significant
time and money toward this endeavor and are working to establish area backbone infrastructure that
will be needed. Avista is being asked to join these efforts by readying and fortifying the electric grid to
accommodate future expanding economic development. The following list are examples of significant
monetary investments in infrastructure for future growth.
• Completion of a new railroad spur
• Accelerated transload facility project (efficient transfer between rail cars and trucks)
• Revised DOT trip requirements to include West Plains as single-day trip from ports
• Accelerated 1-90 interchange projects at Geiger and Medical Lake
• Reconstruction of Geiger Boulevard
• Established airport acreage development area
• Formed PDA partnership (multi-jurisdictional focus between Spokane, Spokane County, and
Fairchild)
By understanding these efforts, it is evident that West Plains Area entities are actively placing time,
efforts, and monetary funds toward ensuring that the area load growth is sustained in the West Plains
region.
There are existing system performance issues in the West Plains Area. Powerflow studies show the
West Plains Area transmission infrastructure is unable to accommodate all required outage scenarios
without overloads to the system. Four contingency scenarios are provided below as examples of
insufficient system performance in the West Plains Area transmission system.
1. An outage of two transmission lines to Westside Substation results in exceedance of applicable
facility ratings which requires forced outages to customers to reduce system loading.
Business Case Justification Narrative Template Version: February 2023 taMgit�f I0
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J. DiLuciano,Avista
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DocuSign Envelope ID:5697FOBB-C658-4212-801D-35AF9709388B
Substation - West Plains System Reinforcement<Project
Name>
2. A simultaneous outage of two transmission lines into the West Plains results in exceedance of
applicable facility ratings which requires forced outages to customers to reduce system loading.
3. The loss of a Westside Substation transmission line into the West Plains area and the
simultaneous loss of a Beacon-Ross Park transmission line results in exceedance of applicable
facility ratings which requires forced outages to customers to reduce system loading.
4. A breaker failure outage on the bus tie breaker at Beacon Substation results in overloads to the
existing system.
The system does not have the flexibility and resiliency needed for operating the system. Two examples
depicting these operational limitations are provided below.
1. System Operators are restricted from opening the Sunset-Westside 115kV Transmission Line
and the College &Walnut—Sunset 115kV Transmission Line without resulting in overloads to the
system.
2. System Operators are unable to restore the system under the following condition:
If generation is low in the downtown Spokane area (Upper Falls generation and Monroe
Street generation) and the Spokane Waste-to-Energy plant is down for routine, mid-
summer maintenance,
And an outage occurs on the Sunset—Westside 115kV Transmission Line,
Then the system is unrestorable resulting in customer outages until the forced outage can
be repaired.
This scenario presents itself annually in July in the daily operational studies work.
A Corrective Action Plan, as required in NERC TPL-001-5, is necessary to mitigate the performance
issues. An effective Corrective Action Plan will include project(s) to mitigate the observed overloaded
transmission lines and provide improved system resiliency for serving new customer growth in the area.
The system capacity concerns of the West Plains area are not only evident in the area transmission
system but are also present in the area distribution system. The distribution system within the West
Plains does not have the capacity needed for expected load requirements. Also, upgrades and
additions are necessary to maintain adequate reliability and operational flexibility. Within the West
Plains distribution system there are station configuration constraints, inadequate station redundancy
and an absence of infrastructure in larger growth areas. The West Plains Reinforcement Plan considers
these problems and their probable solutions in mind. However, distribution issues will be addressed in
a separate document and justification will not be included as part of the West Plains Reinforcement
Plan.
1.2. Discuss the major drivers of the business case.
The West Plains System Reinforcement Project primary driver is Performance and Capacity with a
secondary driver of Mandatory and Compliance.
Performance and Capacity:
As outlined in Section 1.1, the transmission system performance does not meet applicable criteria due
to lack of capacity to serve customer load in the West Plains Area.
Mandatory and Compliance:
NERC Standard TPL-001-5 requires Avista to establish performance criteria to be evaluated in the
short and long-term planning horizons. When studies show the transmission system is unable to meet
the applicable criteria, a Corrective Action Plan needs to be developed and eventually implemented.
Obligations to implement Corrective Action Plans are not clearly defined within TPL-001-5. The
objective of completing Corrective Action Plans is to ensure the transmission system can operate
securely through the process of planning ahead and not reacting to events.
Business Case Justification Narrative Template Version: February 2023 taMgitVf IR
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 212 of 535

DocuSign Envelope ID:5697FOBB-C658-4212-801D-35AF9709388B
Substation - West Plains System Reinforcement<Project
Name>
Components of the Customer Requested and Customer Service Quality and Reliability investment
drivers may be associated with the West Plains System Reinforcement Project from a qualitative
perspective. Customers are requesting new or increased service in the West Plains area. Without the
construction of the West Plains System Reinforcement project, the transmission system will not be
capable of serving the new customer load. Reliability impacts from transmission system issues are
often difficult to describe as the system has been designed to minimize impacts to customers when
there are outages on the system. The risk of not constructing the West Plains System Reinforcement
project has the potential to result in reliability issues customer due to lack of sufficient redundancy built
into the system during outage scenarios.
1.3. Identify why this work is needed now and what risks there are if not approved or if
deferred or risks being mitigated by the request.
The West Plains System Reinforcement project is needed in the near future because performance
issues identified in the planning horizon have begun to materialize in the operations time horizon.
During summer conditions Operational Planning Analysis (next day studies) have shown forced
transmission line or transformer outages may require the reduction of load (turning customers power
off) to ensure the system can operate acceptably for the next possible outage as required with the
Reliability Coordinators System Operating Limit Methodology.
Deferral of the project in past years has presented additional risk. Real time performance issues
typically have low probability of occurrence but with high consequence. Continuing to defer the project
will increase the probability of issues arising due to increased load in the area increase of the
consequence as more load is needed to be shed to mitigate issues that arise. Load growth is expected
to be 3% a year in the local area.Additional load growth in the greater Spokane area contributes to the
issues defined in the problem statement.
The scope of the project includes large infrastructure investments which will require several years to
construct. The project must be started in advance of the need or as soon as possible as the need has
been seen in the operations time horizon. Construction of a new 12-mile 230kV transmission line
through populated area will likely present challenging schedule issues. Deferring the project will also
increase transmission line routing issues as the area becomes more populated as acquiring new right-
of-way for the transmission line will impact more landowners.
1.4. Discuss how the proposed investment,whether project or program, aligns with the
strategic vision, goals, objectives and mission statement of the organization. See
link.
The West Plains System Reinforcement project provides additional capacity to the system which is
"critical to serving our customers well and unlocking pathways to growth." The Perform Focus Area of
Avista's focus goals is the primary alignment with the requested project but there are elements to the
project which are aligned with the theme of our Vision, Mission, and Focus Areas.
Our Customers:
Existing and future customers in the West Plains area expect to have electrical service. Avista needs
to deliver a system which can serve the customer demands and continue to meet the company's
defined reliability objectives.
Our People:
The portion of our company who will support the implementation of the project represents a core electric
utility collection of our employees. These employees will take pride in the efforts of such a
transformative project which will impact the West Plains community in a positive way.
Perform:
Business Case Justification Narrative Template Version: February 2023 tagit�f as
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 213 of 535

DocuSign Envelope ID:5697FOBB-C658-4212-801D-35AF9709388B
Substation - West Plains System Reinforcement<Project
Name>
With completion of the project, Avista will be unlocking growth potential in the West Plains area.
Invent:
Constructing transmission lines and substations are traditional project alternatives but Avista has the
opportunity to improve the construction and delivery process as part of such a large-scale project.
Vision; Better energy for life:
Investment in the transmission system represents a long term invest of infrastructure which will be in
place to serve our customers for several generations.
Mission; We improve our customers' lives through innovative energy solutions:
The West Plains System Reinforcement project has been identified as the most prudent energy solution
to deliver the high-level capacity needed to serve the area. The additional capacity is needed to meet
our customer's need for power.
1.5. Supplemental Information — please describe and summarize the key findings from
any relevant studies, analyses, documentation, photographic evidence, or other
materials that explain the problem this business case will resolve.'
System Planning has completed a thorough system study for this project. Many of the details have
been added to this business case document, for more details please see the full study: West Plains
Study and Reinforcement Plan Version 2 (West Plains 2020 Study - V5.pdf). Additionally, the
transmission system is analyzed bi-annually through the System Assessment process performed by
the System Planning team.The most recent System Assessment is the 2021-2020 System Assessment
Version 2 (2021-2022 Avista System Assess ment-V2.pdf). An example of study results is shown in the
below figure from the System Assessment which illustrates transmission line facility rating issues during
outage scenario if the project is not constructed.
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' Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 taMgit7Wf as
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 214 of 535

DocuSign Envelope ID:5697FOBB-C658-4212-801D-35AF9709388B
Substation - West Plains System Reinforcement<Project
Name>
2. PROPOSAL AND RECOMMENDED SOLUTION - Describe the proposed
solution to the business problem identified above and why this is the best and/or least cost
alternative (e.g., cost benefit analysis).
2.1. Please summarize the proposed solution and how it helps to solve the business
problem identified above.
The following figure illustrates the intended scope of the West Plains System Reinforcement project.
Garden Springs Project
Project Description
OConstruct a 3-position 230kV double bus double breaker arrangement with space for 3 future
positions at the existing Garden Springs switching station piope dy.Construct a]-position 115kV
breaker and a half arrangement with space for 2 future positions and future distribution equipment.
Install two 250MVA 230/115kV transformers.
115kV to O Construct,3-position 230kV double bus double breaker arrangement with space for 3 future
Existing Facilities Devils Gap Bluebird 2 positions near the Intersection of the Airway Heights-Devils Gap 115kV line and the Bell-Coulee
Planned A—ta Facilities O nidor.Line and Load interc ection request with BPA(L0485)define,the scope of line
Proposed Avisla Facilities nlerconnections to the existing BPA Bell-Coulee#5 2301,V line.
OCar,—a 12-mile Bluebird to Garden Springs 230kV transmission line.
®Upgrade line section between Garden Springs and Sonnet on the existing Sonnet-Westside 115kV
line.
115,230, 115,230,
500kV to 4xxxxxxxxxxxxx 500kV to
Grand Coulee Bell
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Shawnee
The West Plains Reinforcement Project will consist of a new 230kV connection to BPA's system,
electrically placed near the strong generation source of the Coulee Dam. This connection will be
made through a new station called Bluebird Substation, located off the BPA's Bell—Coulee#5 230kV
Transmission Line. From Bluebird Substation a 230kV transmission line will carry energy south into
the West Plains to Garden Springs Station. The Garden Springs Station will include two new
230/115kV, 250 MVA transformers, also addressing transformation capacity issues. The scope of
this work includes:
Construct a new 230kV substation at Garden Springs and include two 250MVA, 230/115kV
transformers.
Construct a new 230kV substation (Bluebird Station) near the Bell — Coulee corridor and loop in
the Bell— Coulee#5 230kV Transmission Line
Business Case Justification Narrative Template Version: February 2023 t.aMgit8rp1 as
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 215 of 535

DocuSign Envelope ID:5697FOBB-C658-4212-801D-35AF9709388B
Substation - West Plains System Reinforcement<Project
Name>
• Construct a new(approximately 12.8 mile)230kV transmission line from Garden Springs to the Bell
—Coulee corridor.
Upgrade existing 115kV transmission line between Garden Springs and Sunset stations.
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2.2. Describe and provide reference to CIRRARR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other information that
was considered when preparing this business case (i.e., samples of savings,
benefits or risk avoidance estimates; description of how benefits to customers are
being measured; metrics such as comparison of cost ($) to benefit (value), or
evidence of spend amount to anticipated return).2
Study reports prepared by System Planning can be referenced for the West Plains System
Reinforcement Project. An example of work includes:
• Garden Spring Integration Project Feasibility Study-Version 0, 2013
• West Spokane Transmission Plan —Version 0, 2016
• West Plains Study and Reinforcement Plan—Version 2, 2020
• 2021-2022 Avista System Assessment—Version 2, 2022 (and previous versions)
The listed reports provide tabular study results showing improvement in system performance with
the completion of the project. For example, without the project specific transmission lines are shown
to exceed their applicable facility ratings under outage conditions and therefore the system does not
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 taMgit�f as
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 216 of 535

DocuSign Envelope ID:5697FOBB-C658-4212-801D-35AF9709388B
Substation - West Plains System Reinforcement<Project
Name>
meet performance criteria as required under NERC standard TPL-001.With completion of the project
the system's performance is improved.
2.3. Summarize in the table, and describe below the DIRECT offsets3 or savings (Capital
and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
O&M $ $ $ $ $
New transmission infrastructure projects are required to safely and reliably serve customers. No
direct offset or savings are expected as a result from this investment.
2.4. Summarize in the table, and describe below the INDIRECT offset4 (Capital and
O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
O&M $ $ $ $ $
No indirect capital or O&M offsets are expected to result from this investment. Qualitatively the
project reduces exposure to potential customer outages as described in the problem statement and
avoidance of possible fines for non-compliance with NERC standards. Both examples of savings
cannot be clearly defined with assumed values.
2.5. Describe in detail the alternatives, including proposed cost for each alternative,
that were considered, and why those alternatives did not provide the same benefit
as the chosen solution. Include those additional risks to Avista that may occur if
an alternative is selected.
Alternative 1 — Do Nothing /Status Quo: $0
This alternative is not recommended because it does not mitigate the expected capacity constraints
and does not comply with applicable NERC transmission planning standards. Operating Procedures,
such as not permitting outages related to other infrastructure projects and turning power off to
customers under specific conditions, may be used to defer some system deficiencies.
Alternative 2 —Construct the West Plains New 230kV Substation: $80,000,000
This alternative includes constructing a new 230kV station in the West Plains area.The 230kV station
would be sourced through a new 230kV transmission line interconnection with the Bonneville Power
Administration (BPA) and/or with connections to Westside Substation. The 115kV portion of the new
station is a part of the West Plains Transmission Reinforcement Plan which addresses reliability
issues and provides operational flexibility. All system deficiencies identified will be mitigated. Costs
of major components of this preferred alternative include:
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Pp%eib1totPof
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 217 of 535

DocuSign Envelope ID:5697FOBB-C658-4212-801D-35AF9709388B
Substation - West Plains System Reinforcement<Project
Name>
• $34,000,000—New Garden Springs station
• $11,500,000—New Bluebird station
• $28,000,000—New 230kV transmission line
Alternative 3—Airway Heights-Westside 115kV Transmission Line: $25,000,000
Constructing a new 9.5-mile 115kV transmission line from Airway Heights to Westside was
considered as an alternative. Outages at the Westside station, including the P6 outage of both
230/115kV transformers and P7 outage of the 230kV double circuit into Westside, continue to cause
performance issues. A new 230kV source to the Spokane area provides a more robust long-term
solution.
Alternative 4 — Garden Springs 230kV Station with 230kV Transmission Line to Westside:
$61,000,000
Constructing a 7.9-mile 230kV transmission line from Westside to a new Garden Springs station was
considered instead of the proposed Bluebird-Garden Springs 230kV Transmission Line
interconnection with BPA. Performance issues are not fully mitigated with this alternative.
Specifically, the P7 outage of the 230kV double circuit into Westside continues to be an issue and
right-of-way events between Westside and Garden Springs stations do not meet performance
criteria. Costs of major components of this alternative include:
• $34,000,000—New Garden Springs station
• $3,000,000—Westside station new line position
• $24,000,000 — New 230kV transmission line, including rebuilding existing 115kV lines in
same right of way.
2.6. Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will success
be measured).
Successful mitigation of the problem statement will be monitored as part of the bi-annual System
Assessment conducted by System Planning. The project will be successful if performance criteria in
short-term planning horizon studies can be met, and performance issues are not observed in the
operations time horizon.Assumptions made in System Assessments are not static therefore projects
are developed based on the best information available. For example,future load forecasts may show
additional load growth not expected when a project is requested. If the project takes ten years to
construct, it is possible the base line assumptions have changed, and additional projects will need to
be justified.
2.7. Please provide the timeline of when this work is schedule to commence and
complete, if known.
Schedule for new Bluebird 230kV Switching Station and the Garden Springs 230/115kV Station:
2023: Engineering Design, Major Equipment Purchases (1-2-year lead times)
2024: Engineering Design, Site Grading.
2025: Foundations, Structures and Electrical construction.
2026: Complete Electrical Construction.
2027: Commissioning and Testing, Final Project Closeout.
2026-2027: Construct new 230kV transmission line.
Business Case Justification Narrative Template Version: February 2023 Pp%eb1t10 I
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 218 of 535

DocuSign Envelope ID:5697FOBB-C658-4212-801D-35AF9709388B
Substation - West Plains System Reinforcement<Project
Name>
2.8. Please identify and describe the Steering Committee/governance team that are
responsible for the initial and ongoing approval and oversight of the business
case, and how such oversight will occur.
For the West Plains Reinforcement Project,there will be a Project Manager, Construction Inspectors
and Design Engineers (Transmission, Substation and Distribution)that will form the oversight group.
The Engineering Roundtable will provide technical review of potential scope changes with the
support of the System Planning and Operations department. Scope changes which require additional
fund requests to the Capital Planning Group will be vetted at the Engineering Roundtable.
Business Case Justification Narrative Template Version: February 2023 Pp%eb1Mf I
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 219 of 535

DocuSign Envelope ID:5697FOBB-C658-4212-801D-35AF9709388B
Substation - West Plains System Reinforcement<Project
Name>
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the West Plains System Reinforcement Project
and agree with the approach it presents. Significant changes to this will be coordinated with and
approved by the undersigned or their designated representatives.
DocuSigned by:
Signature: I WAA4, Date: May-12-2023 1 5:25 PM PDT
Print Name: 7D4B3Genr*Madden
Title: Substation Engineering Manager
Role: Business Case Owner
DocuSigned by:
Signature: l/eym, ill IAAAS W Date: May-14-2023 1 6:01 PM PDT
Print Name: osc4FF\,@ffl4MaIe risky
Title: Electrical Engineering Director
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Pp%eb1t�f
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 220 of 535

DocuSign Envelope ID:37473B22-EOD8-46C2-B56D-0375F2DEB494
Transmission Minor Rebuild
EXECUTIVE SUMMARY
Unlike Asset Management studies and analysis that develop long-term facility failure models, the inspection
protocols associated with the Transmission Minor Rebuild Business Case identify asset problems; that, if
left unaddressed, will lead to near-term catastrophic structural failures. These structural failure conditions, if
left unaddressed, will result in an increased risk of system failures, customers outages, and wildfires. This
includes the follow-up work to Wood Pole Inspections, Aerial Patrol inspections, Ad Hoc ground inspections,
and Air Switch Reliability complaints.
More specifically, this Business Case covers the Transmission rebuild and reconductor work necessary to
maintain compliance with the North American Electric Reliability Corporation (NERC) Reliability Standard
FAC-501-WECC-1 as applied through Avista's Transmission Maintenance Inspection Program (TMIP) This
standard mandates that specific Transmission lines be inspected annually and assessed for corrective
actions to be implemented to remedy any system performance deficiencies. The TMIP applies the same
inspection methodology to the entire Avista system with the understanding that only a portion of the mitigation
work is recognized as Mandatory and Compliance. The remaining work undertaken within this Business
Case is recognized as Customer Requested, Failed Plant and Asset Condition.
During routinely scheduled inspections, issues are discovered regarding the condition of assets, including
items such as rotten poles, broken/split/rotten crossarms, broken conductor or ground/shield wire, and air
switches that no longer operate safely or reliably.
The implementation of this business case will be considered successful if these projects are all completed
within the same year as inspection, on an annual basis, or the dates identified in the Engineering Roundtable
Project List.
The recommended solution is to correct the issues found by these inspections either in the same year, or
within 1-2 years afterwards. There are no expected business impacts to continuing this program in place. If
Avista does not fully implement this business case, it runs an increased risk of system failures, customers
outages, and wildfires. This Program will have a Service Code of Electric Direct and a Rate Jurisdiction of
Allocated North.
An annual spend of$4,350,000 is needed to complete the mitigations as follows:
• ER 2057, BI AMT12 and AMT13 ($2,000,000): Wood and Steel Pole Inspections (FAC-501-WECC-
1, TMIP)
• ER 2057, BI XT902 ($2,000,000): Aerial and ground inspections (FAC-501-WECC-1, TMIP, and Ad
Hoc)
• ER 2254, BI AMT10 ($350,000): Planned/unplanned replacements based on failure or upgrade
needs
By not funding this Business Case at the $4,350,000 projects are delayed, creating a bow wave of time
sensitive projects moving into outer years. Because of the limited outage windows available for construction
(six months out of the year) delaying a project typically means moving six months or over a year. Outage
windows are further complicated by competing interests from other departments and Business Cases. The
increased funding provides a flexibility in construction to offset this situation.
The customer benefits from this Business Case through increased overall system service reliability.
Business Case Justification Narrative Template Version: February 2023 Page 1 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 221 of 535

DocuSign Envelope ID:37473B22-EOD8-46C2-B56D-0375F2DEB494
Transmission Minor Rebuild
VERSION HISTORY
Version Author Description Date
1.0 Ken Sweigart Initial draft of original business case 311212024
BCRT Team Steve
BCRT Member Has been reviewed by BCRT and meets necessary requirements Carrozzo
51112024
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT($)
2024 $4,350,000 $4,350,000
2025 $4,350,000 $4,350,000
2026 $4,350,000 $4,350,000
2027 $4,350,000 $4,350,000
2028 $4,350,000 $4,350,000
2029 $4,350,000 $4,350,000
Project Life Span Continuous Program
Requesting Organization/Department TLD Engineering
Business Case Owner Sponsor Ken Sweigart/Vern Malensky
Sponsor Organization/Department Energy DeliverylElectrical Engineering
Phase Execution
Category Program
Driver Multiple (see Executive Summary)
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
During routinely scheduled inspections, issues are discovered regarding the condition of assets,
including items such as rotten poles, broken/split/rotten crossarms, broken conductor or ground/shield
wire, and air switches that no longer operate safely or reliably.
The recommended solution is to correct the issues found by these inspections either in the same year,
or within 1-2 years afterwards. There are no expected business impacts to continuing this program in
place. If Avista does not fully implement this business case, it runs an increased risk of system failures,
customers outages, and wildfires.
Business Case Justification Narrative Template Version: February 2023 Page 2 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 222 of 535

DocuSign Envelope ID:37473B22-EOD8-46C2-B56D-0375F2DEB494
Transmission Minor Rebuild
The customer benefits from this Business Case through increased service reliability.
1.1 What is the current or potential problem that is being addressed?
Avoidance of failure conditions; that, if left unaddressed will result in an increased risk of system
failures, customers outages, and wildfires.
1.2 Discuss the major drivers of the business case (in descending propriety).
Customer Requested: A small portion of the projects in this Business Case are Customer
Requested with an associated Contribution in Aid of Construction (CIAC) component.
Mandatory & Compliance: Both the Pole Inspection and Aerial Patrol Inspection programs for
Transmission facilities are linked to NERC Standard FAC-501-WECC-1.
Failed Plant: Projects linked to Ad Hoc Inspections and critical Pole Inspection/Aerial Patrol
Inspection results are implemented to address facilities that are a risk of imminent failure. These
near-term (<1-2 year) projects make up a portion of this Business Case.
Asset Condition: Projects linked to Pole Inspections and Aerial Patrols that identified under a 2-
5+ year need horizon make up a portion of the projects under this Business Case.
Customer benefits by having a Transmission System in compliance with Federal Standards, and
one where identified near-term failure risks are proacitively addressed.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
Unlike Asset Management studies and analysis that develop long-term facility failure models, the
inspection protocols associated with this Business Case identify asset problems; that, if left
unaddressed, will lead to near-term catastrophic structural failures.
Because of the limited outage windows available for construction (six months out of the year)
delaying a project typically means moving six months or over a year, resulting in a bow wave of
projects that accumulate with new annual inspections Outage windows are further complicated
by competing interests from other departments and Business Cases. The requested funding
provides a flexibility in construction to offset this situation
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strateizic Goals
This program focuses on our Customers by making sure that our word and system are reliable,
reducing outages and the risk of wildfire.
This program specifically supports the "Safety. Affordability. Responsibly" portion of the Avista
Mission Statement.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 223 of 535

DocuSign Envelope ID:37473B22-EOD8-46C2-B56D-0375F2DEB494
Transmission Minor Rebuild
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
Asset Maintenance Wood Pole Management annual inspection reports
Transmission Line Design annual aerial patrol reports
Ad hoc inspections and or real-time notifications from area offices
The above documents identify assets that have reached end of life; and, via testing and visual
inspection, are deemed likely to fail in the near term. These assets would typically be placed in
1-2 and 2-5+year anticipated failure categories, with the most critical deemed likely to fail before
end-of-year.
Outage requests on the Avista Transmission System are typically restricted to the lower load
months of March-May and September-November. The months of December-February and June-
August are Avista's Winter and Summer load peaking months respectively. During these months
planned outages are restricted due to system capacity and flexibility constraints.
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Proposed solution is to replace those assets deemed at risk of failing in the near term.
Replacement greatly reduces risk of failure and it removes any delay or other consequence
associated in replacing failed assets such as unplanned outages and potential wildfire
implications.
2.2 Describe and provide reference to CIRRARR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 224 of 535

DocuSign Envelope ID:37473B22-EOD8-46C2-B56D-0375F2DEB494
Transmission Minor Rebuild
The benefits of this Business Case are seen in something not happening. Pro-actively addressing
near-term failures results in avoiding public safety risks including physical, electrical, and fire. A
portion of this Business Case was previously funded through an Operations Business Case.
This program is in the Execution Stage with spend directed primarily at structure and structure
component change-outs resulting in facility failure avoidance.
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
Direct offsets associated with this project are the incremental costs associated with performing
work under emergency conditions versus planned conditions. Emergency conditions would likey
result in overtime wages and increased contractual expenditures. A lesser probability would be
for an unplanned outage to affect other planned outages, or possibly cause load to be dropped.
Unplanned outages negatively affect the overall Transmission System.
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $2,720 $2,720 $2,720 $2,720 $2,720
There are no additional indirect offsets associated with projects between 2025-2029. The nature
of the project (replacing poles, crossarms, or insulators only before end of life) does not change
maintenance schedules. The$2,720 offset is related to the changing out of conductor associated
with the 2023 Metro-Sunset Rebuild Project.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternatives under this Business Cases primarily resolve in a basic choice of either replacing or
not replacing the identified asset. The amount of work completed each year is tailored to the
available budget. When immediate replacements are required as a result of in-year inspection
s Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 225 of 535

DocuSign Envelope ID:37473B22-EOD8-46C2-B56D-0375F2DEB494
Transmission Minor Rebuild
additional monies may be requested. By not funding this Business Case at the $4,350,000
projects are delayed, creating a bow wave of time sensitive projects moving into outer years.
Alternative 1:
Do Nothing: Unlike Asset Management studies and analysis that develop long-term facility failure
models,the inspection protocols associated with this Business Case identify asset problems;that,
if left unaddressed, will lead to near-term catastrophic structural failures.
Alternative 2:
Reinforce: Only wood poles have an option for being reinforced rather than being replaced. This
is identified in the Wood Pole Inspection notes. This is further evaluated by the Engineer to
determine most cost effective response. The cost for reinforcing a pole is approximately$2,500,
and is the solution of choice when there are no other extenuating circumstances.
Alternative 3:
Replace Identified Assets: See commentary for Alternative 2. Where assets are not reinforced
the solution is to fully replace. The cost of replacing a pole leads to replacing the entire structure.
Similar to most installation projects the unit cost of replacing a pole/structure can vary based on
location, access,and other extenuating circumstances. $50,000 is generally a middle-of-the-road
estimate for replacing a structure.
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
As-Built confirmation of mitigation measures.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Outage requests on the Avista Transmission System are typically restricted to the lower load
months of March -May and September-November. The months of December-February and
June-August are Avista's Winter and Summer load peaking months respectively. During these
months planned outages are restricted due to system capacity and flexibility constraints.
Some smaller projects can take place throughout the year. Most projects take place in the
Spring or Fall months and Transfer to Plant in the June or November/December time frame.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
The Engineering Roundtable functions as the Vetting Platform, Steering Committee, and
Advisory Group.
Electrical Engineering Expected Spend Committee reviews on a monthly basis ongoing spend
for projects approved by the ERT. Committee members include Managers, Project Managers,
analysts, and the Electrical Engineering Director.
During the design phase these functions are processed through the Engineering Roundtable.
During large project Contracted construction, Change Orders are processed through Supply
Chain. On smaller in-house construction projects, changes are agreed upon at the Project
Eneginer/Project Manager, and are documented in the As-Built process.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 226 of 535

DocuSign Envelope ID:37473B22-EOD8-46C2-B56D-0375F2DEB494
Transmission Minor Rebuild
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Transmission Minor Rebuild Business
Case Justification Narrative and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated representatives.
DocuSigned by:
Signature: WU Date: May-02-2024 1 3:11 PM PDT
Print Name: 21 OC3W@ff�S%eigart
Title: Manager, Transmission Line Design
Role: Business Case Owner
DocuSigned by:
Signature: Vuy- hab l&stw Date: May-03-2024 1 1:51 PM PDT
Print Name: 06c4FF3MPffgValensky
Title: Director of Electrical Engineering
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 7 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 227 of 535

DocuSign Envelope ID: D96B1413-B150-4E36-BB6B-C1DF5EED8DC0
Transmission Construction - Compliance
EXECUTIVE SUMMARY
The Transmission Construction — Compliance Business Case covers the Transmission rebuild and
reconductor work necessary to maintain compliance with the NERC Reliability Standard TPL-001-4 —
Transmission System Planning Performance Requirements ("Standard"). It has 8 requirements and 57 sub-
requirements related to planning and analysis, including the requirement for robust system models to
determine system stability, voltage levels and system performance under various scenarios. This standard
mandates that an annual planning assessment be conducted and corrective actions be identified and
implemented to remedy any system performance deficiencies. In addition, when Avista's system planning
studies indicate any kind of problem that could arise in the transmission system, it must be remedied within
specific timeframes. The Transmission Construction -Compliance Program provides funding to mitigate any
identified reliability issues in order to remain in compliance with NERC requirements. As of Spring 2024
there are thirty-four (34) structures that need to be replaced on seven (7) transmission lines with
additional remediation expected as new Joint Use requests are received going forward.
The implementation of this business case will be considered successful if these projects are all completed
prior to the required compliance dates identified in the Engineering Roundtable Project List,which are copied
from the Corrective Action Plans (within the annually published Avista System Planning Assessment).
The Transmission Construction — Compliance Business Case also covers the Transmission line rebuild for
lines not meeting National Electric Safety Code (NESC) physical capacities for appropriate loading cases.
These code minimums have also been adopted into the State of Washington's Administrative Code (WAC).
These lines may have met the NESC criteria at the time of their original construction, but have been found to
not be up to standards through anaysis either as a result of requests for facility additions, or identified past
additions not analyzed at the time of installation.
The recommended solution is to build,rebuild,or reconductor transmission lines as identified in the Corrective
Action Plans to stay in compliance with NERC mandatory and enforceable Reliability Standards(most notably
TPL-001-4) and the NESC code (via WAC).
If Avista does not implement this business case,the company is at risk of violating NERC Reliability Standard
Requirements and could be subject to penalties of up to $1 M per day for the duration of any such violation.
Following a "do nothing"option for this business case would likely be treated as an aggravating factor by the
regulatory authority when assessing enforcement actions. If Avista does not fully implement this business
case, it also runs the risk of being fined for not staying in compliance with the NESC code and WAC rules.
There are no expected business impacts to continuing this program in place. A spend of $3,000,000 is
needed to complete the planned 2025-2029 projects . This Program will have a Service Code of Electric
Direct and a Rate Jurisdiction of Allocated North.
The 2025-2029 Business Case contains multiple identified and anticipated projects based on Joint Use
attachment analyses.
The customer benefits from this Business Case through increased service reliability and avoided fines
VERSION HISTORY
Version Author Description Date
1.0 Ken Sweigart Initial draft of original business case 311212024
Business Case Justification Narrative Template Version: February 2023 Page 1 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 228 of 535

DocuSign Envelope ID: D96B1413-B150-4E36-BB6B-C1DF5EED8DC0
Transmission Construction - Compliance
BCRT Team Steve
BCRT Member Has been reviewed by BCRT and meets necessary requirements Carrozzo
5101124
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT($)
2024 $1,000,000 $1,000,000
2025 $1,000,000 $1,000,000
2026 $500,000 $500,000
2027 $500,000 $500,000
2028 $500,000 $500,000
2029 $500,000 $500,000
Project Life Span Continuous Program and Individual Projects
Requesting Organization/Department TLD Engineering
Business Case Owner Sponsor Ken Sweigart/Vern Malensky
Sponsor Organization/Department Energy Delivery/Electrical Engineering
Phase Execution
Category Program and Projects
Driver Mandatory& Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
Business Case Justification Narrative Template Version: February 2023 Page 2 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 229 of 535

DocuSign Envelope ID: D96B1413-B150-4E36-BB6B-C1DF5EED8DC0
Transmission Construction - Compliance
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
The Transmission Construction — Compliance Business Case covers the Transmission rebuild
and reconductor work necessary to maintain compliance with the NERC Reliability Standard TPL-
001-4—Transmission System Planning Performance Requirements ("Standard"). This standard
mandates that an annual planning assessment be conducted and corrective actions be identified
and implemented to remedy any system performance deficiencies. Corrective Action Plans must
be completed within the required timeframe to meet the system performance requirements
dictated by the Standard.
The Transmission Construction —Compliance Business Case also covers the Transmission line
rebuild for lines not meeting National Electric Safety Code (NESC) physical capacities for
appropriate loading cases. These code minimums have also been adopted into the State of
Washington's Administrative Code (WAC). These lines may have met the NESC criteria at the
time of their original construction, but have been found to not be up to standards through anaysis
either as a result of requests for facility additions, or identified past additions not analyzed at the
time of installation. As of Spring 2024 there are thirty-four (34) structures that need to be
replaced on seven (7) transmission lines with additional remediation expected as new
Joint Use requests are received going forward. It is expected that 7-10 structures will be
addressed per year once the initial group of structures are replaced.
1.2 Discuss the major drivers of the business case.
Mandatory & Compliance: Customer benefits by having a Transmission System in compliance
with Federal Code and State Law. If Avista does not implement this business case, the company
is at risk of violating NERC Reliability Standard Requirements and could be subject to penalties
of up to $1 M per day for the duration of any such violation. State law (WAC) violations are
expected to have severe consequences as well.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
2.9 Concealment or Intentional Violation:
NERC or the Regional Entity shall always consider as an aggravating factor any attempt by a
violator to conceal the violation from NERC or the Regional Entity, or any intentional violation
incurred for purposes other than a demonstrably good faith effort to avoid a significant and greater
threat to the immediate reliability of the Bulk Power System.
2.10 Economic Choice to Violate:
Business Case Justification Narrative Template Version: February 2023 Page 3 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 230 of 535

DocuSign Envelope ID: D96B1413-B150-4E36-BB6B-C1DF5EED8DC0
Transmission Construction - Compliance
Penalties shall be sufficient to assure that entities responsible for complying with Reliability
Standards do not have incentives to make economic choices that cause or unduly risk violations
of Reliability Standards, or incidents resulting from violations of the Reliability Standards.
Economic choice includes economic gain for, or the avoidance of costs to, the violator. NERC or
the Regional Entity shall treat economic choice to violate as an aggravating factor when
determining a Penalty.
2.15 Maximum Limitations on Penalties:
In the United States, the maximum Penalty amount that NERC or a Regional Entity will assess
for a violation of a Reliability Standard Requirement is $1,000,000 per day per violation. NERC
and the Regional Entities will assess Penalties amounts up to and including this maximum amount
for violations where warranted pursuant to these Sanction Guidelines.
In the case of projects addressing NESC capacity inadequacies, Avista will be cognisant of not
meeting the WAC. As of Spring 2024 there are thirty-four(34)structures that need to be replaced
on seven (7) transmission lines with additional remediation expected as new Joint Use requests
are received going forward.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
This program specifically supports the "Safety. Affordability. Responsibly"portion of
the Avista Mission Statement.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 231 of 535

DocuSign Envelope ID: D96B1413-B150-4E36-BB6B-C1DF5EED8DC0
Transmission Construction - Compliance
Replacing overloaded poles helps guard against increasing risk for more failures and outages (in
addition to reducing litigation risks). Transmission outages can have significant consequences,
as they tend to impact a large number of customers and have the potential to start fires in dry
areas. In addition to reliability issues, failure to properly invest builds a bow-wave of needed
investments in the future, thus this program is crucial to maintaining operations.
The Transmission Construction —Compliance Business Case covers Transmission line rebuilds
for lines not meeting National Electric Safety Code (NESC) physical capacities for appropriate
loading cases. These code minimums have also been adopted into the State of Washington's
Administrative Code (WAC). These lines may have met the NESC criteria at the time of their
original construction, but have been found to not be up to standards through anaysis either as a
result of requests for facility additions, or identified past additions not analyzed at the time of
installation.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
APL-RAT 115kV Joint Use Request Structural Analysis(118-1112&411-418)
M23-TVW 115kV Joint Use Request Structural Analysis(3113)
9CE-OPT 115kV Joint Use Request Structural Analysis(5116)
AIR-FLT 115kV Joint Use Request Structural Analysis(0118, 1/11, 2/11 &2114)
CLW-LOL#1 115kV Joint Use Request Structural Analysis (415&416)
BEA-9CE#1 115kV Joint Use Request Structural Analysis(2112-2114)
9CE-3HT 115kV Joint Use Request Structural Analysis (313-3114)
The above are all reports prepared in response to 3rd party Joint Use (JU) attachment requests
showing an existing structural deficiency of 115kV structures beyond added JU responsibility.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 232 of 535

DocuSign Envelope ID: D96B1413-B150-4E36-BB6B-C1DF5EED8DC0
Transmission Construction - Compliance
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
This is the continuation of an ongoing Program and requires the replacement of
infrastructure to support compliance requirements.
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Proposed solution is to replace those assets (poles); that, by analysis, do not meet NESC
minimum strength requirements. Analysis takes place when a Joint User entity requests
attachment to an Avista Transmission pole. When analysis for a new attachment shows Avista
has a structurally overloaded pole not caused by the Joint User,Avista is obligated to replace the
pole. The NESC has been adopted by the Washington Administrative Code (WAC). Failing to
replace these structures will place Avista in violation of the WAC.
2.2 Describe and provide reference to CIRRARR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
The benefits of this Business Case are seen in something not happening. Pro-actively replacing
poles that are structurally overloaded and in violation of WAC adopted NESC standards results
in avoiding high consequence public safety risks including physical, electrical, and fire. It also
avoids, in the case of potential litigation, discovery of Avista knowingly being in violation of state
law(WAC). It is reasonable that the consequences of such a situation would be severe.. If Avista
does not implement this business case, the company is at risk of violating NERC Reliability
Standard Requirements and could be subject to penalties of up to $1 M per day for the duration
of any such violation. State law (WAC) violations are expected to have severe consequences as
well.
This program is in the Execution Stage with spend directed at structure change-outs resulting in
asset failure avoidance.
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 1 2026 1 2027 1 2028 1 2029
Capital $5,000 1 $5,000 $5,000 1 $5,000 1 $5,000
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 233 of 535

DocuSign Envelope ID: D96B1413-B150-4E36-BB6B-C1DF5EED8DC0
Transmission Construction - Compliance
0&M I $ $ Is $ $
Direct offsets associated with this project are the incremental costs associated with performing
work under emergency conditions versus planned conditions. Emergency conditions would
likey result in overtime wages and increased contractual expenditures. A lesser probability
would be for an unplanned outage to affect other planned outages, or possibly cause load to
be dropped. Unplanned outages negatively affect the overall Transmission System.
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
There are no additional indirect offsets associated with projects between 2025-2029. The
nature of the project(replacing poles) does not change maintenance schedules.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternatives under this Business Cases primarily resolve in a basic choice of either replacing or
not replacing the identified asset. The amount of work completed each year is tailored to the
available budget. When immediate replacements are required as a result of in-year inspection
additional monies may be requested. By not funding this Business Case at the requested amount
projects are delayed, creating a bow wave of time sensitive projects moving into outer years.
Alternative 1:
Maintain As-Is ($0 until a failure occurs): Proposed solution is to replace those assets (poles);
that, by analysis, do not meet NESC minimum strength requirements. The NESC has been
adopted by the Washington Administrative Code (WAC). Failing to replace these structures will
place Avista in violation of the WAC. When a failure does occur Avista will be in a situation of not
fixing an asset that was in violation of the WAC. Situation would be similar to a utility being shown
to be deficient in maintenance or vegetation management resulting in a wildfire. If Avista does not
implement this business case, the company is at risk of violating NERC Reliability Standard
Requirements and could be subject to penalties of up to$1 M per day for the duration of any such
violation. State law(WAC) violations are expected to have severe consequences as well.
Alternative 2:
Reinforce($2,500 per pole when applicable—almost never): Only wood poles have an option for
being reinforced rather than being replaced. This is identified in the Wood Pole Inspection (WPI)
notes, and would only be an option where the pole is not structurally overloaded but is recently
identified as being available for reinforcement per WPI. This would be a rare situation where the
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 234 of 535

DocuSign Envelope ID: D96B1413-B150-4E36-BB6B-C1DF5EED8DC0
Transmission Construction - Compliance
structural analysis picks up info from a recent WPI not directly attributable to the structural
overloading issue. Further evaluation by the Engineer would determine most cost effective
response. The cost for reinforcing a pole is approximately $2,500, and is the solution of choice
when there are no other extenuating circumstances.
Alternative 3:
Replace Identified Assets ($50,000 or more per structure): The cost of replacing a pole leads to
replacing the entire structure. Similar to most installation projects the unit cost of replacing a
pole/structure can vary based on location,access,and other extenuating circumstances. $50,000
is generally a middle-of-the-road estimate for replacing a structure.
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
As-Built confirmation of mitigation measures in addition to project schedule tracking will clear the
initial thirty-four (34) structures that need to be replaced on seven (7) transmission lines with
additional remediation expected as new Joint Use requests are received going forward. It is
expected that 7-10 structures will be addressed per year once the initial group of structures are
replaced.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Outage requests on the Avista Transmission System are typically restricted to the lower load
months of March-May and September-November. The months of December-February and June-
August are Avista's Winter and Summer load peaking months respectively. During these months
planned outages are restricted due to system capacity and flexibility constraints.
Some smaller projects can take place throughout the year. Most projects take place in the Spring
or Fall months and Transfer to Plant in the June or November/December time frame.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of
the business case, and how such oversight will occur.
The Engineering Roundtable functions as the Vetting Platform, Steering Committee,and Advisory
Group.
Electrical Engineering Expected Spend Committee reviews on a monthly basis ongoing spend for
projects approved by the ERT. Committee members include Managers, Project Managers,
analysts, and the Electrical Engineering Director.
During the design phase these functions are processed through the Engineering Roundtable.
During large project Contracted construction, Change Orders are processed through Supply
Chain. On smaller in-house construction projects, changes are agreed upon at the Project
Engineer/Project Manager, and are documented in the As-Built process. Any needed funding
increases would be requested through the Capital Planning Group (CPG).
Business Case Justification Narrative Template Version: February 2023 Page 8 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 235 of 535

DocuSign Envelope ID: D96B1413-B150-4E36-BB6B-C1DF5EED8DC0
Transmission Construction - Compliance
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Transmission Construction — Compliance
Business Case Justification Narrative and agree with the approach it presents. Significant changes
to this will be coordinated with and approved by the undersigned or their designated representatives.
DocuSigned by:
Signature: " swUgAil Date: May-02-2024 1 3:07 PM PDT
Print Name: 21 oc3544%eigart
Title: Manager, Transmission Line Design
Role: Business Case Owner
DocuSigned by:
Signature: Ut,V�r— habA,,A Date: May-03-2024 1 1:53 PM PDT
Print Name: o5c41V&Walensky
Title: Director of Electrical Engineering
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 9 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 236 of 535

DocuSign Envelope ID: CEOA277F-5D1B-4AAO-A23C-C6C8C205C5B8
Transmission Critical Crossing Reinforcments
EXECUTIVE SUMMARY
The Transmission Critical Crossing Reinforcements Business Case identifies high failure consequence
asset/structure locations; that, if subject to failure, would create life loss or injury conditions. This would lead
to diminished brand image and likely a loss of trust with Avista's service territory community. Additional
concern would be potential customer outages.
The triggering event for this Business Case is the "near miss" shown in the following photos:
The first photo shows a Benewah-Boulder 230kV h-frame structure located on the south side of Interstate I-
90 crossing near Liberty Lake, WA. The second photo shows what took place. A single polymer insulator
holding the 1-90 crossing conductor broke. The only thing that prevented the conductor from falling in 70 mph
traffic was the jumper splice (shown in the second photo). Jumper splices are not designed to hold full wire
tension; and, under higher tension conditions, would have likely failed with the insulator. Avista doesn't have
a way to inspect insulators for remaining life similar to wood poles. What Avista does have is an updated
reinforced design that uses higher class steel structures and redundant insulator hardware (shown below).
Business Case Justification Narrative Template Version: February 2023 Page 1 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 237 of 535

DocuSign Envelope ID: CEOA277F-5D1B-4AAO-A23C-C6C8C205C5B8
Transmission Critical Crossing Reinforcments
f
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t
Avista's 230kV/115kV railroad line crossings have historically been reinforced through additional guying at
time of construction, and would be considered as part of a replaced/rebuilt structure. This reinforcement
originally was required by the railroads to protect their interests. The idea behind this concept should guide
Avista's approach to other critical crossings. What this Business Case does is provide a heightened level of
reinforcement(based on present-day construction matrerials)for freeways and highways.
The work within this Business Case is recognized as High Risk Asset Condition.
Review of Interstate and US Route Highways within Avista territory shows (56) 230kV/115kV line crossings.
Of these most were constructed between the 1960's and 1980's, with some having been built in the 1940's
and 1950's, encroaching on their end-of-life (typical wood structure estimated to have a 60-70 year life). It is
expected that a review of State Route Highways will result in similar or greater risk results.
The implementation of this Business Case will be considered successful if these projects are all completed
within the same year as planned, or according to the dates identified in the Engineering Roundtable Project
List.
The recommended solution is to replace the existing wood pole freeway and highway crossings with an
updated reinforced steel pole design. There are no expected business impacts to continuing this program in
place. If Avista does not fully implement this business case, it runs an increased risk of high consequence
failure events. This Program will have a Service Code of Electric Direct and a Rate Jurisdiction of Allocated
North.
An annual spend of$2,000,000 is needed to complete the mitigations in an expedient manner. Prioritization
will be based on age and location. Case-by-case complexities will determine cost to mitigate each crossing.
By not funding this Business Case at the$2,000,000 level projects are delayed, creating a bow wave of time
sensitive projects moving into outer years. Because of the limited outage windows available for construction
(six months out of the year) delaying a project typically means moving six months or over a year. Outage
windows are further complicated by completing interests from other departments and Business Cases. The
funding level provides flexibility in construction to offset this situation.
Business Case Justification Narrative Template Version: February 2023 Page 2 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 238 of 535

DocuSign Envelope ID: CEOA277F-5D1B-4AAO-A23C-C6C8C205C5B8
Transmission Critical Crossing Reinforcments
The customer benefits from this Business Case through increased public safety and reliability.
VERSION HISTORY
Version Author Description Date
1.0 Ken Sweigart Initial draft of original business case 311212024
BCRT Team Steve
BCRT Member Has been reviewed by BCRT and meets necessary requirements Carrozzo
51112024
Business Case Justification Narrative Template Version: February 2023 Page 3 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 239 of 535

DocuSign Envelope ID: CEOA277F-5D1B-4AAO-A23C-C6C8C205C5B8
Transmission Critical Crossing Reinforcments
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT($)
2024 $2,000,000 $2,000,000
2025 $2,000,000 $2,000,000
2026 $2,000,000 $2,000,000
2027 $2,000,000 $2,000,000
2028 $2,000,000 $2,000,000
2029 $2,000,000 $2,000,000
Project Life Span Continuous Program Until Completion approx 10 yrs
Requesting Organization/Department TLD Engineering
Business Case Owner Sponsor Ken Sweigart/Vern Malensky
Sponsor Organization/Department Energy Delivery/Electrical Engineering
Phase Execution
Category Program
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
During routinely scheduled inspections, issues are discovered regarding the condition of assets,
including items such as rotten poles, broken/split/rotten crossarms, broken conductor or ground/shield
wire, insulators, and air switches that no longer operate safely or reliably. These types of inspections
cannot capture all the potential asset failures. Reinforcement by way of structure, insulator, hardware
and conductor replacements of high consequence crossings is the solution.
Avista's 230kV/115kV railroad line crossings have historically been reinforced through additional
guying at time of construction, and would be considered as part of a replaced/rebuilt structure. This
reinforcement originally was required by the railroads to protect their interests. The idea behind this
concept should guide Avista's approach to other critical crossings. What this Business Case does is
provide a heightened level of reinforcement (based on present-day construction matrerials) for
freeways and highways.
Review of Interstate and US Route Highways within Avista territory shows (56) 230kV/115kV line
crossings. Of these most were constructed between the 1960's and 1980's, with some having been
built in the 1940's and 1950's, encroaching on their end-of-life (typical wood structure estimated to
have a 60-70 year life). It is expected that a review of State Route Highways will result in similar or
greater risk results.
The recommended solution is to replace the existing wood pole freeway and highway crossing with an
Business Case Justification Narrative Template Version: February 2023 Page 4 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 240 of 535

DocuSign Envelope ID: CEOA277F-5D1B-4AAO-A23C-C6C8C205C5B8
Transmission Critical Crossing Reinforcments
updated reinforced steel pole design, similar to that used throughout the utility industry. There are no
expected business impacts to continuing this program in place. If Avista does not fully implement this
business case, it runs an increased risk of high consequence failure events.
The customer benefits from this Business Case through increased public safety and system reliability.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 241 of 535

DocuSign Envelope ID: CEOA277F-5D1B-4AAO-A23C-C6C8C205C5B8
Transmission Critical Crossing Reinforcments
1.1 What is the current or potential problem that is being addressed?
Avoidance of failure conditions; that, if left unaddressed will result in an increased consequence
risk to public safety and system reliability.
Review of Interstate and US Route Highways within Avista territory shows (56)230kV/115kV line
crossings. Of these most were constructed between the 1960's and 1980's, with some having
been built in the 1940's and 1950's, encroaching on their end-of-life (typical wood structure
estimated to have a 60-70 year life). It is expected that a review of State Route Highways will
result in similar or greater risk results.
1.2 Discuss the major drivers of the business case.
Asset Condition: Projects linked to wood pole critical freeway/highway crossings make up the
projects under this Business Case.
The customer benefits from this Business Case through increased public safety and system
reliability.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The previous failure event on the Benewah-Boulder 230kV Transmission Line shows the
vulnerability of our critical crossing assets. Pre-emptively addressing these identified assets will
reduce a high consequence risk. The risk profile is similar to that of Wildfire (low probability with
a very high consequence resulting in a high risk profile).
Review of Interstate and US Route Highways within Avista territory shows (56) 230kV/115kV line
crossings. Of these most were constructed between the 1960's and 1980's, with some having
been built in the 1940's and 1950's, encroaching on their end-of-life (typical wood structure
estimated to have a 60-70 year life). It is expected that a review of State Route Highways will
result in similar or greater risk results.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
This program focuses on our Customers by making sure that our word and system are reliable,
reducing outages and the risk to publice safety.
This program specifically supports the "Safety. Affordability. Responsibly" portion of the Avista
Mission Statement.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 242 of 535

DocuSign Envelope ID: CEOA277F-5D1B-4AAO-A23C-C6C8C205C5B8
Transmission Critical Crossing Reinforcments
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
Critical Crossings Age and Material Summary Spreadsheet, summarized as:
• Between Interstate and US Route Roadways, there are (80) 230/115kV crossings
o (47) Wood and (33) Steel
o Majority of Wood Poles between 40-65 years old
o Some younger Wood Poles(25-30 years old) may be able to be reinforced rather
than replaced.
• Results for State Routes expected to yield higher number and percentage of wood poles
This Business Case allows immediate attention to those assets based on age and location.
Failure to fully fund this Business Case will result in a bow wave of projects that are of the most
time sensitive nature.
Outage requests on the Avista Transmission System are typically restricted to the lower load
months of March-May and September-November. The months of December-February and June-
August are Avista's Winter and Summer load peaking months respectively. During these months
planned outages are restricted due to system capacity and flexibility constraints.
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Proposed solution is to replace those assets deemed at risk of failing in the near term and at
locations of highest risk consequence. Replacement greatly reduces risk of future failure.
Specifically the proposed solution is to fully replace wood structure crossings. $75k-$100k is
generally a middle-of-the-road deadend estimate for replacing a structure, but complexities
encountered around freeway/highway locations could easily increase the unit cost. It is expected
5-10 locations would be addressed per year.
More specifically, the replaced structures will either be direct embed or caisson foundation steel
poles with redundant (double) toughened glass insulators. This design configuration is common
in the utility undustry and will bring Avista's level of commitment to roadway crossings on a level
of that with railroad crossings.
Steel structures are estimated to have a life span over 100-years. The existing wood poles are
estimated to have life spans in the 60-70 year range. Some wood pole lines (HAT-M23) have
shown wood pole life spans to be even lower.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 243 of 535

DocuSign Envelope ID: CEOA277F-5D1B-4AAO-A23C-C6C8C205C5B8
Transmission Critical Crossing Reinforcments
f_
1 .
Ae'
Business Case Justification Narrative Template Version: February 2023 Page 8 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 244 of 535

DocuSign Envelope ID: CEOA277F-5D1B-4AAO-A23C-C6C8C205C5B8
Transmission Critical Crossing Reinforcments
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
The benefits of this Business Case are seen in something not happening. Pro-actively addressing
failures results in avoiding public safety risks including physical, electrical, and fire.
This program is in the Execution Stage with spend directed at structure and structure component
change-outs resulting in asset failure avoidance.
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $5,000 $5,000 $5,000 $5,000 $5,000
0&M $ $ $ $ $
Direct offsets associated with this project are the incremental costs associated with performing
work under emergency conditions versus planned conditions. Emergency conditions would
likey result in overtime wages and increased contractual expenditures. A lesser probability
would be for an unplanned outage to affect other planned outages, or possibly cause load to
be dropped. Unplanned outages negatively affect the overall Transmission System.
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
There are no indirect offsets associated with projects between 2025-2029. The nature of the
project (replacing poles, crossarms, or insulators only before end of life) does not change
maintenance schedules. Indirect Risk Costs include outage claims as well as loss of life and
property lawsuits.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
s Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 9 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 245 of 535

DocuSign Envelope ID: CEOA277F-5D1B-4AAO-A23C-C6C8C205C5B8
Transmission Critical Crossing Reinforcments
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternatives under this Business Cases primarily resolve in a basic choice of either replacing or
not replacing the identified asset. The amount of work completed each year is tailored to the
available budget. When immediate replacements are required as a result of in-year inspection
additional monies may be requested. By not funding this Business Case at the $2,000,000
projects are delayed, creating a bow wave of time sensitive projects moving into outer years.
Alternative 1:
Do Nothing: See Sections 1.5,2.1,and 2.2 for commentary. Replace only when asset fails. Direct
offset cost is the difference between planned replacement and unplanned replacement. Avoided
consequence cost would be much higher and should be considered in the same way we consider
avoidance of wildfires.
Alternative 2:
Reinforce or replace hardware/components: Wood poles have an option for being reinforced
rather than being replaced. If applicable, this partial solution option would only be employed as
a temporary fix as part of a future full replacement in the event of funds or outage restrictions.
The Engineer shall determine most cost effective response. A "best case" temporary fix would
be to spend $5,000 to reinforce poles in anticipation of rebuilding structure within 6 months to 1
year(see Post Falls-Ramsey 1-90 crossing).
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
As-Built confirmation of mitigation measures. We expect to complete 5-10 locations per year,
resulting in a reduction in failure risk..
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Outage requests on the Avista Transmission System are typically restricted to the lower load months
of March-May and September-November. The months of December-February and June-August are
Avista's Winter and Summer load peaking months respectively. During these months planned
outages are restricted due to system capacity and flexibility constraints.
Some smaller projects can take place throughout the year. Most projects take place in the Spring or
Fall months and Transfer to Plant in the June or November/December time frame.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
The Engineering Roundtable functions as the Vetting Platform, Steering Committee, and Advisory
Group.
Business Case Justification Narrative Template Version: February 2023 Page 10 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 246 of 535

DocuSign Envelope ID: CEOA277F-5D1B-4AAO-A23C-C6C8C205C5B8
Transmission Critical Crossing Reinforcments
Electrical Engineering Expected Spend Committee reviews on a monthly basis ongoing spend for
projects approved by the ERT. Committee members include Managers, Project Managers, analysts,
and the Electrical Engineering Director.
During the design phase these functions are processed through the Engineering Roundtable. During
large project Contracted construction, Change Orders are processed through Supply Chain. On
smaller in-house construction projects, changes are agreed upon at the Project Eneginer/Project
Manager, and are documented in the As-Built process.
Business Case Justification Narrative Template Version: February 2023 Page 11 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 247 of 535

DocuSign Envelope ID: CEOA277F-5D1B-4AAO-A23C-C6C8C205C5B8
Transmission Critical Crossing Reinforcments
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Transmission Critical Crossing
Reinforcements Business Case Justification Narrative and agree with the approach it presents.
Significant changes to this will be coordinated with and approved by the undersigned or their
designated representatives.
DocuSigned by:
Signature: Date: May-02-2024 1 3:08 PM PDT
Print Name: 21OC35KM9 eigart
Title: Manager, Transmission Line Design
Role: Business Case Owner
DocuSigned by:
Signature: ULM k,�.tan.S�U Date: May-03-2024 1 1:55 PM PDT
Print Name: 05c4FF 4Malensky
Title: Director of Electrical Engineering
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 12 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 248 of 535

DocuSign Envelope ID:7lA7FE08-C4C8-4D85-867A-E7838EE9820F
Transmission Major Rebuild - Asset Condition
EXECUTIVE SUMMARY
The Transmission Ma►or Rebuild—Asset Condition Business Case covers major rebuilds of transmission
lines due to overall asset condition. Although line conductor will sometimes be included in the rebuild scope,
the primary target of this business case is the replacement of aging wood infrastructure. Factors considered
in prioritizing work include condition, sustained outages,accessibility, system reliability, wildfire risk, customer
density, and reputation impact. Potential for joint facility improvements (i.e. communications build-out) are
also considered in prioritizing this work. The projects within this program are developed through Asset
Management's general analysis ofAvista's Transmission System facilities that provides a risk-based ranking
of over 100 Transmission Lines. Projects are chosen to maximize stakeholder value.
Investments made under this program rebuild existing transmission lines based on overall asset condition.
"Condition"is measured by useful life or the number of condition-related outages. Factors such as operational
issues, ease of access during outages, and need to add automation or communications equipment may be
included in the type of spending in this category. Replacing old and worn-out poles and cross-arms and other
associated transmission equipment help guard against increasing risk for more failures and outages.
Transmission outages can have significant consequences, as they tend to impact a large number of
customers and have the potential to start fires in dry areas. In addition to reliability issues, failure to properly
invest builds a bow-wave of needed investments in the future, thus this program is crucial to maintaining
operations. When facilities reach an age when it is close to or at the end of its useful life, the Company
preventively replaces it to maintain reliability and acceptable levels of service.
The implementation of this business case will be considered successful if these projects are completed as
planned on time and on budget.
The recommended solution is to rebuild transmission lines as prioritized by the Engineering Roundtable group
to ensure that Avista sufficiently addresses its aging Transmission Line infrastructure. There are no expected
business impacts to continuing this program in place. This Program will have a Service Code of Electric
Direct and a Rate Jurisdiction of Allocated North. A spend of$10,000,000 is needed to complete the projects
as follows:
• ER 2631, BI CT207($25,000,000): Pine Street-Rathdrum 115kV Transmission Line Rebuild Phases
2 through 3 (years 2023-2025)
• ER 2596, BI LT900 ($8,300,000): Lolo-Oxbow 230kV Transmission Line Rebuild Phase 3 (year
2024-2025)
• ER 2116, BI KT901 ($10,000,000): Noxon-Pine Creek 230kV Transmission Line Rebuild(year 2026)
• ER 2594, BI CT207($30,000,000): Benewah-Pine Creek 230kV Transmission Line Rebuild Phases
1 through 3 (year 2027-2029)
Avista, KEC, and IP&L customers benefit from this Business Case through improved service reliability.
Avista's brand image improves as showing commitment to all customers.
VERSION HISTORY
Version Author Description Date
1.0 Ken Sweigart Initial draft of original business case 3/13/2024
BCRT Team
BCRT Member—Joe Has been reviewed by BCRT and meets necessary requirements 512124
Wright
Business Case Justification Narrative Template Version: February 2023 Page 1 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 249 of 535

DocuSign Envelope ID:71A7FE08-C4C8-4D85-867A-E7838EE9820F
Transmission Major Rebuild - Asset Condition
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT($)
2024 $11,300,000 $8,000,000
2025 $13,000,000 $16,300,000
2026 $10,000,000 $10,000,000
2027 $10,000,000 $10,000,000
2028 $10,000,000 $10,000,000
2029 $10,000,000 $10,000,000
Project Life Span Continuous Program
Requesting Organization/Department TLD Engineering
Business Case Owner Sponsor Ken Sweigart/Vern Malensky
Sponsor Organization/Department Energy Delivery/Electrical Engineering
Phase Execution
Category Program
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
Business Case Justification Narrative Template Version: February 2023 Page 2 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 250 of 535

DocuSign Envelope ID:71A7FE08-C4C8-4D85-867A-E7838EE9820F
Transmission Major Rebuild - Asset Condition
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
The Transmission Major Rebuild—Asset Condition Business Case covers investments made to rebuild
existing transmission lines based on overall asset condition. "Condition"is measured by useful life or
the number of condition-related outages. Factors such as operational issues, ease of access during
outages, and need to add automation or communications equipment may be included in the type of
spending in this category. Replacing old and worn-out poles and cross-arms and other associated
transmission equipment, help guard against increasing risk for more failures and outages.
Transmission outages can have significant consequences, as they tend to impact a large number of
customers and have the potential to start fires in dry areas. In addition to reliability issues, failure to
properly invest builds a bow-wave of needed investments in the future, thus this program is crucial to
maintaining operations. When facilities reach an age when it is close to or at the end of its useful life,
the Company preventively replaces it to maintain reliability and acceptable levels of service.
The below graph shows a snapshot of the system asset age as of 2016. We have a number of assets
beyond their remaining service life. Some poles can make it past their service life and others failure
much earlier, but the average is reflected in the graph. Trends show that"old growth"poles last longer
than "new growth"poles, which may explain why we are seeing concerning failure trends in some lines
50-years old and less.
Transmission System Replacement Cost vs Remaining Service Life
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Remaining Service Life(years)
The following excerpt is taken from the 2016 AM Transmission System AM Plan Executive Summary:
Consistent with last year's assessment,the primary message of this asset management plan is
that the company must commit itself to sustainably replace the bulk of the aging transmission
system over the next three decades.This is essential to achieve the company's strategic
objectives of maintaining reliability levels while minimizing total lifecycle costs, requiring over
$624 million in capital replacement investment. As this represents a significant increase in capital
investment as well as internal and external workloads from recent years, success demands strong
Business Case Justification Narrative Template Version: February 2023 Page 3 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 251 of 535

DocuSign Envelope ID:71A7FE08-C4C8-4D85-867A-E7838EE9820F
Transmission Major Rebuild - Asset Condition
company support and management. In order to be most effective and beneficial to customers
and the company, it also requires fact-based prioritization and targeting of available funds to the
riskiest elements of the system. Replacement budget recommendations remain relatively
unchanged at$12 million for 115kV and $9 million for 230kV. Planned budgets for 2016 and 2017
are relatively close to this recommendation.Additional mandated, growth and reimbursable
capital projects, as well as O&M work puts the total planned budget for Transmission Engineering
at approximately$25 million for 2016 and is expected to remain at this level or increase for many
years.
1.1 What is the current or potential problem that is being addressed?
Transmission outages can have significant consequences, as they tend to impact a large number
of customers and have the potential to start fires in dry areas. In addition to reliability issues,
failure to properly invest builds a bow-wave of needed investments in the future, thus this program
is crucial to maintaining operations.
The Pine St.-Rathdrum(PIP-RAT) 115kV line is nearing end of life and showing signs of increased
plant failures. While the remaining wood poles average approximately 20-years of remaining life,
the most recent wood pole inspections noted(120)major components(poles/crossarms)needing
closer inspection, reinforcement, or replacement;an indication of facilities nearing end-of-life.
Additionally, sustained outages experienced by PIP-RAT have increased over the past 5-years
to average nearly two per year(see Section 2.2). This increase is another signal that the line's
life span is trending shorter than the average.
The Lolo-Oxbow (LOL-OXB) 230kV Transmission Line was ranked #1 under the old Asset
Management prioritizing system (see table in Section 1.3) and underwent two phases of
reconstruction. The third phase of this project is funded to start in 2024, with completion in early
2025. Beyond 2025 the Lolo-Oxbow project is more of a placeholder and will be evaluated against
other transmission if not chosen approved for a DOE Grant.
The Noxon-Pine Creek (NOX-PIN) 230kV line is nearing end of life and shows a significant
increase in Wood Pole Management test failures. This line is scheduled for a 2024 Minor Rebuild
to take care of the poorest condition structures, with the remaining structures to be replaced in
2026 under this Business Case. The testing failure increases are reflective of what took place on
the recently rebuilt Hatwai-Moscow 230kV Line in 2022 under this Business Case. The NOX-PIN
line was ranked#2 under the old Asset Management prioritizing system(see table in Section 1.3).
The Benewah-Pine Creek (BEN-PIN) 230kV Transmission Line was ranked #3 under the old
Asset Management prioritizing system(see table in Section 1.3). At this time the BEN-PIN project
is more of a placeholder and will be evaluated against other transmission lines for the 2027-2029
fiscal years.
1.2 Discuss the major drivers of the business case.
Asset Condition: Customer benefits by having a more reliable Transmission System capable of
supporting service needs. Please see metric trends shown in table below:
Business Case Justification Narrative Template Version: February 2023 Page 4 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 252 of 535

DocuSign Envelope ID:71A7FE08-C4C8-4D85-867A-E7838EE9820F
Transmission Major Rebuild - Asset Condition
Customer-Hours
unplanned,extended
outage due to
transmission issues 113,142 255,426 64,453 82,908 238,861 200,977 262,949
#of customers of Tx
related unplanned
outages greater than 3
hrs 10,182 16,478 6,644 5,409 17,135 17,609 124,927
Tx emergency repair
costs $1,321,019 $1,442,969 $1,029,597 $1,409,972 $1,630,943 $3,040,313 L,180,921
Once completed the Pine Street-Rathdrum 115kV line is expected to no longer show up on the
top five most impacted lines (see tables in Section 2.2).
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
Transmission outages can have significant consequences, as they tend to impact a large number
of customers and have the potential to start fires in dry areas. In addition to reliability issues,
failure to properly invest builds a bow-wave of needed investments in the future, thus this program
is crucial to maintaining operations.
The Pine Street-Rathdrum (PIP-RAT) 115kV Transmission Line has the highest Risk Score of all
Avista transmission lines based on the 2022 Asset Management model version (see below). This
version was updated to include wildfire, customer density, and Avista brand reputation impacts.
Of special note w/r the PIP-RAT is the number of"other"utility customers. Recently Kootenai
Electric Cooperative (KEC) has become very vocal w/r outages on this line affecting their
customers to the extent of making commission complaints and publicly blaming Avista in
notifications to their customers.
Avista
Circuit ID Voltage Owned Risk Condition
Length Score score
(mi)
Pine St:Rathdrum 115 115 33.24 9.79 3.15
Noxon-Pine Creek 230 230 43.51 9.291 3.50
Add -Devil's Ga 115 115 43.66 9.01 3.05
Burke-Pine Creek#3 115 115 24.11 8.59 3.15
Sunset-Westside 115 115 10.04 8.39 2.45
Clearwater-Lolo#2 115 115 9.29 8.18 2.45
Ninth&Cent-Opportunity 115 115 7.13 7.80 2.75
Bell-Northeast Waikiki Tap 115 115 2.83 7.611 3.20
Beacon-Northeast 115 115 5.25 7.56 3.20
Beacon-Fr&Cedar Bell Tap lil� 115 0.61 7.23 3.80
Grangeville-Nez Perce#2 115 115 37.17 7.14 2.90
Sunset-Westside South Fairchild Tap 115 115 11.99 7.09 2.35
College&Walnut-Westside 115 115 8.78 7.02 2.20
Moscow 230-5outh Pullman 115 115 12.07 6.93 2.70
Shawnee-Sunset 115 1151 61.511 6.92 2.80
Hatwai-Lolo 230 2301 8.271 6.91 2.60
Business Case Justification Narrative Template Version: February 2023 Page 5 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 253 of 535

DocuSign Envelope ID:71A7FE08-C4C8-4D85-867A-E7838EE9820F
Transmission Major Rebuild - Asset Condition
The Lolo-Oxbow (LOL-OXB) 230kV Transmission Line has the highest Risk Score of all Avista
transmission lines based on the 2016 model version (see below). This model has since been
updated to include wildfire, customer density, and Avista brand reputation impacts (see above).
Although no longer prioritized No.1, it still shows up on the high end of the over 100 Transmission
Lines within Avista's system.
Transmission Line Name Voltage(kV) Length(miles) Replacement Value Probability Index Consequence Index Risk Index
Lolo-Oxbow 230 63.41 $45,655 200 85.4 100.0 100.0
Noxon-Pine Creek 230 43.51 $31,327,200 80.5 87.8 82.8
Benewah-Pine Creek 230 42,77 $30,794,400 68.3 87.8 70.3
Walla Walla- napum 230 77.78 $56,001,600 68.4 83.7 67.1
Benewah-Boulder 230 26.15 $18,828,000 67.1 72.9 57.3
Hot Springs-Noxon#2 230 70.05 $50,436 000 66.0 68.8 53.2
Dry Creek-Talbot 230 28.27 $20,354,400 51.4 78.3 47.1
Latah-Moscow 115 51.41 $21592 200 96.0 41.7 47.0
DevilsGap-Stratford US 96.19 $36,199,800 100.0 39.0 45.6
Post Street-3rd&Hatch 115 1-76 $3,696,000 70 0 43
Benewah-Moscow 230 44.28 $31,881,600 61.1 5910.3 42.5
Table 13: Top 20 Most at Risk Circuits according to the Reliability Risk Index
The important take away is the need to maintain a $10,000,000 annual spend to prevent a bow
wave of aging infrastructure. Much of Avista's infrastructure is beyond its life expectancy.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
This program focuses on our Customers by making sure that our word and system are reliable,
reducing outages and the risk of wildfire.
• Avista, KEC, and IP&L customers benefit from this Business Case through improved
service reliability. Avista's brand image improves as showing commitment to all
customers.
This program specifically supports the "Safety. Affordability. Responsibly"portion of the Avista
Mission Statement.
• Replacing old and worn-out poles and cross-arms and other associated transmission
equipment help guard against increasing risk for more failures and outages.
Transmission outages can have significant consequences, as they tend to impact a
large number of customers and have the potential to start fires in dry areas. In addition
to reliability issues, failure to properly invest builds a bow-wave of needed investments
in the future, thus this program is crucial to maintaining operations.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 254 of 535

DocuSign Envelope ID:71A7FE08-C4C8-4D85-867A-E7838EE9820F
Transmission Major Rebuild - Asset Condition
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
The following documents provide the basis for needed planned Condition replacements,
prioritization lists, and project specific information:
2016 Lolo-Oxbow 230kV Model Asset Management Plan Rev a.docx
• Original Asset Management Transmission Line plan document showing need for
prioritized and levelized spend
LOL-OXB—model results.pptx
• Asset(Transmission Line) specific analysis recommending replacement approach.
Transmission Lines List(Scored).xlsx
• Updated prioritization of Transmission Line assests inclusive of wildfire and customer
affects
Transmission Lines Risk Index.pdf
• Original prioritization of Transmission Line assests
Engineering Project Request Template PIP-RAT Rebuild.docx
• Project documentation used in presentation to Engineering Round Table advisory group
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
This is the continuation of an ongoing Program and requires the replacement of aging infrastructure to
support service levels. Please see Alternatives Prioritization within Section 1.3 tables for details.
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
A Maior Rebuild of the Pine Street-Rathdrum (PIP-RAT) line is the recommended alternative for
construction years 2023-2025. The customers served off this line (Avista, KEC, and IPL) are
currently experiencing substandard electric service due to the condition of our infrastructure.
Rebuilding this line will demonstrate our commitment to holding our customers'interests at the
forefront of our decisions. A major rebuild of this line will increase our service reliability and align
with Avista's vision and core values.
Additionally, the risk of wildfire ignition exists every time the line trips to ground. Rebuilding this
line entirely will reduce this risk significantly, thus increasing the safety and resiliency of our
infrastructure.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 255 of 535

DocuSign Envelope ID:71A7FE08-C4C8-4D85-867A-E7838EE9820F
Transmission Major Rebuild - Asset Condition
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
The benefits of this Business Case are seen in something not happening. Pro-actively addressing
near-term failures results in avoiding public safety risks including physical, electrical, and fire.
This program is in the Execution Stage with spend directed primarily at structure and structure
component change-outs resulting in facility failure avoidance.
Below are Customer Impacts Results for 2021 and 2022(PIP-RAT).
Top 5 Lines by Customer Impacts
80000
70000
60000 — —
50000 —
40000
30000 arm
20000
10000
0
Add-!_Kettle Falls GrangevBle-Nez Perce#1 Moscow-A114(LAT-M23) Moscow-Orofirw Pine Street-Rathdruin
Reclose ■Lockout
Top 5 Lines by Customer Impacts
90000
Boom
70M
60M
SOOM
400M
30000
20000
10000
0
Moscow-A114(LAT- Lolo-Nez Perce Moscow-Orofino Pine Street-Rathdrum A147-Sunset(SHN-SUN)
M23)
Reclose ■ Lockout
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 8 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 256 of 535

DocuSign Envelope ID:71A7FE08-C4C8-4D85-867A-E7838EE9820F
Transmission Major Rebuild - Asset Condition
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $10,000 $10,000 $10,000 $10,000 $10,000
0&M $10,000 $10,000 $10,000 $10,000 $10,000
Direct offsets associated with the projects within this Business Case are the incremental costs
associated with performing work under emergency conditions versus planned conditions.
Emergency conditions would likely result in overtime wages and increased contractual
expenditures (Capital). A lesser probability would be for an unplanned outage to affect other
planned outages, or possibly cause load to be dropped. Unplanned outages negatively affect the
overall Transmission System (0&M).
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
There are no indirect offsets associated with these projects. The nature of the projects(replacing
poles, crossarms, or insulators only before end of life) does not change maintenance schedules,
and therefore no offsets were/are realized.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternatives under this Business Cases primarily resolve in a basic choice of either replacing or
not replacing the identified asset. The amount of work completed each year is tailored to the
available budget. By not funding this Business Case at the $10,000,000 projects are delayed,
creating a bow wave of time sensitive projects moving into outer years. Alternatives below refer
to PIP-RAT.
Alternative 1:
Maintain As-Is (Option #1: $0) is not an option because the increasing outages (cost to
customers) and a significant risk of wildfire ignition (major cost associated with litigation), and a
threat to Avista's brand image (3,d party customer outages leading to Utility Commission
complaints).
s Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 9 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 257 of 535

DocuSign Envelope ID:71A7FE08-C4C8-4D85-867A-E7838EE9820F
Transmission Major Rebuild - Asset Condition
Alternative 2:
A Minor Rebuild (Option #2: TBD) of this line is not a recommended alternative. The work
associated with a minor rebuild would be substantial and would only be a stopgap for maybe 20-
years. After 20-years, all remaining wood poles would be at their end of life and require
replacement. Mobilizing construction resources for significant rebuild work twice within 20-years
is very cost-ineffective.
Alternative 3:
A Major Rebuild (Option #3: $25,000,000) of this line is the recommended alternative. The
customers served off this line (Avista, KEC, and IPL) are currently experiencing substandard
electric service due to the condition of our infrastructure. Rebuilding this line will demonstrate our
commitment to holding our customers'interests at the forefront of our decisions. A major rebuild
of this line will increase our service reliability and align with Avista's vision and core values.
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
As-Built confirmation of mitigation measures.
The investment is considered successful when the targeted Transmission Line no longer shows up
on the Customer Impacts Tables shown in Section 2.2.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Outage requests on the Avista Transmission System are typically restricted to the lower load months
of March-May and September-November. The months of December-February and June-August are
Avista's Winter and Summer load peaking months respectively. During these months planned
outages are restricted due to system capacity and flexibility constraints.
The Pine Street-Rathdrum project will take place in the Spring or Fall months and Transfer to Plant
in the June or November/December time frame. The Lolo-Oxbow project will take place over Winter
months and likely Transfer to Plant in the March-April time frame.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
The Engineering Roundtable functions as the Vetting Platform, Steering Committee, and Advisory
Group. Committee members and Charter can be found under the System Planning SharePoint site
via the Avenue.
Electrical Engineering Expected Spend Committee reviews on a monthly basis ongoing spend for
projects approved by the ERT. Committee members include Managers, Project Managers, analysts,
and the Electrical Engineering Director.
During the design phase these functions are processed through the Engineering Roundtable. During
large project Contracted construction, Change Orders are processed through Supply Chain. On
Business Case Justification Narrative Template Version: February 2023 Page 10 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 258 of 535

DocuSign Envelope ID:71A7FE08-C4C8-4D85-867A-E7838EE9820F
Transmission Major Rebuild - Asset Condition
smaller in-house construction projects, changes are agreed upon at the Project Engineer/Project
Manager and are documented in the As-Built process.
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Transmission Major Rebuild—Asset Condition
Business Case Justification Narrative and agree with the approach it presents. Significant changes to
this will be coordinated with and approved by the undersigned or their designated representatives.
DocuSigned by:
Signature: CwugayF Date: May-02-2024 1 3:10 PM PDT
Print Name: 21OC35"PVISWeigart
Title: Manager, Transmission Line Design
Role: Business Case Owner
DocuSigned by:
Signature: U�,VIn hdti , Date: May-03-2024 1 1:59 PM PDT
Print Name: 16c4FWRfMalensky
Title: Director of Electrical Engineering
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 11 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 259 of 535

2022 Transmission NERC Low Priority Ratings Mitigation
EXECUTIVE SUMMARY
The Transmission NERC Low Priority Lines Mitigation Business Case covers the work to reconfigure insulator
attachments, and/or rebuild existing transmission line structures, or remove earth beneath transmission lines in order
to mitigate ratings/sag discrepancies found between "design"and "field"conditions as determined by LiDAR survey
data. This program was undertaken in response to the October 7, 2012 North American Electric Reliability Corporations
(NERC) "NERC Alert"- Recommendation to Industry, "Consideration of Actual Field Conditions in Determination of
Facility Ratings". This Capital Program covers mitigation work on Avista's"Low Priority"230kV and 115kV transmission
lines. Mitigation brings lines in compliance with the National Electric Safety Code(NESC)minimum clearances values.
These code minimums have also been adopted into the State of Washington's Administrative Code (WAC). This
program is expected to be completed in 2024.
The recommended solution is to correct the issues found in the LiDAR studies to stay in compliance with the NESC
code and WAC. There are no expected business impacts to continuing this program in place. If Avista does not fully
implement this business case, it runs the risk of being fined for not staying in compliance with the NESC code and
WAC rules. A spend of$3,500,000 is needed to complete the mitigations by 2024. This Program will have a Service
Code of Electric Direct and a Rate Jurisdiction of Allocated North.
The customer benefits from this Business Case through increased service reliability.
VERSION HISTORY
Version Author Description Date Notes
Draft Ken Sweigart Initial draft of original business case 4/28/2022
1.0
1.1
2.0
Business Case Justification Narrative Template Version:04.21.2022 Page 1 of 6
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 260 of 535

2022 Transmission NERC Low Priority Ratings Mitigation
GENERAL INFORMATION
Requested Spend Amount $3,500,000
Requested Spend Time Period 2 years
Requesting Organization/Department TLD Engineering
Business Case Owner Sponsor Josh DiLuciano/Heather Rosentrater
Sponsor Organization/Department Energy Delivery/Electrical Engineering
Phase Execution
Category Program
Driver Mandatory & Compliance
1. BUSINESS PROBLEM
The Transmission NERC Low Priority Lines Mitigation Business Case covers the work to reconfigure insulator
attachments, and/or rebuild existing transmission line structures, or remove earth beneath transmission lines in
order to mitigate ratings/sag discrepancies found between "design" and "field" conditions as determined by
LiDAR survey data. This program was undertaken in response to the October 7, 2012 North American Electric
Reliability Corporations (NERC) "NERC Alert" - Recommendation to Industry, "Consideration of Actual Field
Conditions in Determination of Facility Ratings". This Capital Program covers mitigation work on Avista's "Low
Priority"230kV and 115kV transmission lines. Mitigation brings lines in compliance with the National Electric
Safety Code (NESC) minimum clearances values. These code minimums have also been adopted into the
State of Washington's Administrative Code (WAC).
1.1 What is the current or potential problem that is being addressed? Clearance
violations.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant& Operations) and the benefits to the customer Mandatory
& Compliance: Customer benefits by having a Transmission System in compliance with Federal Code
and State Law.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred The North American Electric Reliability Corporations (NERC) "NERC
Alert"originally identified Low Priority Transmission Line assessments to complete by December 31, 2013.
Although a mitigation timeline did not include a penalty threat, we have been operating under a grace
period that requires us to report progress every six months. Completing the program by 2024 will show
us taking eleven years to complete the effort. Deferring completion is tempting greater scrutiny from NERC
and delays mitigation of a compliance violations recognized by Washington State Law.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above. As-Built confirmation of mitigation measures.
Business Case Justification Narrative Template Version:04.21.2022 Page 2 of 6
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 261 of 535

2022 Transmission NERC Low Priority Ratings Mitigation
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
CAN-0009_FAC-008 FAC-009.pdf
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
Recommendation to industry:Consideration of Actual Field Conditions in Determination of Facility Ratings
0 November 30,2010,NERC provided a,update m the October 7,2010 Recommendation M Industry entitled Gorak*mfuu,ofActual Field Conditions in Determination of Facility Ratings'Transmission owners andf Genemb,0—ofbulk
el:(Z system facilities should mine,the,current hecilly'aftws methooiblogy to,their transmission lines W vefy the memociatogy used is based on actual Field conditions and dea,mmhe if their mon,is methoolotogy willpoduce abomp-te ratings
when c�si�,,Wdfte�s��,�sgneWFeldcoWito,s Ifentibes hoe notp—ously vefied that the facility aesV,,installation.anal Field conditions are mHu,design tolerances when me Facilffies are loaded at their mtulis entities are
required by January 18.2011,to de—bads plans to complete such an assessment fall its transmission lines, am me highestp"only Imes assessed by December 31.2011.anedum,priority lines by D—ba,31.2012.autl the lowastm—dy by
Decembe,31.2013 At thia,conclusion of each y­each Transmission Owne,and Garemlo,crime,must report wits Regwriat Entity a summary of the assessments and identification of all transmission facilities where as-buift conditions am
different from design conditions.resulting mmcorrectrahngs.and their associatedmitgatku,tumelmes Remedial—is ekjowtedl within one year from identification ofthe issue or on a schedule approved by the Regional Entity iflonger than a year
Owners am also epecW ad coord—fe with their respective operafW and planning organizations to coordinate interim mitigation strategies
Owner Informatiorill
Entity Name Avesta Utilities
NCR#
Region WECC
Owner Type Transmission Owner
Miles 227.50
Circuits 6.00
Total Medium Priority
Miles 760.00
Circuits 54.00
Low Priority
Miles 127000
Circuits 67.00
Grand Totals
Miles 225T50
Circuits 12T00
1/16/2020 Update:Continue multi-phase rebuild projects with LiDAR NERC Alert components.
2. PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]
Option Capital Cost Start Complete
Mitigate Violations $3.5M 01-2023 12-2024
[Alternative#1] $M MM YYYY MM YYYY
(Alternative#21 $M MM YYYY MM YYYY
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost($)to benefit(value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
Business Case Justification Narrative Template Version:04.21.2022 Page 3 of 6
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 262 of 535

2022 Transmission NERC Low Priority Ratings Mitigation
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
This program is in the Execution Stage with spend directed primarily at structure change-outs resulting in
greater ground clearance.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward(ref. WUTC Docket No.U-190531 Policy
Statement),therefore it is critical that these impacts are thought through in order to support rate recovery.]
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Primary impacts are in the area of obtaining Transmission system outages and construction resources.
Although Transmission Line Design has the ability to Contract for construction services on the large
projects, internal construction resources typically perform the smaller jobs.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Raising structure heights is by far the go to alternative. In one instance the removal of earth was used.
Earth removal can trigger permitting, which otherwise would not be necessary.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
Smaller projects can take place throughout the year. Most of the large projects take place in the Fall
months and Transfer to Plant in the November time frame.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Aligns with Avista's Culture of Compliance.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Mitigation design solution performed within PLS-CADD, which is the industry leader in providing
Transmission Line Design computer based programs. Designs are reviewed at multiple stages to ensure
prudency and maximum Stakeholder value.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Many and varied throughout Avista.
2.8.2 Identify any related Business Cases
None
Business Case Justification Narrative Template Version:04.21.2022 Page 4 of 6
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 263 of 535

2022 Transmission NERC Low Priority Ratings Mitigation
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The Engineering Roundtable functions as the Vetting Platform, Steering Committee, and Advisory Group.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Electrical Engineering Expected Spend Committee reviews on a monthly basis ongoing spend for projects
approved by the ERT. Committee members include Managers, Project Managers, analysts, and the
Electrical Engineering Director.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
During the design phase these functions are processed through the Engineering Roundtable. During large
project Contracted construction, Change Orders are processed through Supply Chain. On smaller in-
house construction projects, changes are agreed upon at the Project Eneginer/Project Manager, and are
documented in the As-Built process.
Business Case Justification Narrative Template Version:04.21.2022 Page 5 of 6
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 264 of 535

2022 Transmission NERC Low Priority Ratings Mitigation
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Low Priority Rating Mitigation
Business Case Justification Narrative and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their designated
representatives.
Signature: APPROVED Date:
Print Name: By Ken Sweigart at 11:35 am, Sep 09, 2022
Title:
Role: Business Case Owner
Signature: EA V-�� Date: 9/9/2022
Print Name: Josh DiLuciano
Title: Vice President - Energy Delivery
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version:04.21.2022 Page 6 of 6
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 265 of 535

DocuSign Envelope ID: C659FOEO-7CE3-4641-9CAA-9DO806C4E6A1
Westside 230/115kV Station Rebuild
EXECUTIVE SUMMARY
This section is reserved to provide a brief description of the business case and high-level summary of the projects or
programs included. Please limit to no more than 2 paragraphs. Components that should be included:
1) NEEDs AssEssMENT-a synopsis of the problem,the current state and recommended solution
2) COST-the cost of the recommended solution
3) DOCUMENT SUMMARY-benefit to the customer
4) RISK-of not approving the business case
5)APPROVALS-who reviewed and approved the recommended solution
<< Both the Executive Summary and Version History should fit into one page >>
The existing Westside #1 230/115 kV transformer exceeds its applicable facility rating for the P1
event of the Westside #2 230/115 kV transformer. System performance analysis indicates an
inability of the system to meet the performance requirements in Table 1 of NERC TPL-001-4 in
scenarios representing 2017 Heavy Summer for P1 events. While Avista intends to avoid
proactively shedding customer load, an operating procedure to shed non-consequential load can
be used until 2021 to mitigate system deficiencies (non-consequential load shedding is
considered acceptable through the 84 month implementation of TPL-001-4). This project is
approved and prioritized by the Engineering Roundtable Committee.
Westside Transformer Replacement is the recommended solution. Replace the existing Westside
transformers with 250 MVA rated transformers and reconstruct both the 230 kV and 115 kV buses
at the station to double bus, double breaker. All associated system deficiencies will be mitigated.
Service: ED— Electric Direct
Jurisdiction: AN —Allocated North
Engineering Roundtable Request Number: ERT 2017-47
Cost of Solution: $26,200,000
VERSION HISTORY
Version Author Description Date Notes
1.0 Ken Sweigart Initial Version 4/14/2017 Initial Version
2.0 Karen Kusel/ Update to 2020 Template 6/2020
Glenn Madden
Business Case Justification Narrative Page 1 of 7
Exhihit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 266 of 535

DocuSign Envelope ID: C659FOEO-7CE3-4641-9CAA-9DO806C4E6A1
Westside 230/115kV Station Rebuild
GENERAL INFORMATION
Requested Spend Amount $26,200,000
Requested Spend Time Period 15 Years
Requesting Organization/Department Transmission/System Planning
Business Case Owner I Sponsor Glenn Madden Josh DiLuciano
Sponsor Organization/Department T&D
Phase Execution
Category Project
Driver Mandatory & Compliance
1 BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
The existing Westside #1 230/115 kV transformer exceeds its applicable facility rating for
the P1 event of the Westside #2 230/115 kV transformer. System performance analysis
indicates an inability of the system to meet the performance requirements in Table 1 of
NERC TPL-001-4 in scenarios representing 2017 Heavy Summer for P1 events. While
Avista intends to avoid proactively shedding customer load, an operating procedure to shed
non-consequential load can be used until 2021 to mitigate system deficiencies (non-
consequential load shedding is considered acceptable through the 84 month
implementation of TPL-001-4).
1.1 What is the current or potential problem that is being addressed?
System performance analysis indicates an inability of the system to meet the performance
requirements in Table 1 of NERC TPL-001-4 in scenarios representing 2017 Heavy
Summer for P1 events.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer Service
Quality& Reliability, Mandatory& Compliance, Performance & Capacity, Asset Condition, or
Failed Plant& Operations) and the benefits to the customer
Mandatory & Complaince -All associated system deficiencies will be mitigated with the completion
of this project.
1.3 Identify why this work is needed now and what risks there are if not approved or is
deferred
While Avista intends to avoid proactively shedding customer load, an operating procedure to shed
non-consequential load can be used until 2021 to mitigate system deficiencies (non-consequential
load shedding is considered acceptable through the 84 month implementation of TPL-001-4).
1.4 Identify any measures that can be used to determine whether the investment would
successfully deliver on the objectives and address the need listed above.
Future System Planning Assessments which show mitigation of all prior deficiencies.
Business Case Justification Narrative Page 2 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 267 of 535

DocuSign Envelope ID: C659FOEO-7CE3-4641-9CAA-9D0806C4E6A1
Westside 230/115kV Station Rebuild
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information;do not attach]
System Planning Assessments.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.
Not Applicable.
2 PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]
Westside Transformer Replacement is the recommended solution. Replace the existing
Westside transformers with 250 MVA rated transformers and reconstruct both the 230
kV and 115 kV buses at the station to double bus, double breaker. All associated system
deficiencies will be mitigated.
Project scope includes the following:
Phase 1: Replace the existing Westside#1 230/115 kV transformer and construct necessary
bus work and breaker positions. $11 million, energize 2018
Phase 2: Continue bus work and breaker replacement: $8 million, energize 2019
Phase 3: Replace the existing Westside #2 230/115 kV transformer and complete bus work
to single bus configuration: $6 million, energize 2020
Phase 4: Complete bus work to double bus, double breaker on both the 230 kV and 115 kV
buses: $7 million, energize 2022. (2022 Note: Project is scheduled to complete in 2024
because of delays for getting planned outages.)
Alternative 1 - Status Quo/Do Nothing: This alternative is not recommended because it does
not mitigate the expected capacity constraints and does not adhere to NERC transmission
planning standards.
Solution/Alternative 2 -Westside Transformer Replacement: Replace the existing Westside
transformers with 250 MVA rated transformers and reconstruct both the 230 kV and 115 kV
buses at the station to double bus, double breaker. All associated system deficiencies will be
mitigated.
Alternative 3- Garden Springs 230kV Station Integration: The Garden Springs 230 kV
Station Integration project includes the installation of new 230/115 kV transformation in the
Spokane area. The additional transformation will offload the Westside #1 and #2 230/115
transformers. In the future, the Garden Springs 230 kV Station Integration project will be
necessary in addition to the Westside Transformer Replacement project.
Alternative 4 - Replace Westside Transformers without Station Rebuild: Replacing the
existing Westside transformers to 250 MVA rated transformers will mitigate the transformer
overload system deficiencies but will create a short circuit breaker rating exceedance.
Additional P2 bus outage system deficiencies will exist.
Business Case Justification Narrative Page 3 of 7
Exhihit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 268 of 535

DocuSign Envelope ID: C659FOEO-7CE3-4641-9CAA-9DO806C4E6A1
Westside 230/115kV Station Rebuild
Option Capital Cost Start Complete
[Recommended Solution] Westside Transformer $32M 2015 2022
Replacement
Alternative#1 Status Quo $OM
Alternative#3 Garden Springs 230kV Station
Integration
Alternative #4 Replace Westside Transformers
without Station Rebuild
2.1 Describe what metrics, data, analysis or information was considered when preparing
this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost($) to benefit(value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
System Planning Assessments.
2.2 Discuss how the requested capital cost amount will be spent in the current year (or
future years if a multi-year or ongoing initiative). (i.e. what are the expected functions,
processes or deliverables that will result from the capital spend?). Include any known or
estimated reductions to O&M as a result of this investment.
How will the outcome of this investment result in potential additional 0&M costs, employee or staffing
reductions to 0&M(offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward(ref. WUTC Docket No. U-190531 Policy
Statement),therefore it is critical that these impacts are thought through in order to support rate recovery.]
2020 — $3,000,000
2021 - $3,500,000
2022 - $2,800,000
2023 - $2,000,000
2024 — $1,000,000
O&M costs will be comparible to what they were before this project.
2.3 Outline any business functions and processes that may be impacted (and how) by
the business case for it to be successfully implemented.
[For example, how will the outcome of this business case impact other parts of the business?]
System Operations will have improved functionality of the electric system.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation
strategies for each alternative.
See Section 2.0 for alternative discussion.
Business Case Justification Narrative Page 4 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 269 of 535

DocuSign Envelope ID: C659FOEO-7CE3-4641-9CAA-9DO806C4E6A1
Westside 230/115kV Station Rebuild
2.5 Include a timeline of when this work will be started and completed. Describe when
the investments become used and useful to the customer. spend, and transfers to
plant by year.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful.
(i.e. if transfer to plant occurs monthly, quarterly or upon project completion).]
Construction will continue through 2024. Transfers to Plant will be at the close of each
Phase.
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives
and mission statement of the organization.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]
Mission: We improve our customers' lives through innovative energy solutions.
Vision: Better energy for life
The completion of this project leads directly to a dimished threat of customer outages.
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please explain
how the investment prudency will be reviewed and re-evaluated throughout the
project
The scope for the project, which is to increase transformation capacity in the Spokane area
is the least cost option that provides the needed functionality. Adhering to the scope and
project objectives will be reviewed regularly by the project team including the project
engineer and the project manager.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Electrical Engineering, Generation Production/Substation Support, Transmission
Operations and System Planning and Operations
2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]
Not Applicable.
3 MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a part
of your departmental prioritization process.]
• Project Engineer/Project Manager (PE/PM)- Dana Gerbing/Zachary Curry
• Engineering Roundtable Committee
The assigned PE/PM holds stakeholder meetings to develop/confirm scope, schedule
and costs. Also meets at time of pre-construction. Other meetings held as necessary.
This project has also been reviewed by the Engineering Roundtable.
Business Case Justification Narrative Page 5 of 7
Exhihit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 270 of 535

DocuSign Envelope ID: C659FOEO-7CE3-4641-9CAA-9DO806C4E6A1
Westside 230/115kV Station Rebuild
3.2 Provide and discuss the governance processes and people that will provide
oversight
Engineering Roundtable meets several times a year to analyze current and future projects.
3.3 How will decision-making, prioritization, and change requests be documented and
monitored
Project folders are saved to Engineering shared drives and Businesss Case Funds
Requests are available on the Finance sharepoint site
Business Case Justification Narrative Page 6 of 7
Exhihit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 271 of 535

DocuSign Envelope ID: C659FOEO-7CE3-4641-9CAA-9DO806C4E6A1
Westside 230/115kV Station Rebuild
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Westside 230/115kV Station
Rebuild and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.
DocuSigned by:
Signature: 9 AA ., h4jkW Date: Tun-28-2022 1 3:36 PM PDT
Print Name: 7D4B3DGf8Yiff3Madden
Title: Manager, Substation Engineering
Role: Business Case Owner
DocuSigned by:
Signature: �bsL vtb�ovh Date: Jul-05-2022 1 7:41 AM PDT
Print Name: J A3C718Ugl ffbiLuciano
Title: Director, Electrical Engineering
Role: Business Case Sponsor
Signature: Date:
Print Name: Damon Fisher
Title: Principle Engineer
Role: Steering/Advisory Committee Review
Template Version: 05/28/2020
Business Case Justification Narrative Page 7 of 7
Exhihit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 272 of 535

DocuSign Envelope ID:295EB345-26ED-4B6E-9598-1809C6891E74
Gas Above Grade Pipe Remediation Program, ER 3009
EXECUTIVE SUMMARY
Within the natural gas distribution system of all three states (WA, ID, &OR), there are sections of gas
pipelines that are located above grade at crossings such as bridges, small ditches, irrigation canals, etc.
These above grade crossings have a variety of construction techniques and supporting structures which
vary in age, condition, design, compliance, and overall risk. This Business Case provides capital
expenditure for remediating those sites where regular O&M maintenance activities (e.g. replacement of
pipe supports and/or pipe wrap) are no longer appropriate. Facilities needing capital remediation will be
identified and prioritized by applying a risk-based scoring methodology to all known above grade crossing
locations. Each identified location will be unique in how it is remediated, and the costs will vary depending
on the complexity of the project. These projects will typically involve either installing new pipe below
grade or rebuilding the existing crossing.
Currently there are a total of 222 known above grade crossing sites across all three states. 155 in
Oregon, 23 in Idaho, and 44 in Washington. All Oregon sites were risk assessed in 2019 and
Washington/Idaho sites were assessed in 2023/2024. Starting in 2024, the annual capital budget for this
program is divided between the three states based on risk and remediation scope.
Out of the original 159 sites risk assessed in Oregon, 33 were identified as exceeding the program's
scoring threshold for allowable risk. Washington and Idaho assessments resulted in an additional 16
sites above the risk threshold for a total of 49 sites across all three states. The plan is for all sites above
the risk threshold to be remediated over the next 10 years through the combination of both O&M and
Capital dollars. Preliminary estimates forecast the need for approximately 43 capital projects with an
average cost of$150,000 per site. This puts the total 10-year budget at about$6.5 million (today's
dollars) with a recommended annual spend of$650,000 (+ 3% inflation) starting in 2024 (Year 2 of
program). In general, this is enough to fund one or two large drill projects, two to four medium drill
projects, or between five to seven small drill or rebuilt crossing projects per year. This work will ensure our
gas pipeline facilities continue operating with reduced risk, resulting in a safe, compliant, and reliable
system for our communities and customers. If this program is not continued, Avista will be at risk of fines
from: State PUCs for being out of compliance with federal safety codes, pipeline failures if support
structures fail, environmental fines if a pipeline failure results in a release of gas, and prolonged loss of
service to gas customers.
Remediation of these sites using capital dollars can provide direct and indirect O&M cost saving benefits,
as well as reputational benefits between Avista and the three State Commissions. Positive working
relationships with state Commissions can lead to more favorable rulings during audits/inspections. The
direct O&M cost savings are associated with quarterly patrol inspections, 3-year atmospheric corrosion
inspections, and future maintenance work (e.g. pipe coating and hanger repairs) that can all be eliminated
when using capital dollars to relocate the pipeline underground. In addition, relocating facilities
underground will reduce Avista's risk of incurring Indirect O&M costs associated with regulatory fines,
customer outages, and safety incidents.
VERSION HISTORY
Version Author Description Date
1.0 Jeff Webb Initial submission of original business case 71812021
2.0 Mike Yang Updated for 2022, Used new template 8/26/2022
2.1 Mike Yang Updated to the refreshed 2023 Business Case Template 411912023
2.2 Brock Benzel Updated for 2024 with WA/ID assessment results. 411512024
BCRT Team
BCRT Memember Has been reviewed by BCRT and meets necessary requirements 412512023
Business Case Justification Narrative Template Version: February 2023 Page 1 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 273 of 535

DocuSign Envelope ID:295EB345-26ED-4B6E-9598-1809C6891E74
Gas Above Grade Pipe Remediation Program, ER 3009
GENERAL INFORMATION
YEAR PLANNED SPEND PLANNED TRANSFER TO
AMOUNT ($) PLANT ($)
2025 (YR3) 669,500 669,500
2026 (YR4) 689,500 689,500
2027 (YR5) 710,000 710,000
2028 (YR6) 731,500 731,500
2029 (YR7) 753,500 753,500
Project Life Span 10years
Requesting Organization/Department Gas Engineering/B51
Business Case Owner I Sponsor Brock Benzel /Jeff Webb Alicia Gibbs
Sponsor Organization/Department Gas Engineering/B51
Phase Execution
Category Program
Driver Mandatory& Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
Aboveground main is required to be inspected once every three years for atmospheric corrosion
per CFR 192.481. To properly inspect for corrosion, the entirety of the pipe must be available for
visible assessment. Some legacy sites have pipe that is installed in a manner that makes it
impossible to do a proper inspection. Additionally, gas mains in places or on structures with the
potential for physical movement(i.e. bridges) must be patrolled 4 times a year in business districts
and 2 times a year outside of business districts per CFR 192.721. The intent of these patrols is to
ensure sound structures and hanging supports. Some of the sites on the list have hanger systems
that are failing due to corrosion or concrete deterioration, resulting in improper support of gas pipes.
This program provides capital dollars to address these deficiencies when an O&M solution is not
preferred.
If the site is remediated with capital dollars by installing the pipe below grade, Avista eliminates the
O&M expense of the once every three-year atmospheric corrosion inspection and the quarterly
bridge inspection. Future O&M work to repair deteriorated pipe coatings and/or pipe hangers would
also be eliminated by relocating the pipe below grade. Additionally, the Distribution Integrity
Management Program (DIMP) will assess a lower risk score since below grade installations have
much less of a chance of being damaged by an earthquake, flood, or vehicle incident. Major events
such as an earthquake, flood, or vehicle incident have the potential to cause large scale customer
Business Case Justification Narrative Template Version: February 2023 Page 2 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 274 of 535

DocuSign Envelope ID:295EB345-26ED-4B6E-9598-1809C6891E74
Gas Above Grade Pipe Remediation Program, ER 3009
outages (500 or more outages) and/or large environmental risks associated with an uncontrolled
release of gas from the pipeline.
1.1 What is the current or potential problem that is being addressed?
This program is addressing above grade gas pipeline crossings that are not in compliance with
federal safety codes and/or have been deemed high risk through a risk evaluation performed by
Gas Engineering and Gas Integrity. Within the natural gas distribution system of all three states,
there are sections of gas pipelines that are located above grade. Some of these sites are no longer
compliant with current safety codes and design practices, or the support structures are failing. Like
other areas of the gas and electric system, over the years construction practices have changed due
to stricter standards and improved construction methods. As a result, these above grade crossings
have a variety of construction techniques and supporting structures with varying degrees of risk
associated with each of them.
Currently there are a total of 222 known above grade crossing sites across all three states. 155 in
Oregon, 23 in Idaho, and 44 in Washington. All Oregon sites were risk assessed and prioritized in
2019, while the Washington and Idaho sites were risk assessed across 2023 and 2024. Starting in
2024 the annual capital budget for this program is split amongst the three states based on risk,
remediation scope, and Gas Engineering assessments.
Out of the 159 sites risk-assessed in Oregon, 33 were identified as exceeding the program's
scoring threshold for allowable risk. Additionally, Washington and Idaho have 16 sites that exceed
the risk threshold, which results in a grand total of 49 sites across all three states being considered
high risk. Site remediations began in 2023 with 6 Oregon sites being bored or eliminated. Over the
next 9 years, the remaining 43 sites will be remediated through the combination of both O&M and
Capital dollars. Current estimates forecast the need for approximately 37 capital projects with an
average cost of$158,000 per site. This puts the remaining 9-year budget at about$5.8 million with
a recommended annual spend of$669,500 (+ 3% inflation).
This capital work will ensure our gas pipeline facilities continue operating with reduced risk,
resulting in a safe, compliant, and reliable system for our communities and customers. If this
program is not started, Avista will be at risk of fines from: State PUCs for being out of compliance
with federal safety codes, pipeline failures if support structures fail, environmental fines if a pipeline
failure results in a release of gas, and prolonged loss of service to gas customers.
1.2 Discuss the major drivers of the business case.
The major driver is Mandatory& Compliance. This remediation is necessary to stay in compliance
with CFR 192 safety codes. Asset Condition is a secondary driver for remediating high risk above
grade piping. Aboveground main is required to be inspected once every three years for atmospheric
corrosion per CFR 192.481. To properly inspect for corrosion, the entirety of the pipe must be
available for visible assessment. Some legacy sites have pipe that is installed in a manner that
makes it impossible to do a proper inspection. Per CFR 190.223 Avista can be fined up to
$257,664/day per violation with a maximum total fine limit of$2,576,627.
Another major driver of this business case is the risk of a pipeline failure due to major events such
as earthquakes, floods, vehicular damages, etc. Above grade pipeline facilities assessed as being
high risk are typically more susceptible to failure during one of these events and/or a failure could
result in consequences that are deemed to be unacceptable. Consequences of an above grade
pipeline failure could result in an uncontrolled release of gas into the air, as well as a prolonged (i.e.
24 hrs or more) loss of gas service to customers. The cost of a gas outage is estimated at$2,960
Business Case Justification Narrative Template Version: February 2023 Page 3 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 275 of 535

DocuSign Envelope ID:295EB345-26ED-4B6E-9598-1809C6891E74
Gas Above Grade Pipe Remediation Program, ER 3009
per customer', which equates to around $296,000 for an outage of 100 customers or$1.48 million
for an outage of 500 customers. There could also be negative reputational and customer safety
impacts (i.e. no heat) associated with a prolonged loss of gas service.
This business case is intended to address and mitigate these compliance and asset condition risks.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The Oregon PUC delivered to Avista a Notice of Probably Violation (NOPV)for a bridge crossing in
Roseburg, Oregon in their 2021 safety audit that requires action on the part of Avista to remediate.
With this program in place, it shows the PUC in all three states (OR, WA, and ID)that Avista
recognizes the shortcomings and has a plan to address them. This work is necessary now because
we currently have pipeline crossings that are not in compliance, are at risk of failing, and are at risk
of fines from State PUC Safety Departments.
There are several issues that are typical of these sites that need to be addressed. Each of these
could cause Avista to be out of compliance with federal safety standards: the pipe wrap may have
failed or deteriorated to the point of no longer being effective, the support hangers may be
dislodged from their support structure (normally a bridge)and/or the support hangers may be the
style that do not allow a complete inspection for atmospheric corrosion, the support structure may
be failing and no longer able to provide adequate support for the gas pipe, or the warning signs
may be missing.
In addition to more immediate threats such as flooding and vehicular damage, the threat of a major
earthquake from the Cascadia Subduction Zone poses a significant threat to seismic vulnerable
high risk pipeline facilities, especially in Western Oregon. Experts predict a 15-40% chance of a
major earthquake within the next 50 years and if it happens before Avista is able to address these
high-risk sites there could be significant financial, safety, and operational consequences.
If Avista chooses to do nothing about these sites, there is a high probability that State PUCs will
fine Avista on future violations. Failing to take any action erodes trust and goodwill between Avista
and State PUCs, so it's expected that the magnitude and frequency of these fines would increase
over time with each successive violation. Per CFR 190.223 Avista can be fined up to $257,664/day
per violation with a maximum total fine limit of$2,576,627.
See section 2.4 for more detail around risk and how it increases over time if nothing is done.
1.4 Discuss how the proposed investment, whether project or program,
aligns with the strategic vision, goals, objectives, and mission statement
of the organization. See link Avista Strategic Goals
One of Avista's core values is"Trustworthy." Taken from the principles and beliefs that drives us,
"our word is reliable; we do what is right." By taking care of these pipeline facilities and making
them as reliable as possible, we keep the public safe by preventing failures and ensues our
facilities are not out of compliance. These preventive measures allow the performance of Avista to
not be hindered and ensures that the gas pipeline facilities continue to operate with reduced risk,
resulting in a safer and more reliable system for our customers.
' See Section 2.4 for more details on the estimated gas outage cost per customer
Business Case Justification Narrative Template Version: February 2023 Page 4 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 276 of 535

DocuSign Envelope ID:295EB345-26ED-4B6E-9598-1809C6891E74
Gas Above Grade Pipe Remediation Program, ER 3009
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.
In 2019, Gas Engineering assessed all known above grade pipe locations in the state of Oregon by
visiting each site in person, taking pictures, evaluating the condition of the pipe, coating, and pipe
support structures, reviewing the area for possible remediation options, and then finally using a risk
scoring matrix developed with Gas Integrity to risk rank all 159 sites. Of these sites, 33 of them
were classified as high risk/requiring remediation. In 2023 and 2024, Gas Engineering assessed a
total of 67 sites, 23 in Idaho and 44 in Washington. This assessment also consisted of in person
site visits, taking photos, and evaluation of the condition of pipe, coating, and pipe support
structure. In addition, the Washington and Idaho risk assessments criteria expanded based on
lessons learned during the Oregon risk evaluations. Additional criteria included: evaluation of bridge
conditions, accessibility to pedestrians, vulnerability to vehicles, and the consequence of an outage
at the crossing. Of the 67 site evaluations, 12 sites in Washington and 4 in Idaho were found to be
above the risk threshold. Because the Washington and Idaho site evaluations gathered additional
data points, the Oregon risk model contains a different scoring matrix than the WA/ID sites.
However, both risk models share a common backbone and scoring technique. Sites above 65000 in
Oregon are considered high risk while Washington and Idaho sites must be above 1400. As time
allows in the future, Gas Engineering would like to reevaluate the Oregon sites to join all crossings
into the same improved scoring matrix.
List of 33 above grade sites in Oregon that exceed 65000 risk score threshold:
Crossing Decription Nearest Address City • Water Name • Size of Pil Operating Pressu MAO•Pipe •Instal -
Hwy 99S/Bridge-S-Umpqua 8374 Old Hwy 995 Winston South Umpqua River 6 intermediate 60 steel 1964 134850
Riverside Dr/Bridge-Days Cr 430 SE Riverside Dr Myrtle Creek South Myrtle Creek or Days Creek 2 intermediate 40 steel 1982 134310
Washington St/Bridge-5-Umpqua 303 W Harvard Ave Roseburg South Umpqua River 6 intermediate 60 steel 1963 110160
Rogue River 333 Classick Dr Rogue River Ward Creek 10 high 293 steel 1963 108570
S Main Ell lot St/Bridge-Canyon Cr 535S Main St Canyonville Canyon Creek 2 intermediate 60 steel 1964 107670
335 Pleasant View 335 Pleasant View Or Grants Pass Tokay Canal 2 intermediate 60 steel 1964 106470
3500 Block Anderson Ave.Bridge 3520 Anderson Ave Klamath Falls 2 intermediate 60 steel 1988 105840
1115 Taylor Bridge 1121 19851-aylor Rd Central Point Griffin Creek 6 intermediate 60 steel 1964 105210
1812Talent Ave 1812Talent Ave Talent Canal 6 high 470 steel 1963 103950
On Bridge over Rogue River 205 Upper River Rd Gold Hill Rogue River 10 high 293 steel 1963 100725
1975 Houston Rd 1975 Houston RD Phoenix Coleman Creek 6 high 470 steel 1963 96720
2908 Voorhies 2809Voorhies Rd Medford Coleman Creek 6 high 470 steel 1963 96720
811 Crestbrook 2295 Crestbrook Rd Medford Lazy Creek 2 intermediate 60 steel 1959 95460
Waite St/Bridge Calapooia Cr 352 Waite St Sutherlin Sutherlin Creek 2 intermediate 60 steel 1998 93330
3028Cole m an Creek Rd 3020 Coleman Creek Rd Medford Coleman Creek 6 high 470 steel 1963 90210
3869Jacksonville 3857W Main St Medford Daisy Creek 3/4 intermediate 60 steel 1992 89670
2188 Fruitdale 2077 Rogue River Hwy Grants Pass 11/4 intermediate 60 steel 2003 82950
401S Rose 401S Rose St Phoenix 2 intermediate 60 steel 1965 81270
1013 Conklin 1013 NW Conkl in Ave Grants Pass 3/4 intermediate 60 steel 1899 80a50
Hamlin St/Bridge-Canyon Cr 185 Hamlin Or Canyonville Canyon Creek 2 intermediate 60 steel 1985 80190
237Talent Ave 237Talent Ave Talent Wagner Creek 6 high 470 steel 1963 78960
Kirtland Rd 2667 Kirtland Rd Central Point Whetstone Creek 6 high 470 steel 1963 77190
S Talent Ave 1Corral Ln Ashland Bear Creek 2 intermediate 60 steel 1899 74250
1755 Gaffney 1755 Gaffney Way Grants Pass South Main Canal 2 intermediate 60 steel 1965 73800
109 Maple St 109 Maple St Phoenix 11/4 intermediate 60 steel 1967 73530
1914 Archer 1895 Archer Dr Medford Phoenix Canal 2 intermediate 60 steel 1971 73260
247 Sky Crest 2475ky Crest Or Grants Pass 2 intermediate 60 steel 1990 73140
3051 Coleman Creek Rd 3051 Coleman Creek Rd Medford 6 high 470 steel 1963 72750
88 Greenway 87 S Gre enway Dr Medford 11/4 intermediate 60 steel 1969 69930
Douglas Ave/Bridge-Deer Cr 2525 N E Douglas Ave Roseburg Deer Creek 2 intermediate 60 steel 1985 68970
816 BI ack Oak 816 Black Oak Or Medford Larson Creek 4 intermediate 60 steel 1964 65520
1899/1901 Hamilton 1797 Hamilton Ln Grants Pass South Main Canal 2 intermediate 60 steel 1969 65520
825 Murphy 825 Murphy Rd Medford Larson Creek 4 intermediate 60 steel 1960 65520
List of 16 above grade sites in Washington and Idaho that exceed the 1400 risk score threshold.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-13-25-01
J. DiLuciano,Avista
Schedule 3,Page 277 of 535

DocuSign Envelope ID:295EB345-26ED-4B6E-9598-1809C6891E74
Gas Above Grade Pipe Remediation Program, ER 3009
1 Missouri Flat Crk@Grand&Ritchie 615 N Grand Ave,Pullman,WA 99163 6 60 4485
2 3rd and Mentem 301 Merriam,Davenport,WA 99122 4 60 2996.25
3 Palouse River@Grand Ave 305 N Grand Ave,Pullman,WA 99163(East) 6 60 2981.5
4 Paradise Creek @ Alpine Clinic 4853 WA-270,Pullman,WA 99163 0.75 300 2904
5 Crawford Rd/ 395-HP 6" 507 W Crawford St,Deer Park,WA 99006 6 500 2613
6 Missouri Flat Crk@Stadium Way 150 NE Stadium Way,Pullman,WA 99163 6 60 2173.5
7 Pal-River,Bridge St S of Main 1205 Bride St,Palouse,WA 99161 2 60 20735
8 Mouth of 9 Mile 2166th St,Wallace,ID 83873 4 60 2025
9 600Arden Hill Rd 640 Arden Hill Rd 2 250 1943
30 Palouse River @ 6th St&Morton 1408 N Parkview Dr,Colfax,WA 99111 2 45 1959.25
11 Spring St@Reaney Way 700 NE Reaney Way,Pullman,WA 99263 8 1W 1780
12 Home-St-West Park School 510 Home St,Moscow,ID 83843 2 60 1750
13 N Division St&W of Elm Ave,Suspended On W side of bridge 701 N Columbia St,RitzviIle,WA 99169 2 30_ 1656.75
14 Mouth of Terror Gu lch 106 Terror Gu lch Rd,Osburn,ID 83849 4 60 1609.75
15 Sprague Access,W of We Ranging on S Overpass 2020 F Sprague Ave,Spokane,WA 99202 6 60 _ 15675
16 Erie N of Sprague Overpass Vertical Along Wall 1020 E Sprague Ave,Spokane,WA 99202 5 60 1518
The ongoing assessment work conducted by Gas Engineering is all stored on the corporate
network drive: c01d44\GASENGINEER\GAS DESIGN DOCUMENTATION\Engineer
Documentation\M Yang\Programs & Committees\ER 3009 -Above Grade Pipe Remediation
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative(e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
It is recommended to spend $669,500 (plus 3% inflation) per year mitigating these sites. In general,
this is enough to fund one or two large directional drill projects, two to four medium directional drill
projects, or possibly between five and seven small directional drill or rebuilt crossing projects per
year. This level of spending will allow the highest ranked projects to be remediated within a 10-year
period. This mitigation work will ensure our gas pipeline facilities continue operating with reduced
risk, resulting in a safe, compliant, and reliable system for our communities and customers.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).
The risk avoidance/reduction of this program would be to avoid the fines from WA, OR and ID State
PUC's for being out of compliance with federal safety codes. Secondly, this program prevents
pipeline failures by ensuring pipe supports are sound and therefore avoids environmental fines if a
pipeline failure results in the release of gas. Lastly, by remediating the above grade pipe we are
mitigating the loss of service risk to downstream gas customers and the resultant outage costs.
See table below and Sections 2.3 and 2.4 for details on the cost offsets associated with this
program:
ER 3009 Cost Offsetsz 2025 2026 2027 2028 2029 2030 to 2043
0&M (Indirect)-Multiple $162,831 $162,831 $162,831 $162,831 $162,831 $3,762,470
0&M (Direct)-Maintenance $6,289 $6,289 $6,289 $6,289 $6,289 $94,340
Reference Sections 2.3 and 2.4 of this document for offset details
Business Case Justification Narrative Template Version: February 2023 Page 6 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 278 of 535

DocuSign Envelope ID:295EB345-26ED-4B6E-9598-1809C6891E74
Gas Above Grade Pipe Remediation Program, ER 3009
0&M (Direct)-Patrols $1,694 $3,388 $5,082 $6,776 $8,470 $237,160
Capital(Indirect)-Leaks $12,500 $12,500 $12,500 $12,500 $12,500 $187,500
The projects listed below are the top ranked project locations and their initial estimates. These
projects total $2,160k, which is about three years' worth of projects averaging $720k per year. Due
to the magnitude of the Rogue River Bridge site, some shifting of funds and projects will need to
happen to ensure timely completion. As we learn more about each of these sites from the maturing
of the designs and permits, the project list may change as appropriate to balance available funds
and risk mitigation.
0 Hwy 99 S/Bridge-S Umpqua River-6" IP Main- $450,000
0 Riverside Dr/Bridge-Days Creek-2" IP Main - $10,000
0 1812 Talent Ave-Canal Crossing -6" HP Main - $90,000
0 1985 Taylor Bridge#121 -Griffin Creek-6" IP Main - $100,000
o Washington St/Bridge-S Umpqua River-6" IP Main - $170,000
0 Rogue River Bridge- 10" HP Main - $1,250,000
0 S Main Elliot St/Bridge-Canyon Creek-2" IP Main - $75,000
0 335 Pleasant View Dr-Canal Crossing -2" IP Main - $15,000
The Reference Offset Calcs spreadsheet that explains the Risk Avoidance Over Time can be found
on department drive c01d44:\GASENGINEER\GAS DESIGN DOCUMENTATION\Budget\Business
Cases Updates\ER 3009 Gas Above Grade Pipe Remediation and can be made available upon
request.
2.3 Summarize in the table, and describe below the DIRECT offsets or
savings (Capital and O&M) that result by undertaking this investment.
ER 3009 Cost Offsets 2025 2026 2027 2028 2029 2030 to 2043
0&M (Direct)-Maintenance $6,289 $6,289 $6,289 $6,289 $6,289 $94,340
0&M (Direct)-Patrols $1,694 $3,388 $5,082 $6,776 $8,470 $237,160
Several above grade pipeline locations per year require O&M maintenance to repair pipe coatings,
warning markers, pipe hangers, etc. Over the next 40 years it is estimated that every high risk
above grade pipe location will require at least two maintenance projects to keep the pipeline
operational and compliant. It is expected over the next 10 years of this program that 35 sites will be
relocated belowground, 3 sites will be remediated with aboveground piping, and 4 sites will be
remediated with O&M maintenance (-42 high risk sites in total). Relocating these high-risk
pipelines belowground eliminates the need for two future maintenance projects and replacing with
aboveground pipe eliminates one future O&M maintenance project.
Avista is currently performing mandated quarterly patrol inspections and documentation for all
above grade pipe crossings.When these pipes are relocated underground, the quarterly bridge
crossing maintenance and documentation burden will be reduced eliminated as there will no longer
be above grade piping at these sites to inspect. In addition to saving O&M dollars, this will allow
employees to focus on higher priority work.
The Reference Offset Calcs spreadsheet that explains Direct Cost offsets can be found on
department drive c01d44:\GASENGINEER\GAS DESIGN DOCUMENTATION\Budget\Business
Cases Updates\ER 3009 Gas Above Grade Pipe Remediation and can be made available upon
request.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 279 of 535

DocuSign Envelope ID:295EB345-26ED-4B6E-9598-1809C6891E74
Gas Above Grade Pipe Remediation Program, ER 3009
2.4 Summarize in the table, and describe below the INDIRECT offsets3
(Capital and OW) that result by undertaking this investment.
ER 3009 Indirect Cost Offsets 2025 2026 2027 2028 2029 2030 to 2043
00 (Indirect)—Regulatory Fines $128,831 $128,831 $128,831 $128,831 $128,831 $1,932,470
Capital(Indirect)-Leaks $12,500 $12,500 $12,500 $12,500 $12,500 $187,500
0&M (Indirect)—Failures&Outages $30,000 $30,000 $30,000 $30,000 $30,000 $1,350,000
0&M (Indirect)—Safety $4,000 $4,000 $4,000 $4,000 $4,000 $480,000
If nothing is done to remediate high risk above grade pipe locations, company risk will continue to
increase over the next 5 to 15 years until it becomes almost certain that Avista will experience an
event resulting in significant O&M and/or Capital costs. The most significant costs would occur due
to major regulatory fines, leaks, failures &outages, and safety incidents as described in previous
sections of this document. The risk matrix below was created to characterize how the probability of
each major item changes over time if nothing is done, and what the potential cost could be.
Risk ProbabilitV Definitions: Risk ProbabilitV for Calculating Indirect Offsets:
—Risk event expected to occur 100%
High(H) Risk event more likely to occurthan not 50%
Probable(P) Risk event may or may not occur 25%
Low(L) Risk event less likely to occur than not 10%
Very Low(VL) Risk event not expected to occur 1%
Risk Avoidance Over Time and the Cost of Doing Nothing:
Risk Over Time(years) Worst Case Cost
# Risk 1 2 5 10 15+ Cost Estimate Estimate
1 Regulatory Fines* L P P H VH $257,664 perday perviolation(Max) $ 2,576,627
$2,576,627 Tota I(Max)
2 Pipeline Leak VL L P H VH $5,000to$250,000persite(site $ 250,000
dependent)
3 Pipeline Failure&Outage VL VL L H VH $2,960/outage(ex.—$1.5 million for $ 1,500,000
500 outages)
4 Reputational L P H VH Erosion of PUC and Publictrust N/A
5 Employee&Public Safety VL VL VL L P $250,000to$2 million for Lost time, $ 2,000,000
healthcare,lawsuits,etc.(varies)
The indirect cost offsets table at the beginning of this section was created by taking the probability
percentage at the 5-year mark, multiplying that probability by the worst-case cost estimate, and
then dividing the cost across the 5-year timeline. The last column on the right was calculated in the
same way, except the probability at 15+ years was used instead of probability at the 5-year mark.
The cumulative costs at years 1-5 were subtracted from the 15+ year column so the costs weren't
counted twice. See below for a breakdown of the indirect cost offsets.
3 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 8 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 280 of 535

DocuSign Envelope ID:295EB345-26ED-4B6E-9598-1809C6891E74
Gas Above Grade Pipe Remediation Program, ER 3009
O&M Indirect Cost offsets:
O&M Indirect Offset years* Total Cost per
# Risk 2024 2025 2026 2027 2028 2029to 2043 Risk Item
1 Regulatory Fines $ 128,831 $ 128,831 $ 128,831 $ 128,831 1$ 128,831 $ 1,932,470 $ 2,576,627
3 Pipeline Failure&Outage $ 30,000 $ 30,000 $ 30,000 $ 30,000 $ 30,000 $ 1,350,000 $ 1,500,000
5 Employee&Public Safety $ 4,000 $ 4,000 $ 4,000 $ 4,000 $ 4,000 $ 480,000 $ 500,000
TOTALS $ 162,831 $ 162,831 $ 162,831 $ 162,831 $ 62,831 $ 3,762,470 $ 4,576,627
CAPITAL Indirect Cost offsets:
CAPITALAnnual Indirect Offsets* Total Cost per
# Risk 2024 2025 2026 1 2027 1 2028 1 2029to 2043 Risk Item
2 Pipeline Leak $12,500 $12,500 $12,500 1 $12,500 1 $12,500 1 $ 187,500 $ 250,000
*Took probability at 5 year mark,multiplied by worst case cost,and then divided by 5 for cost/year over 5 years
from 2024to 2028. For 2029 to 2043 took probability at 15+year mark,multiplied by worst case cost,and
subtracted 5-year costs(2024to 2028).
The Reference Offset Calcs spreadsheet that explains Indirect cost offsets and the associated risk
matrix can be found on department drive c01d44:\GASENGINEER\GAS DESIGN
DOCUMENTATION\Budget\Business Cases Updates\ER 3009 Gas Above Grade Pipe
Remediation and can be made available upon request.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those
additional risks to Avista that may occur if an alternative is selected.
Option Capital Cost Start Complete
Recommended Solution: Remediate above ground $669,500 Jan Dec
pipe sites at requested funding level-
Alternative Solution 1: Remediate above ground $335,000 Jan Dec
pipe sites at a reduced funding level -
Alternative Solution 2: Remediate above ground $1,339,000 Jan Dec
pipe sites at an increased funding level-
Business Case Justification Narrative Template Version: February 2023 Page 9 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 281 of 535

DocuSign Envelope ID:295EB345-26ED-4B6E-9598-1809C6891E74
Gas Above Grade Pipe Remediation Program, ER 3009
Alternative 1: Lower Funding
This alternative solution would remediate the identified above ground pipe sites at half the
recommended annual funding level. If the program is funded at a lower level, then the risk to the
gas system and our customers will be reduced at a slower pace. Additionally, the slower
remediation pace will increase our risk to potential fines from the utility commissions. Furthermore,
it could be difficult to remediate a large, complex site with a low annual budget. This alternative is
not advised.
Alternative 2: Increased Funding
This alternative solution would remediate the identified above ground pipe sites at double the
recommended annual funding level. If the program receives double the annual funding, in theory,
the program would remediate twice as many sites per year. However, due to the increased
workload, it is likely that the additional budget would not be spent and instead be returned or
reallocated. This alternative is not advised.
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
Success will be measured by a reduction in the number of high-risk sites from the original 33 on the
current Oregon risk matrix, as well as a reduction in the 16 high risk sites identified during the 2023
WA& ID risk assessment.
Projects will be started each year, and in most cases will be completed within a year of beginning.
Some sites may require unique permitting or specialty equipment that may extend that project
timeline beyond a year. Once construction begins, an individual project will typically be completed
within the same calendar year.
Progress is monitored by the Engineering team and more information can be made available upon
request. In 2023, 6 high risk sites in Oregon were remediated.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
At this time, this is an ongoing program that will typically consist of multiple completed projects
each year for a program timeline of 10 years to remediate an estimated 43 sites using capital
dollars. Projects become used and useful and beneficial to customers upon the purging into
service of the new pipeline and retirement of the high-risk pipeline.
Remediation projects commenced in 2023 where 6 high-risk sites were remediated in Oregon.
There are 5 projects in the design phase for 2024 across Oregon, Washington, and Idaho.
The program will be reassessed every year to determine if adjustments are needed to the risk
evaluation methodology, risk scoring results, program funding, and program timeline.
Business Case Justification Narrative Template Version: February 2023 Page 10 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 282 of 535

DocuSign Envelope ID:295EB345-26ED-4B6E-9598-1809C6891E74
Gas Above Grade Pipe Remediation Program, ER 3009
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of
the business case, and how such oversight will occur.
The Gas Engineering department is responsible for the approval and oversight of this business
case. The program's spend and budget will be reviewed monthly by the Gas Engineering
Prioritization Investment Committee. If any changes to the budget for the year are needed, the
Business Case Owner proposes a budget change and justification that must get approval from the
Business Case Sponsor before it is brought before the Capital Planning Group. If additional funds
are not approved, then the remaining work is reduced to remain within budget.
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Above Grade Pipe Remediation
Program, ER3009 and agree with the approach it presents. Significant changes to this will
be coordinated with and approved by the undersigned or their designated representatives.
s de Ma 1
Signature: g�w� Date: y-
21-2024 10:07 AM PDT
F
Print Name: Jeff Webb
Title: Mgr Gas Engineering
Role: Business Case Owner
Signature: agua �us Date:May-21-2024 15:00 PM PDT
�49C42885348E483..
Print Name: Alicia Gibbs
Title: Director of Natural Gas
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 11 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 283 of 535

DocuSign Envelope ID: 94AEE31C-04DC-44F1-ADD7-3E6E28A7FAFF
Gas Cathodic Protection Program, ER 3004
EXECUTIVE SUMMARY
Cathodic Protection (CP) systems are used to stop corrosion on buried steel gas pipes. CP
system compliance is mandated by Federal Rules within the Department of Transportation code
49 CFR 192, Subpart I. Failure to meet code requirements can result in financial penalties up to
$2,675,627 per violation.
Some CP systems have been in service at Avista for extended periods of time, have exceeded
their useful service life, and are no longer functional (or are showing signs of imminent failure).
Natural gas leaks on corroded pipe, especially at or near buildings and residences, can result in
a threat to life and property. Gas leaks can result in unsafe environments for customers and
Avista's employees. These conditions warrant a replacement of those systems. It is often
difficult to predict in advance when specific projects are required, because sudden component
failures do occur. Anodes, a key component of the CP systems, are buried and not observable,
they deteriorate at differing rates, and can become ineffective when they are physically
depleted. Annual testing is required on all CP systems. Each test reading must fall within a
certain numerical range to be compliant with pipeline code. Any test results that are not
compliant are flagged for follow-up action. Repairs or adjustments must be made to the system
- usually within 90 days to meet code requirements. Additionally, new anode beds are needed to
provide additional CP to the growing gas system.
The estimated annual cost for this budget is based on past expenditures and allows for the
installation of approximately 7 anode beds per year. Because of the unpredictable nature of
these projects, it is not always known in advance how much of the funding will be allocated to
each state. The annual program spend of$735,000 effectively protects millions of dollars worth
of steel pipe that may need to be replaced if CP systems were not adequately maintained.
Additional expenditures in this budget also include the installation of system testing and
monitoring equipment. These new technologies allow for remote monitoring and control of the
CP systems. They alert technicians to system failures and reduce the number of trips needed to
check system status, resulting in a reduction of O&M expenses. Customers benefit from this
reduction in expenses as well as the improved safety and reliability of the gas system.
VERSION HISTORY
Business Case Justification Narrative Template Version: February 2023 Page 1 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 284 of 535

DocuSign Envelope ID: 94AEE31C-04DC-44F1-ADD7-3E6E28A7FAFF
Gas Cathodic Protection Program, ER 3004
Version Author Description Date
1.0 Tim Harding Initial draft of original business case 4/03/2017
1.1 Jeff Webb 4/04/2017
2.0 Tim Harding Revised for 2020 Oregon GRC Filing 211712020
2.1 Tim Harding Updated to the refreshed 2022 Business Case Template 813112022
2.2 Shontelle Wilson Updated to the refreshed 2023 Business Case Template 4/6/2023
2.3 Tim Harding Updated to the refreshed 2023 Business Case Template 411812023
2.4 Tim Harding Updated Direct Offset section 11127123
2.5 Tim Harding Updated for 2024 Business Case 4115124
BCRT BCRT Team Has been reviewed by BCRT and meets necessary requirements 411712024
Member
GENERAL INFORMATION
YEAR PLANNED SPEND PLANNED TRANSFER TO
AMOUNT ($) PLANT ($)
2025 735,000 735,000
2026 755,000 755,000
2027 780,000 780,000
2028 805,000 805,000
2029 830,000 830,000
Project Life Span Ongoing
Requesting Organization/Department B51 —Gas Engineering
Business Case Owner I Sponsor Jeff Webb/Tim Harding Alicia Gibbs
Sponsor Organization/Department B51 —Gas Engineering
Phase Execution
Category Mandatory
Driver Mandatory& Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
Business Case Justification Narrative Template Version: February 2023 Page 2 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 285 of 535

DocuSign Envelope ID: 94AEE31C-04DC-44F1-ADD7-3E6E28A7FAFF
Gas Cathodic Protection Program, ER 3004
1. BUSINESS PROBLEM — This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
Buried steel gas systems are protected from corrosion in two ways. First, they rely on
coatings that prevent contact between the steel and the surrounding soil. Secondly, a
technology called Cathodic Protection (CP) is used. CP systems use anodes that connect
to the gas system, and the anodes corrode instead of the steel pipe.
Much of this program budget is used to install new CP anode beds to replace aging
infrastructure. The sacrificial anodes are consumed as part of the CP process and the
service life of one of these installations is approximately 20-30 years. There are
approximately 250 anode beds installed across our service territory.
The operations of Avista's CP systems are largely governed by code requirements. Not
performing this work will put Avista out of compliance with state and federal codes. If CP
systems are not working properly, corrosion will occur on buried steel gas piping. This will
result in system integrity risks (corrosion leaks), as well as regulatory fines. Federal fines
are not prescribed but can range to a maximum daily fine of$257,664 per day and a
maximum total of$2,675,627 per violation. Natural gas leaks on corroded pipe, especially
at or near buildings and residences, can result in a threat to life and property. Gas leaks
can result in unsafe environments for customers and potentially Avista's employees.
1.2 Discuss the major drivers of the business case.
The main drivers for this business case are Mandatory & Compliance and Asset Condition.
Properly functioning cathodic protection systems are required by federal code. This code
requires the systems to operate within specific parameters. Those parameters can only
be met when the CP systems are regularly maintained and replaced when the anodes are
depleted.
The secondary driver for this business case is cost savings. The cost to install, operate,
and maintain a CP system is a small fraction of the financial benefit it provides. By funding
this program as requested, Avista can protect hundreds of millions of dollars' worth of steel
pipe infrastructure from corrosion, extending its useful life for decades.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The operations of Avista's CP systems are largely governed by code requirements. Not
performing this work will put Avista out of compliance with state and federal codes. If
cathodic protection systems are not working properly, corrosion will occur on buried steel
gas piping. This will result in system integrity risks (corrosion leaks), as well as regulatory
fines.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 286 of 535

DocuSign Envelope ID: 94AEE31C-04DC-44F1-ADD7-3E6E28A7FAFF
Gas Cathodic Protection Program, ER 3004
1.4 Discuss how the proposed investment, whether project or program,
aligns with the strategic vision, goals, objectives and mission statement
of the organization. See link.
Avista Strategic Goals
Cathodic Protection falls within Avista's goals for reliability, affordability, responsibility, and
safety. Avista chose to install CP systems prior to when they became a federal
requirement in the 1970's. Providing proper corrosion control on the gas systems has
extended the useful life of the steel pipes by several decades. A study found that a
significant amount of the steel gas system at Avista will have a service life of over 100
years. This would not have been possible without the early adoption of cathodic protection
systems in the 1960's, along with the continued operation, maintenance, and
improvements to these systems.
By extending the life the gas system, the need to replace aging infrastructure is reduced,
keeping costs down. The reduction in corrosion prevents pipe degradation and system
leaks. This reduces the need to make repairs and improves safety.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
Anode beds are installed for two reasons. The first is to replace an existing anode bed
that has failed due to end of life. The second reason is to increase the amount of
cathodic protection current available. Current requirements increase as the pipe coating
degrades over time, which effectively puts more pipe surface in contact with the
surrounding soil. Anode beds have a design life of approximately 25 years. With
approximately 250 anode beds in the system, it would be expected that approximately
10 are replaced every year.
See below for information related to anode bed installations from 2017 through 2023.
The average yearly anode bed replacement was 0.76% of the total anode beds in the
system (About 2 per year). This low replacement rate is approximately 1/5th the rate to
be expected on assets with a 25 year life expectancy. One reason that this is occurring
is because over 50% of the existing anode beds in the system were installed in the last
20 years. During this timeframe the CP systems in all three states were substantially
upgraded. Further analysis is needed to determine when the anode bed failure rate will
begin increasing. This information will be important for forecasting future budget needs.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 287 of 535

DocuSign Envelope ID: 94AEE31C-04DC-44F1-ADD7-3E6E28A7FAFF
Gas Cathodic Protection Program, ER 3004
New Anode Beds Replacement Anode Total Anode
Year Installed Beds Installed Beds Installed
2017 9 0 9
2018 2 4 6
2019 0 1 1
2020 2 2 4
2021 7 0 7 End of Year
2022 7 2 9 Anode Bed Count
2023 6 0 6 256
Total 9 42
Based off the above findings, anode beds are currently being replaced at a fraction of
the expected rate. In the future, failure rates are likely to increase, and more
replacements will be needed each year. The current funding of this program only
addresses the minimum installations required to stay compliant with code. Current
funding levels are not high enough to allow for the proactive replacement of aging CP
assets. In the future, possibly in 5-15 years, the program budget will need to increase
substantially to fund the replacement of 10+ anode beds per year.
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative(e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The program currently operates in a reactive manner. Annual testing identifies areas
in the system where follow-up work is needed, whether that be replacing anode beds
that have failed, or installing new anode beds to provide additional CP. The requested
level of spending is the lowest cost option to keep these systems functioning and
compliant with state and federal code. As mentioned in the above section, equipment
replacement rates are nearly an order of magnitude lower than necessary to keep up
with anticipated future failures. All these anode beds will eventually fail, and more
analysis needs to be done to predict when that will happen. At some point in the
future, failure rates will grow rapidly. A proactive approach that replaces the oldest or
poorest performing anode beds would spread replacement costs out more evenly in
the future and help avoid a future surge in failures.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 288 of 535

DocuSign Envelope ID: 94AEE31C-04DC-44F1-ADD7-3E6E28A7FAFF
Gas Cathodic Protection Program, ER 3004
2.2 Describe and provide reference to CIRRARR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
The requested amount is based on recent program spending and is the minimum cost
that keeps Avista's CP system in compliance with federal and state codes. This
budget primarily funds the installation of new and replacement anode beds. Cathodic
protection systems are required by federal code, and the criteria under which they
must be operated is specified in that code. Testing is performed on these systems
annually. Any system deficiencies must be addressed to remain in compliance, the
timeframe for this is 90 days based off WAC code 480-93-110. Since the actual
spending requirement for each year is difficult to predict, mid-year adjustments are
common. Overall, the annual cost of this program is low relative to the hundreds of
millions of dollars' worth of steel pipe that the CP system protects. In addition, this
program reduces the risk of corrosion related leaks that can range in severity from
relatively minor to potentially catastrophic.
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
There are no direct offsets or savings associated with this Business Case as it is a
mandatory, code required program.
2.4 Summarize in the table, and describe below the INDIRECT offsets
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital Addressed in Direct Offsets $0 $0 $0 $0 $0
0&M See note below $18,500 $19,000 $19,500 $20,000 $21,000
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 289 of 535

DocuSign Envelope ID: 94AEE31C-04DC-44F1-ADD7-3E6E28A7FAFF
Gas Cathodic Protection Program, ER 3004
When installing new anode beds, Avista's cathodic protection technicians charge time
to this capital budget that would otherwise be charged to O&M accounts. The above
numbers are based on the installation of five deep wells each year.
Risk Probability Definitions:
Risk event expected to occur
High(H) Risk event more likely to occurthan not
Probable(P) Risk event may or may not occur
Low(L) Risk event less likely to occur than not
Very Low(VL) Risk event not expected to occur
Risk Avoidance Over Time and the Cost of Doing Nothing:
Risk Over Time
1 2 5 10 15+
# Risk Year Years Years Years Years Cost Estimate
1 Regulatory Fines H VH V $257,664 per day per violation(Max)*
$2,576,627Total (Max)*
2 Pipeline Leak L L P H VH $5,000to$150,000 per site(site dependent)
3 Pipeline Failure&Outage L L P H VH $150,000to$3,000,000 per site(site dependent)
4 Negative Reputation L H H VH VH Erosion of PUC and Public trust
5 Employee&Public Safety VL L P H VH I Lost time, lawsuits,healthcare,etc.(varies)
*Regulatory fines present a daily and overall maximum value per violation in
accordance with 49 CFR Part 190.223. However, these values are not necessarily
an accurate representation of how much Avista would be fined for any specific
violation. The actual amount is likely to be much lower since Avista has an ongoing
reputation and history of investing in programs related to safety and non-compliance
issues. However, it is a bookend reminder from which to characterize the regulatory
risk associated with chronic and/or egregious non-compliance, especially in the event
of a pipeline safety incident (i.e. failure). Therefore, Avista must continue to
demonstrate an ongoing commitment to compliance and pipeline safety to ensure
favorable future outcomes with respect to regulatory penalties (actual penalty amount
is at the discretion of the state or federal agency).
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those
additional risks to Avista that may occur if an alternative is selected.
Alternative 1: Replace equipment at a faster rate
Replace equipment when it fails and add new equipment to keep the system in
compliance. Proactively replace aging anode beds to avoid a future rush of
replacements. When there is a rush of replacement to meet the 90-day repair
Business Case Justification Narrative Template Version: February 2023 Page 7 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 290 of 535

DocuSign Envelope ID: 94AEE31C-04DC-44F1-ADD7-3E6E28A7FAFF
Gas Cathodic Protection Program, ER 3004
requirement (required per code), this halts other programs and work. In these
instances, the project must be rushed, and it becomes more expensive due to the
expedited nature of the work.
Anode bed installations are needed both to replace failed beds, as well as to add
more CP current to existing systems. Both of these needs are code-required and are
just being met by the current funding level. As mentioned in section 1.5, current
replacement rates are low and will increase in the future. Replacing 4% of the
system's anode beds each year would allow the oldest and poorest performing beds
to be removed from the system and reduce the chance of sudden failures. To achieve
this, about 8 additional beds would need to be replaced each year, at the additional
cost of approximately $600k ($1.265M total).
Alternative 2: Replace all steel pipe with plastic
Per Federal code, CP systems are required on all buried steel gas pipes. The only
way to avoid having CP systems is to replace all steel piping with plastic piping. A
project like this would cost well over$1 billion and require digging up thousands of
miles of streets to install the new pipe.
As of 2022, Avista had 15 million feet of buried steel main and 5.5 million feet of
service piping. In 2024 the average main replacement cost is $180/ft, and the average
service replacement cost is $40/ft. Replacing all of Avista's steel gas piping with
plastic piping would cost approximately $3 billion and take decades of construction
accomplish.
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
Annual testing is required on all CP systems. The results of this testing are stored in
Maximo and the data is audited by inspectors from the public utility commissions in all
three states. Each test reading must fall within a certain numerical range to be
compliant with pipeline code. Any test results that are not compliant are flagged for
follow-up action. Repairs or adjustments must be made to the system - usually within 90
days per code.
All the processes, including follow-up actions, are tracked in Maximo. The CP group
doesn't actively track metrics, but there is historical data available to review.
2.7 Please provide the timeline of when this work is schedule to
commence and complete, if known.
This is an ongoing program with work being performed year-round. Anode beds
are typically installed in the summer and fall. Each project is unique, but they
generally take between one week and two months to complete. Projects are used
and useful upon completion.
Business Case Justification Narrative Template Version: February 2023 Page 8 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 291 of 535

DocuSign Envelope ID: 94AEE31C-04DC-44F1-ADD7-3E6E28A7FAFF
Gas Cathodic Protection Program, ER 3004
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of
the business case, and how such oversight will occur.
The General Foreman of the Cathodic Protection group oversees projects done by the
group. This program is monitored by an Engineer within Gas Engineering who has
technical expertise in Cathodic Protection. If any changes to the budget for the year are
needed, the Business Case Owner proposes a budget change and justification that must
get approval from the Business Case Sponsor before it is brought before the Capital
Planning Group. If additional funds are not approved, then the remaining work is
reduced to remain within budget.
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the ER 3004 Cathodic Protection and
agree with the approach it presents. Significant changes to this will be coordinated with
and approved by the undersigned or their designated representatives.
o s'g d by:
Signature: g w.0 Date: May-01-2024 1 4:42 PM PDT
E
Print Name: Jeff Webb
Title: Mgr Gas Engineering
Role: Business Case Owner
—si d by:
Signature: al�aa ebbs Date: May-02-2024 1 8:05 AM PDT
Print Name: Alicia Gibbs
Title: Director of Natural Gas
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 9 of 9
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 292 of 535

Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
EXECUTIVE SUMMARY
In February 2012, Avista's Asset Management Group released findings in the "Avista's Proposed Protocol
for Managing Select Aldyl-A Pipe in Avista Utility's Natural Gas System" report. The report documents
specific Aldyl-A pipe in Avista's natural gas pipe system, describes the analysis of the types of failures
observed, and the evaluation of its expected long-term integrity. The report proposed the undertaking of a
twenty-year program to systematically replace select portions of Aldyl-A medium density pipe within its
natural gas distribution system in the States of Washington, Oregon, and Idaho.
The Gas Facility Replacement Program (GFRP) was initiated in 2012 and is planned to continue for 20
years in Washington (until the end of 2031) and in Idaho and Oregon (until the end of 2037). It is the sole
mission and charter for the GFRP to plan and execute the replacement of 737 miles of Aldyl-A main pipe
and to rebuild 17,769 service tee transitions throughout Avista's service territories. The Aldyl-A main pipe
replacement work includes Aldyl-A pipe that is 1-1/4" diameter through 4" diameter and with an install date
prior to January 1, 1987, or a manufactured date prior to January 1985, As of March 2024, the GFRP has
298 miles of Aldyl-A remaining to be replaced across Avista's service territory and 325 STTR's left to
address via construction or map correction.
Avista has a regulatory mandate in Washington State to complete this program by the end of 2031 and has
a goal of investing in its infrastructure to achieve optimum life-cycle performance. The historical spending
trend from 2018 through 2023 has been $21 M-$30M annually. The requested budget amounts consider
Avista's regulatory mandate to complete this program with full contractor and company crew complement
and to adjust for labor, contract, paving and inflation costs. By completing Aldyl-A replacement on schedule.
we are aligning with Avista's Distribution Integrity Management Program's (DIMP) evaluation of risk. This
also meets Avista's goal of investing in its infrastructure to achieve optimum life-cycle performance. Inflation
of approximately 4-6% has been planned for by escalating the annual forecasted budgets.
This targeted Aldyl-A pipe will eventually reach a level of unreliability that is not acceptable due to the
tendency for this material to suffer brittle-like cracking leak failures. There is potential harm to the public
through damage to life and property and a high likelihood of increased consequences from failures in
Washington due to slow crack growth statistics These statistics show that the number of slow crack growth
failures in Washington have remained steady, despite nearly half of the Aldyl-A pipe having been replaced
since the program's inception. This data is available in 'Avista Utilities Aldyl-A Pipe Analysis (slow crack
growth leaks in WA, ID, OR)
GFRP UPDATE
In 2023 the GFRP completed a total of ten Major Main projects across three states. 28.20 miles of Aldyl-A
was replaced by contract crews and pipe verification, while an additional 5 miles was completed by Avista
crews. 6 miles were also removed through map corrections and editing. In total, 39.48 miles of Aldyl-A was
removed in 2023, leaving 310 miles remaining in Avista's system.
The initial approved budget for 2023 was $27,437,251. The GFRP received three different funds requests
throughout the year totaling $2.8M, bringing our final approved budget to $30,237,251. These additional
funds helped provide work for Avista crews which allowed us to meet our mileage goals in Washington as
well as keeping our contractor in Oregon working throughout the year. The GFRP's total spend in 2023 was
$30,438,014.
Business Case Justification Narrative Template Version: February 2023 Page 1 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 293 of 535

Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
2023 Miles Completed
State Miles mfles-gemawft
Washington 26.35 123.51
Idaho 2.67 65.23
Oregon 10.46 121.70
Total 39.48 310.44
In 2024, the GFRP plans to replace 30.48 miles of Aldyl-A. 24.28 miles will be completed by contract crews
on ten GFRP Major Main projects across all three states. An additional 5 miles will be completed by Avista
crews, including work in Ritzville and Goldendale. Washington. Work will also continue with the intent to
complete all remaining STTRs in the system in 2025 The current approved budget for 2024 is$27,187.251.
Total mileage of Aldyl-A remaining after 2024 is expected to be 279.96
2024 Miles Planned
State Planned Miles Miles Remaining
Washington 21.54 101.97
Idaho 1.21 64.02
Oregon 7.73 113.97
Total 30.48 279.96
In 2025, the GFRP plans to replace 31.02 miles of Aldyl-A. 26.02 miles will be completed by contract crews
on nine GFRP Major Main projects in Washington and Oregon. An additional 5 miles will be completed by
Avista crews, including work in Stevenson, Washington The current requested budget for 2025 is
$33,664,264. This budget will help support work for Avista crews and keep our program on pace to meet
commission required mileage goals in Washington state by 2031.
2025 Miles Planned
State Planned Miles Miles Remaining
-Washington 22.35 79.62
Idaho 0.00 64.02
Oregon 8.67 105.30
Total 31.02 248.94
Business Case Justification Narrative Template Version: February 2023 Page 2 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J.DiLuciano,Avista
Schedule 3,Page 294 of 535

Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
VERSION HISTORY
Version Author Liescrinflon -Date Notes
Draft Michael Whitby Initial draft of original business case 2011
1 Michael Whitby Budget Change 2015 $1.8M approved
2 Michael Whitby Bud et Chan a 2016 $3M approved
3 Michael Whitby Budget Change 2017 $21W returned
4 Michael Whitby Budget Chan a 2018 $1 M returned
5 Michael Whitby Bud et Chan a 2019 $1.5M returned
6 Karen Cash Budget Change 2020 $2.53M returned
7 Karen Cash Budget Change 2021
8 Karen Cash Budget Change 2022 $1.3lMapproved
9 Cody Lee Bud et Chan a 2023 $2.8M approved
BCRT BCRT Team Has been reviewed by BCRT and meets necessary Steve Carrozzo
Member uirements 413012024
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO PLANT
2025 $33,664,264 $33,664,264
2026 $33,802,675 $33,802,676
2027 $34,309,885 $34,309,885
2028 $35,576,667 $35,675,667
2029 $35,008,538 $35,008,538
Project Life Span 20 years in Washington and 25 years in Idaho&Oregon
Requesting Organization/Department Natural Gas/Gas Facility Replacement Program
Business Case Owner I Sponsor Cody Lee/Alicia Gibbs
Sponsor Organization/Department Energy Delivery/ Natural Gas
Phase Execution
Category Program
Driver Mandatory&Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
Business Case Justification Narrative Template Version: February 2023 Page 3 of 14
Exgibit No. 10
Case Nos.AW-E-25-01/AW-G-25-01
J.DiLuciano,Avista
Schedule 3,Page 295 of 535

Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
�. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
For Avista, aside from third party excavation damage, the highest risks within our natural gas
distribution system is Aldyl-A Main Pipe (Manuf. 1964-1984), and the bending stress that occurs on
Aldyl-A service pipe where it is connected to steel rnain pipe.
The GFRP was initiated in 2012 and is planned to continue for 20 years in Washington (until the end
of 2031) and in Oregon & Idaho(until the end of 2037). It is the sole mission and charter for the GFRP
to plan and execute the replacement of 737 miles of Aldyl-A main pipe and to rebuild 17,769 service
tee transitions. The Aldyl-A main pipe replacement work includes Aldyl-A pipe that is 1-1/4" diameter
and great and with an install date prior to January 1, 1987. or a manufactured date prior to January
1985. As of March 2024, there are 298 miles of pipe remaining across Avista's service territories.
The GFRP's Service Tee Transition Rebuild (STTR) Program was structured to mitigate the risks
associated with the "Bending Stress Services" category within a 5-year time frame. The STTR
Program started in 2013 and was deemed substantially complete in December 2017. As of March
2024, there are 325 STTR's remaining in Avista's service territory and are continuing to be
remediated by local gas districts.
1.2 Discuss the major drivers of the business case.
Avista has a regulatory mandate to complete this program and has a goal of investing in its
infrastructure to achieve optimum life-cycle performance.
As of August 2011, the US Department of Transportation Pipeline and Hazardous Materials Safety
Administration (PHMSA) mandates gas distribution pipeline operators to implement Integrity
Management Plans, or in Avista's case, a Distribution Integrity Management Plan (DIMP) in which
pipeline operators are required to identify and mitigate the highest risks within their system. For
Avista, aside from third party excavation damage, the highest risks within our natural gas distribution
system is Aldyl-A Main Pipe (Manuf. 1964-1984). and the bending stress that occurs on Aldyl-A
service pipe where it is connected to steel main pipe.
More specifically, and as related to the risks identified above, in February 2012 Avista's Asset
Management Group released findings in the "Avista's Proposed Protocol for Managing Select Aldyl-
A Pipe in Avista Utility's Natural Gas System-report. The report documents specific Aldyl-A pipe in
Avista's natural gas pipe system, describes the analysis of the types of failures observed, and the
evaluation of its expected long-term integrity. The report proposed the undertaking of a 20-year
program to systematically replace select portions of Aldyl-A medium density pipe within its natural
gas distribution system in the states of Idaho, Oregon. and Washington.
Subsequently, the Gas Facility Replacement Program's(GFRP)was formed as the operational entity
committed to structuring and implementing a systematic approach to mitigating the Aldyl-A pipe risks
as identified in the aforementioned report.
On December 31, 2012, the Washington Utilities and Transportation Commission (WUTC)
issued its policy statement on Accelerated Replacement of Pipeline Facilities with Elevated Risks
which requires gas utility companies to file a plan every two year for replacing pipe that represents
an elevated risk of failure. The requirement to file a Pipe Replacement Plan (PRP) commenced on
June 1, 2013. In response to this order. Avista's first 2-year PRP for 2014-2015 was submitted and
approved in 2013 per Docket PG-131837, Order 01. Avista's second two-year PRP for 2016-2017
was submitted in 2015 and approved in 2016 per WUTC Docket PG-160292, Order 01 Avista has
also submitted and received approval PRP's in 2017, 2019, 2021, and 2023. In Avista's filings, the
"Avista's Proposed Protocol for Managing Select Aldyl-A Pipe in Avista Utility's Natural Gas System"
Business Case Justification Narrative Template Version: February 2023 Page 4 of 14
Exhibit No. 10
Case Nos.AW-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 296 of 535

Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
report serves as the pipe replacement "Master Plan", and two-year pipe replacement goals which
includes specific project locations, and the anticipated pipe replacement quantities.
On March 6, 2017 the Oregon Public Utilities Commission ("Commission") issued Order 17-084
(Docket UM 1722, Investigation into Recovery of Safety Costs by Natural Gas Utilities), which in part
required each of the natural gas distribution companies serving customers in Oregon to file with the
Commission by September 30th each year an annual "Safety Project Plan" (or Plan).1 The purpose
of the Plan is to increase transparency into the investments rnade by each utility that are based
predorninantly on the need to achieve important safety objectives. More specifically, the Plan is
intended to achieve the following objectives:
• Explain capital and expenses needed to mitigate safety issues identified by risk analysis or new
federal and state rules.
• Demonstrate the utility's safety commitment and priority to its customers.
• Provide a non-technical explanation of primary safety reports each utility is required to file with the
Commission's pipeline safety staff; and
• Identify major regulatory changes that impact the utility's safety investments.
The Idaho Public Utilities Commission (IPUC) has not required gas utility companies to submit an
action plan, Avista has submitted the "Avista's Proposed Protocol for Managing Select Aldyl-A Pipe
in Avista Utility's Natural Gas System"report for review and communicates annual pipe replacement
goals which includes specific project locations, and the anticipated pipe replacement quantities.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
This work is needed now to ensure Avista fulfills the regulatory mandate to complete this program
and mitigate risk per DIMP modeling. The need to conduct this program has been identified in
"Avista's Proposed Protocol for Managing Select Aldyl-A Pipe in Avista Utility's Natural Gas System"
report. Further, and more specifically, due to the tendency for this material to suffer brittle-like
cracking leak failures, Aldyl-A will eventually reach a level of unreliability that is not economically
responsible to maintain and repair rather than replace. There is a potential harm to the public through
damage to life and property and there is a high likelihood of increasing regulatory scrutiny from
increasing failures. Not approving or deferring this body of work would further exacerbate the risks
as identified above.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
The Gas Facilities replacement Program (GFRP) is responsible for Aldyl-A pipe replacement which
aligns with Avista's mission to operate and maintain a "Safe and Reliable Infrastructure". Avista has
a goal of investing in its infrastructure to achieve optimum life-cycle performance.
The objective of this investment and structured replacement program is to reduce risk and prevent
future catastrophic natural gas incidents. We are holding our customers interests at the forefront of
all our decisions by choosing to replace these natural gas facilities. The GFRP also aligns with
Avista's strategic vision by doing this in a safe, responsible, and affordable manner.
Business Case Justification Narrative Template Version: February 2023 P grfb5 of�4
10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 297 of 535

Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
1.5 Supplemental Information — please describ and ;ummarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
a. On December 31, 2012, the Washington Utilities and Transportation Commission (WUTC) issued its
policy statement on Accelerated Replacement of Pipeline Facilities with Elevated Risks which requires gas
utility companies to file a plan every two years for replacing pipe that represents an elevated risk of failure.
The requirement to file a Pipe Replacement Plan (PRP) commenced on June 1, 2013.
b. February 23, 2012 —Avista Utilities Asset Management"Proposed Protocol for Managing Select Aldyl-
A Pipe in Avista Utilities' Natural Gas System."
c. April 11, 2013 - Revised Avista Utilities Asset Management"Proposed Protocol for Managing Select
Aldyl-A Pipe in Avista Utilities' Natural Gas System."
d. July 2013 —ARMS Reliability Report—Avista Study of Aldyl-A Mainline Pipe and Bending Stress Point
Leaks
e. Avista's first 2-year PRP to the WUTC for 2014-2015 was submitted and approved in 2013 per Docket
PG-131837, Order 01.
f. Avista's second 2-year PRP to the WUTC for 2016-2017 was submitted in 2015 and approved in 2016
per WUTC Docket PG-160292, Order 01.
g. Order of the Public Utility Commission of Oregon in Docket UM 1722, Investigation into Recovery of
Safety Costs by Natural Gas Utilities, March 6, 2017.
h. Avista's Proposed Protocol for Managing Select Aldyl-A Pipe in Avista Utility's Natural Gas System
report serves as the pipe replacement"Master Plan", and two-year pipe replacement goals which
includes specific project locations. and the anticipated pipe replacement quantities.
i. April 2018 —ARMS Reliability Report-Avista Study of Aldyl-A Mainline Pipe Leaks 2018 Update.
j August 2020 -Avista Utilities Asset Management"Aldyl-A Pipe Analysis (slow crack growth leaks in
WA, ID, OR)".
k. September 2022 —Avista Utilities Asset Management"Study of Aldyl-A Pipe Leaks 2022 Update".
I. Avista's sixth 2-year PRP to the WUTC was approved in 2023 per WUTC Docket PG-230390, Order 01.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 298 of 535

Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
2. PROPOSAL AND RECOMMENDED SOLUTION - Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g.,_cost benef!t
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
"Avista's Proposed Protocol for Managing Select Aldyl-A Pipe in Avista Utility's Natural Gas System"
report details the various time horizons modeled for the Aldyl-A Pipe Replacement program. The
Aldyl-A Pipe Replacement effort has been proposed and planned as a systematic 20-25-year pipe
replacement program. The program is expected to have a nominal impact to existing business
resources, functions, and processes since the GFRP has been structured to function as a "stand
alone" program consisting of mostly dedicated internal resources. The primary functions established
for these internal resources are to plan, design. oversee, manage, and administer the significant body
of projectized work as assigned to"external" contract construction resources.
Periodically, on an as-needed basis, the GFRP will call on other business units for support. Since
pipe replacement work is a capital expenditure, the impact to O&M cost has been minimal.
Occasionally GFRP projects will encounter circumstances that necessitate O&M expenditures. When
known, these O&M costs are estimated prior to construction The GFRP tracks and monitors O&M
costs monthly.
Option Capital Cost Start Complete
Replace priority high-risk Aldyl-A pipe = S650M January 2012 December 2037
in a 20-25-year timeframe
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, ucneiizs or riSK avuivance L'SU jaLL: ; description of
how benefits to customers are being measured; metrics such as
jnparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
The 2013 Avista Study of Aldyl-A Mainline Pipe Leaks was updated in 2018 based on the current leaks
and replacements statistics through the end of 2017 The study incorporated leak reduction and risk
avoidance in the analysis.
After updating the model with leaks and replacements from 2013-2018 the expected number or leaks
for the remaining period (2018-2088) reduced from 26,792 to 12,335 due to the large amount of at-risk
pipe already replaced.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 PEa 7�p1t
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 299 of 535

Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
Scenario Leaks IRR Levelized Gr. Lev ROE' NPV equity*
from Mar.
2018 Requirement"
through
2088
Baseline with effects- 26 792 9 21% $18,417 s0 $0
2013
20 Year Replacement 2y�with effects-2013 o G4°° 523.229 S6 513 593.490
Baseline with effects-
2018 12 335 18 040a S 10.785 SQ $0
20 Year Replacement
with effects-2018 24r 3 870o S36.147 512-214 S177,848
Safety risks and criticality were also considered as part of the study update. It is understood that each
failure event (leak) does not always result in an injury, and this is incorporated as a percentage of
events that result per Avista standard modeling guidelines. The severities used are shown in table
below. The projected number of catastrophic events drop from 258 to 5 events over the next 70 years
by replacing the Aldyl-A pipe
Seventy °°of Failures Where Effect
�...,.
Occurs
Catastrophic event 50 Years 1.M
Craft injury,WITH Lost
1 Ye3i 0.1100
Time/Light Duty
Craft injury,NO lost Time 3 Months I 0.2T,,
While Avista's structured replacement program has proven to reduce the highest risk in the early years
of the program, the continuation of this structured replacement program is both necessary and prudent
to mitigating the remaining risks within the system, and to achieving Avista's goal of operating and
maintaining a safe and reliable natural gas distribution system.
The 2013 study predicted a total of 26,792 leaks on Aldyl-A mainline pipe from 2018 through 2088
years without any form of a proactive replacement program Based upon the proactive replacements
that have occurred, the number of leaks predicted over the same period has reduced to 12,335 with
246 catastrophic events if the proactive replacement were to not continue With the current
replacement of all Aldyl-A pipe by 2035, the number of predicted leaks from 2018 to program
completion reduces slightly, moving from 255 to 246 leaks of which 4 have the potential to be
catastrophic events. The offsets to the GFRP, include but not limited to, regulatory fines, pipeline leaks,
pipeline failures and outages. negative company reputation, and elevated safety concerns. See below
for a list of the relevant pipeline safety regulations pertaining to the GFRP, as well as a breakdown of
each risk over time assuming nothing is done to remediate the Aldyl-A pipe.
Business Case Justification Narrative Template Version: February 2023 Page 8 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 300 of 535

Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
Risk Probability Definitions:
Risk event expected to occur
High(H) Risk event more likel- to occur than not
Probable(P) Risk event may or may not occur
Low(L I Risk event less likely to occur than not
Very Low(VL) Risk event not expected to occur
Risk Avoidance Over Time and the Potential Cost of the"Do Nothing" Alternative.
Potential RiskLH
Potential Risk 01er Time
Year _'Years fear% 10 Yeats 15- fears Cost Estimate
$225.1 34 per day per violation(Ntax)'
Regulatory Fines P H VFf VH S2.252.334 Total(.Ni x)`
Pipeline Leak H VH VH S5.000 to S150.000�ersite(site dependentPi lute Fail re R(hot e L P P VH S150.000 to S3.000.000 er site(site de endent)
`Ne ative Re utation P H VH VR Erosion of R't'TC and Public Trust
Em to•ee&Public SafyL P If Lost tune,healthcare.lawsuits.etc.(varies)
`Regulatory fines present a daily and overall maximum value per violation in accordance with 49 CFR
Part 190.223. However, these values are not necessarily an accurate representation of how much
Avista would be fined for any specific violation. The actual amount is at the discretion of the
enforcement agency and is likely to be much lower due to Avista's ongoing reputation and history of
investing in programs related to safety and non-compliance issues. However, it is a bookend reminder
from which to characterize the regulatory risk associated with chronic and/or egregious non-
compliance, especially in the event of a pipeline safety incident (i.e., failure). Therefore, Avista must
continue to demonstrate an ongoing commitment to compliance and pipeline safety to ensure favorable
future outcomes with respect to regulatory penalties.
It has been determined that this type of pipe is at risk and is approaching unacceptable levels of
reliability without prompt attention. The "Do Nothing" option exposes Avista to increased operational
risks, decreased system reliability, and worse, is a potential harm to customers and the public through
damage to life, property, and the environment. There would be a high likelihood of legal action against
Avista, regulatory fines, and negative reputation. The Aldyl-A pipe will eventually reach a level of
unreliability that is not acceptable due to the tendency for this material to suffer brittle-like cracking
leak failures. There is a potential harm to the public through damage to life and property and there is
a high likelihood of increasing regulatory scrutiny from increasing failures. Not approving or deferring
this body of work would further exacerbate the risks as identified above. Additionally, the GFRP would
not be able to address some of the highest risk/threats in the natural gas distribution system that have
been identified by Avista's Distribution Integrity Management Plan (DIMP).
Business Case Justification Narrative Template Version: February 2023 PP96'it�'O1140
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 301 of 535

Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
As shown in the graph below and outlined in "Forecasting Results" section of "Avista's Proposed
Protocol for Managing Select Aldyl-A Pipe in Avista Utility's Natural Gas Systerrr' report, Avista's
forecast modeling tool "Availability Workbench Modeling" evaluates several classes of pipe which are
represented as "curves" showing the percentage of the amount of pipe class that is projected to fail in
each year of the forecasted period.
Forecast Failure Rates for Natural Gas Piping
25%
— t
ti 1
O 1
v 20% 1
m
u t
w 1
w15°', r i Bending Stress Services
WEL
i Pre-1984AIdylA
0 10% r i 1984 and later Aldo A
Steel
Newer Polyethylene
a 5c'
u / i
a
0°lb -�. ....i' —
�
Years
The chart below identifies the expected number of material failures in Avista's Priority Aldyl-A piping in
two cases: Replacement Case — piping replaced over a 20-year time horizon, and Base Case —
assumed that priority piping was not remediated under any program.
—BaseCase —Replacement Case
N 600
Y
M
a+ 500
J
w
O 400 - —
Cl
E 300
3
Z
4+ 200
N
10
100 —
O
0 -,
2010 2015 2020 2025 2030 2035
Year
Business Case Justification Narrative Template Version: February 2023 PacGe.10 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 302 of 535

Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
2.3 Summaries in #hatable and describe below-the- DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M Leak Survey Cost Avoidance $114,539 $121,439 $127,908 $133.671 $139,836
Aldyl-A gas main is leak surveyed by a contractor on an annual basis rather than the
standard five-year cycle of other intermediate pressure natural gas mains. The 2024
contracted cost to survey one linear foot of gas main is $0.0467. The 439 miles of Aldyl-A
that has already been removed from Avista's system since 2012 and the forecasted 2025-
2029 replacement schedules are calculated cumulatively for the above O&M direct cost
savings. This calculation does not consider, CPI increases, per diem or Grade 1 standby
cost.
Other considerations of direct offsets were also taken into account but not calculated such
as reduced system maintenance, leak rates, etc. The GFRP will work with Gas
Compliance to establish how we can track and quantify these cost savings in the future.
2.4 Summarize in the table and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital Mitigatable Risk Cost Value $31,743 $62,620 $90,886 $117,370 $144,274
The above cost savings represent the probabilistic risk value that is mitigated by removing
vintage Aldyl-A gas main from our system. The value is calculated by analyzing the
probability of failure times the consequence of failure and takes into account geographic
location, ground composition and history of previous failures. The 439 miles of Aldyl-A that
has been removed since 2012 is not calculated since it is no longer in service. The
mitigatable risk value is calculated per year and will continue to compound and increase if
nothing is done to remediate the Aldyl-A. This model is re-run annually as risk values
increase with the age and degradation of the facility.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 11 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 303 of 535

Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those �iditional
to Avista that may occur if an alternative is selected.
To establish context, Avista's goal is to operate a safe, reliable, and cost-effective gas distribution
system Specifically, as related to the above statement, Avista's original 20-year plan is outlined in
"Avista's Proposed Protocol for Managing Select Aldyl-A Pipe in Avista Utilitys Natural Gas System".
This report details the various time horizons originally modeled for the Aldyl-A Pipe Replacement
program. It proposed and suggested that a systematic replacement program conducted over a 20-
year timeline was the optimum timeframe to prudently manage risk based on the forecasted number
of leaks, risks, and the rate impact to our customers.
Since the inception of the GFRP, Avista's Asset Management and Distribution Integrity Management
teams have continued to analyze expected trends and potential consequences, making program
adjustments as appropriate. The most recent changes made to program timelines are the extension
of Oregon and Idaho Aldyl-A pipe replacement to 2037. This is due in part to the reduction of slow
crack growth failures in Oregon and Idaho coupled with the number of failures in Washington
remaining steady despite nearly half of the Aldyl-A pipe having been replaced since the program's
inception. Extending Avista's Aldyl-A replacement work in these states to 2037 will allow us the
opportunity to balance affordability and overall impact to our customers. The supporting data and
analysis from Avista's Asset Management group shows that risk is continuing to be mitigated and
that extending work in Oregon and Idaho will not increase the risk of catastrophic failure.
If funding is not approved for this work, annual reductions in mileage will have to be made that impact
completion dates of our Aldyl-A replacement in Oregon and/or Idaho. For example, if funding is
reduced by $3M each year, the GFRP will have to reduce pipe replacement by 2.7 miles in either
Oregon or Idaho annually. Over a five-year period, this will cause a shortfall of mileage replaced by
13.5 miles. The impact of this is extending work an additional two years past 2037 to 2039.
Alternative 1:
Do Nothing:
It has been determined that this type of pipe is at risk and is approaching unacceptable levels
of reliability without prompt attention. The "Do Nothing" option exposes Avista to increased
operational risks, and worse, is a potential harm to our customers and the public through
damage to life and property, and a high likelihood of legal action against the Company and likely
regulatory fines. For this reason, it was deemed"not prudent'and is not a serious consideration.
Alternative 2:
Less than 20 Year Pipe Replacement Program:
Business Case Justification Narrative Template Version: February 2023 Pagge,12 of 14
ESchibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 304 of 535

Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
Avista found that a timeline less than 20 years resulted in a greater cost impact to customers in
the near term, and that it did little to reduce the forecast number of leaks expected each year.
This approach did not effectively optimize the potential risks and rate impacts.
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
See findings in section 2.2, 2.3, 2.4
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Washington
Start: 2012
Expected End: December 2031
Oregon & Idaho
Start: 2012
Expected End: December 2037
The annual list of projects in each of the three states (ID, OR, and WA) are established as unique
"blanket projects" that transfer to plant (TTP) each month as they are "used & useful".
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
The Gas Facility Replacement Program(GFRP)Advisory Group consists of the Manager of GFRP,
Gas Operations Contract Construction Manager. GFRP Business Analyst II, Director of Natural
Gas, and the Manager of Gas Design & Measurement. This group meets monthly to review
program wide Earned Value results, the status of the delivery of the individual projects, budget
allocations and variances, internal resource demands, customer care results and issues, contractor
performance, and to communicate potential program risks and shortfalls.
In addition, Avista's Distribution Integrity Management Plan and Asset Management groups provide
periodic input, and/or validation of the replacement plan and schedule.
Each year an annual portfolio of projects is derived from Avista's Distribution Integrity Management
Program (DIMP) Aldyl-A prioritization list which currently identifies unique priority project areas
(polygons) throughout the natural gas system in ID, OR, and WA. The portfolio of projects is sized
to meet jurisdictional commitments. Then individual priority projects are planned, phased, scoped,
designed, and detailed estimates are prepared. Once the individual project estimates are finalized.
the overall program-wide capital budget is refined to reflect a more precise budget. The requested
spend level has historically been determined based upon Avista's experience in the management
of the Aldyl-A pipe facilities across Avista's service territories coupled with any changing costs of
construction year to year.
Business Case Justification Narrative Template Version February 2023 Pa e 13 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 305 of 535

Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
3. APPROVAL AND AUTHORIZATION -
The undersigned acknowledge they have reviewed the Gas Facilities Re17lacement Program
Business Case and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.
Signature: Date: 4/29/2024
Print Name: Cody Lee
Title: Manager, GFRP
Role: Business Case Owner
Signature: ! , Date:
Print Name: Alicia Gibbs
Title: Director, Natural Gas
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 14 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 306 of 535

DocuSign Envelope ID:33DE473C-7232-491E-811F-32AA475F77137
Gas Isolated Steel Replacement Program, ER 3007
EXECUTIVE SUMMARY
In accordance with a Stipulated Agreement between Avista and the Washington State Utility
Commission (WUTC), and to maintain compliance with the Code of Federal Regulations 49
CFR 192.455, 192.457 and 192.465 Avista implemented an "Isolated Steel Identification and
Replacement Program" (program) beginning in 2011. The initial goal of the program was to
inspect, identify and remediate steel pipe and risers that are cathodically isolated or lack
required cathodic protection within Avista's Washington State natural gas pipeline systems.
Inadequate cathodic protection can result in corrosion of steel pipe and leaks related to
corrosion. Natural gas leaks on corroded pipe, especially at or near buildings and residences,
can result in a threat to life and property. Gas leaks can result in unsafe environments for
customers and potentially Avista's employees. As part of the program evolution, and to be
prudent in our operations, our efforts in recent years have expanded into Avista's Idaho and
Oregon service territories. Work completed under this program helps maintain Federal and
State compliance requirements and results in a safer gas distribution system, both for the
communities we serve and for Avista employees. Over the long term, this investment will help to
reduce operating and maintenance costs for Avista as we will no longer be required to spend
time and money locating and mitigating unknown isolated steel facilities. In general, the
corresponding O&M inspection program is focused on finding isolated steel services and service
risers by testing cathodic protection at each riser. It is important to note, however, that there are
other isolated steel service and mainline remediation projects completed under this Program
that are identified outside of the associated inspection program in all three states.
Remediation efforts in Washington State were completed in 2021 and approved by the WUTC
as outlined within a 2022 Closure Letter for the Stipulated Agreement. As this program has been
completed in Washington, the focus of the Gas Isolated Steel Replacement Program shifted into
Idaho and is now primarily in Oregon. Avista has finished identifying isolated steel in Idaho and
is now about halfway through the program inspections required to identify isolated steel in
Oregon. Remediation of identified sections of isolated steel pipe is ongoing in both Idaho and
Oregon to reduce the risk of hazardous leaks caused by continued corrosion of isolated steel
pipe in our distribution system. Most of the remediation in Idaho has been completed with only a
few known projects remaining. Due to the amount of isolated steel that needs to be identified
and remediated in OR, this will need to be an ongoing capital program. It is estimated, with the
requested level of capital funding, that the program will require approximately 7-10 additional
years to complete. Many of the replacement jobs generated during the inspection process have
a quick timeline (90-days to 1-year)for remediation to re-establish compliance. The remaining
jobs have longer term (10-year) replacement timelines from the date they are discovered. This
is because they comply with the Code requirements for cathodic protection, but they are still
isolated and require remediation as a best practice. This business case helps define the scope
of the Gas Isolated Steel Replacement Program.
VERSION HISTORY
Version Author Description Date
1.0 Jeff Webb Initial draft of original business case 311612017
1.1 Jeff Webb Revisions 410712017
1.2 Jenn Massey Revised for 2020 Oregon GRC Filing 211712020
1.3 Nick Messing Updated to the refreshed 2020 Business Case Template 711012020
1.4 Nick Messing Updated to the refreshed 2022 Business Case Template 5/05/2022
1.5 Seth Samsell S. Samsell took over Program and revised Business Case Template 8/25/2022
1.6 Shontelle Wilson/Seth Samsell Updated to the refreshed 2023 Business Case Template 411412023
1.7 Seth Samsell Revised 2024 Business Case 411512024
BCRT BCRT Team Member Has been reviewed by BCRT and meets necessary requirements 412212024
Business Case Justification Narrative Template Version: February 2023 Page 1 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 307 of 535

DocuSign Envelope ID:33DE473C-7232-491E-811F-32AA475F77137
Gas Isolated Steel Replacement Program, ER 3007
GENERAL INFORMATION
YEAR PLANNED SPEND PLANNED TRANSFER TO
AMOUNT ($) PLANT ($)
2025 3,000,000 3,000,000
2026 4,000,000 4,000,000
2027 5,000,000 5,000,000
2028 5,000,000 5,000,000
2029 5,000,000 5,000,000
Project Life Span Ongoing.Estimate 7-10 Additional Years
Requesting Organization/Department R08—Gas Programs
Business Case Owner I Sponsor Seth Samsell /Jeff Webb I Alicia Gibbs
Sponsor Organization/Department B51 —Gas Engineering
Phase Execution
Category Mandatory
Driver Mandatory& Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
There is an unknown amount of"isolated" steel pipe in Avista's Oregon natural gas
systems. Isolated steel pipe is defined as pipe that does not have adequate cathodic
protection or is protected but may be isolated from a cathodic system. Cathodic
protection is required by Federal Code to help prevent buried steel from corroding
below grade. Corrosion can cause leaks at or near service points resulting in
conditions that may be hazardous to life and/or property. This program originally
began in Washington State as result of a failed audit in which Avista was found to be
in violation of Code due to unknown and unprotected steel service piping. As a result,
we entered into a Stipulated Agreement with the WUTC, to identify, document and
remediate all unknown sections of isolated steel pipe including isolated steel main,
services and service risers within a specified timeframe. These efforts were carried
over into Idaho and are now ongoing primarily in our Oregon service areas.
Business Case Justification Narrative Template Version: February 2023 Page 2 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 308 of 535

DocuSign Envelope ID:33DE473C-7232-491E-811F-32AA475F77137
Gas Isolated Steel Replacement Program, ER 3007
1.2 Discuss the major drivers of the business case.
The major drivers for this business case include the categories "Mandatory and
Compliance" as well as aspects of"Customer Service, Quality and Reliability."
Isolated (unprotected) portions of steel pipe, including main, service pipe and risers,
do not comply with the Code of Federal Regulations. Per Federal rules 49 CFR
192.455 & 192.457 steel gas pipelines installed below ground must be cathodically
protected to prevent corrosion of the steel material. When steel pipe is found to be not
cathodically protected, Federal rule, 49 CFR 192.465 states that the issue needs to
be remediated "promptly". Washington Administrative Code (WAC) 480-93-110
defines promptly as "within 90 days". This is the standard that the original Washington
program was based upon, and it is also the recommended practice by the National
Association of Corrosion Engineers (NACE). Isolated (protected) portions of steel pipe
are allowed by Federal Code, if they are monitored every 10-years to ensure the
cathodic protection is still adequate and maintained.
Per the initial Stipulated Agreement in Washington, Avista was required to replace all
isolated steel pipe identified through the Washington inspection program within a
period of 90-days (if unprotected) or 10-years (if protected) to eliminate the potential
risk for non-cathodically protected steel and corrosion related leaks in the future.
Keeping in line with this practice, when isolated steel pipes have been found through
cathodic inspections in Idaho and Oregon (program and non-program), we have
historically replaced them to meet the requirements of 49 CFR 192.455 and 192.465.
Avista incorporated this standard of 90-day (isolated & unprotected) and 10-year
(isolated & protected) replacement timeframes as a means to stay compliant in all
three states. The alternative to replacement, to maintain Federal and State
compliance, would be to re-establish cathodic protection and monitor these locations
every 10-years per 192.465. Not maintaining the effort to locate and remediate
isolated steel pipe within the specified timeframes could mean that Avista would be
increasingly out of compliance with mandatory Federal and State regulations. This is
a significant risk and a required action in Avista's Integrity Management Plan.
Since the initial Washington program requirements have been satisfied, Avista has
shifted the program forward in Idaho and is working primarily in the Oregon service
areas to identify and remediate isolated steel pipe. Work under this program for Idaho
and Oregon is currently being completed to the same standard as in Washington.
Proactively locating and mitigating isolated steel pipe will result in a safer gas
distribution system for Avista's customers as well as our employees. When steel
pipes do not have proper cathodic protection, the risk of corrosion and related
corrosion leaks become significantly greater over time. We are not able to predict the
condition of the pipe or how long this pipe has been unprotected. We do know some
of steel pipe has been in the ground since the 1950s. Natural gas leaks on corroded
pipe, especially at or near buildings and residences, can result in a threat to life and
property. Gas leaks can result in unsafe environments for customers and potentially
Avista's employees. In circumstances where a corrosion related leak might require an
unplanned outage to repair, customer service, quality and reliability suffer as well.
These risks only continue to increase the longer this isolated steel pipe remains in the
ground and undetected.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 309 of 535

DocuSign Envelope ID:33DE473C-7232-491E-811F-32AA475F77137
Gas Isolated Steel Replacement Program, ER 3007
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
This work is needed now to comply with the Federal and State regulations and
Avista's standards as discussed in previous sections. Per Avista Gas Standards
Manual Spec 5.14 "When facilities under cathodic protection are found with pipe-to-
soil (P/S) potentials below adequate levels, the facilities must be scheduled for
restoration. Areas shall be restored within 90-days from the date they are found below
adequate levels of protection in Washington and should be restored within 90-days in
Idaho and Oregon as a best management practice." The goal of this program, moving
forward, is to maintain the same quality of work that was completed in Washington for
the states of Idaho and Oregon. Failure to complete the program to this same
standard may result in danger to life, property, and the environment. Other increased
risks include operational and financial penalties determined by Federal and State
regulators. These penalties could range from thousands of dollars to multi-millions of
dollars depending upon the severity of the incidence or violation. There is no effective
way to predict what the severity of an incident or penalty might be. However, by
maintaining and expanding this program, Avista is making an effort to locate isolated
steel within our natural gas system and to operate in compliance within Federal and
State regulations. The intent is to reduce the risk of corrosion on steel piping systems
and thereby reducing the chance for future leaks associated with these pipes. Work
completed under this program results in a safer, more reliable natural gas distribution
system in all the communities we serve, for Avista's customers as well as our
employees.
It is important to clarify that programmatic inspection work (O&M) creates follow-up
work (Capital)that is required to be completed within either a 90-day or a 10-year
timeframe to remain in compliance with the Code of Federal Regulations and Avista's
Standards for Gas Construction. Failure to replace pipe or re-establish CP within 90-
days or to meet other required compliance timeframes could lead to potential
violations with the Oregon Public Utility Commission. Deferring the budget request will
limit the Program's ability to complete the Program in the estimated timeline as well
as mitigate the risks associated with this compliance and integrity issue.
Additional system risks and estimates of their associated costs are listed in the table
on the following page. The exact cost of all these risks cannot always be predicted.
For that reason, cost ranges are provided.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 310 of 535

DocuSign Envelope ID:33DE473C-7232-491E-811F-32AA475F77137
Gas Isolated Steel Replacement Program, ER 3007
Risk Probability Definitions:
Risk event expected to occur
High(H) Risk event more likely to occur than not
Probable(P) Risk event may or may not occur
Low(L) Risk event less likely to occurthan not
Very Low(VL) Risk event not expected to occur
Risk Avoidance Over Time and the Cost of Doing Nothing:
Risk OverTime(years)
# Risk 1 2 5 10 15+ Cost Estimate
1 Regulatory Fines* L P H $257,664 per day per violation(Max)
$2,576,627Total(Max)
2 Pipeline Leak P P H $5,000 to$50,000 per site(site dependent)
3 Pipeline Failure&Outage L L L P H $50,000 to$200,000 per site(site dependent)
4 Negative Reputation L P H Erosion of PUC and Public trust
5 Employee&Public Safety L P p H Loss of life,property,lost time,lawsuits,
healthcare,etc.(varies)
*Regulatory fines present a daily and overall maximum value per violation in accordance with 49 CFR Part 190.223.
However,these values are not necessarily an accurate representation of how much Avista would be fined for any
specific violation. The actual amount is likely to be much lower since Avista has an ongoing reputation and history
of investing in programs related to safety and non-compliance issues.However,it is a bookend reminder from
which to characterize the regulatory risk associated with chronic and/or egregious non-compliance,especially in
the event of a pipeline safety incident(i.e.failure). Therefore,Avista must continue to demonstrate an ongoing
commitment to compliance and pipeline safety to ensure favorable future outcomes with respect to regulatory
penalties.(actual penalty amount is at the discretion of the state or federal agency).
Business Case Justification Narrative Template Version: February 2023 Page 5 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 311 of 535

DocuSign Envelope ID:33DE473C-7232-491E-811F-32AA475F77137
Gas Isolated Steel Replacement Program, ER 3007
1.4 Discuss how the proposed investment, whether project or program,
aligns with the strategic vision, goals, objectives and mission statement
of the organization. See link.
Avista Strategic Goals
This program aligns with Avista's organizational focus on our responsibility to
maintain a safe and reliable infrastructure in all the communities we serve, for all our
customers and for our employees who maintain these systems each day. By
proactively identifying and mitigating isolated steel pipe, we are staying in compliance
with Federal and State regulations, remaining innovative, and improving our existing
distribution systems. This program further demonstrates to our customers that we are
a responsible operator that puts customer safety first. Corrosion related leaks cannot
only cause outages but can compromise the safety of Avista customers and our
employees. As a best practice, Avista should continue with this program to prevent
corrosion leaks on steel pipe and help prevent associated incidents or outages by
proactively locating and establishing cathodic protection or replacing isolated steel
pipe.
The Gas Isolated Steel Replacement Program is in line with meeting Federal and
State code requirements. The program also follows Avista Gas Standards Manual
Spec 5.14 Cathodic Protection Maintenance, as quoted above in section 1.3 of this
business case justification. This program will locate and mitigate currently unknown
pipe that is not adequately protected cathodically and is at high risk for corrosion. By
working to comply with 49 CFR 192.455 and 192.465 this program works to maintain
safe and reliable natural gas systems and helps prevent future corrosion related leaks
at or near buildings which places Avista's customers and employees at risk. All of this
is in accordance with Avista's Standards and Integrity Management Plan.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 312 of 535

DocuSign Envelope ID:33DE473C-7232-491E-811F-32AA475F77137
Gas Isolated Steel Replacement Program, ER 3007
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
During the Washington program, beginning in 2011, approximately 175K inspections
were completed resulting in over 4,780 follow-up jobs ranging from additional required
inspections to full replacements of service risers or service lines. From these findings
Avista determined that continuing this program will address significant risk in our
Idaho and Oregon service territories as well. It is in Avista's best interest to address
these risks sooner rather than later. Idaho inspections are now complete and there
were approximately 1,500 follow-up jobs from over 58K locations inspected. There
are only a handful of replacement jobs remaining in Idaho, and these should be
completed over the next year or two.
Currently, of approximately 89K service locations in Oregon, more than 45K locations
still require inspection. The nature of the program often requires multiple inspections
at an individual location. At this time, it is estimated that more than 58K visits will be
required to complete the Oregon inspection process. Since Oregon inspections began
(in 2020) we have been finding isolated steel replacement jobs at a higher rate (1.5x-
2x) than that for Washington and Idaho. Because our sampling rate for steel
inspections is small, relative to the entire Oregon system, it is unknown if this high
rate of isolated steel discovery will continue in Oregon. What we do know, with the
information we have currently, is that we estimate there may be anywhere between
1,500 and 2,000 jobs in Oregon that would require remediation within a 90-day period
to re-establish compliance. We also estimate there may be up to 600-800 additional
jobs that would require remediation up to 10-years from the date they are discovered.
These are locations where we are compliant with cathodic protection requirements,
but replacement of a riser or service line is recommended as a best practice due to
the nature of the cathodic protection or the construction practices used at the time of
installation.
An isolated steel service replacement job in Oregon costs, on average, about $1 OK to
complete. A riser replacement is less cost; however, we do not always know what
mitigation will be required until the inspection process is completed, or the pipe is
exposed by a crew. Service replacements at these quantities and costs are estimated
to result in a capital investment of$15-20M to re-establish compliance. It is projected
an additional $6-8M will be required to mitigate remaining isolated steel services
estimated to be in the system long term. In total, it is estimated it will cost Avista
approximately $20-$30M in capital funding to complete the project. Capital funding
levels can limit the number of jobs that can be created and remediated each year.
Current operational resources can also limit the number of remediation jobs we can
complete each year. It is believed that the Program will require approximately 7-10
additional years to complete. These forecasts are based upon requested funding
levels. We believe the proposed capital funding will help us to generate the
information we require to continue to fine tune these estimates. Regardless, we will
continue to reduce risk within our natural gas system both from an operational and a
compliance standpoint through this program.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 313 of 535

DocuSign Envelope ID:33DE473C-7232-491E-811F-32AA475F77137
Gas Isolated Steel Replacement Program, ER 3007
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution
to the business problem identified above and why this is the best and/or least cost alternative(e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
As the program is now complete in Washington state, and mostly complete in Idaho,
the proposed solution in Oregon is to maintain similar standards and practices set out
for the original Washington program. The goal is to systematically identify and
remediate all sections of isolated steel pipe and service risers in our Oregon
operational areas. Replacement of these isolated steel pipes and risers maintains
compliance with Federal Code 49 CFR 192.465, WAC 480-93-110, NACE, and
Avista's Standards. It also fulfills Avista's goal to maintain our responsibility of
operating a safe and reliable infrastructure in all the communities we serve, for our
customer's as well as our employees.
There are approximately 45K locations remaining in Oregon that potentially require
multiple inspections to determine whether they have isolated steel. Ideally, we would
approach this program by completing all remaining inspections over a 3-4 year period
and at the same time be addressing the remediation efforts as follow-up in up to a 10-
year period post inspection, similar to the Washington program. With the information
we have currently, we estimate there may be anywhere between 1,500 and 2,000
replacement jobs in Oregon that would require remediation within a 90-day period to
re-establish cathodic protection and compliance. We also estimate there may be 600-
800 additional jobs that would require remediation within 10-years from the date they
are discovered. These additional locations are those where we are compliant with
cathodic protection requirements, but replacement of a riser or service line is
recommended as a best practice due to the nature of the cathodic protection,
materials or the construction practices used at the time of installation. Each season
we fine tune these estimates to update this business case to reflect the latest data.
Since the program O&M inspections generate capital replacement jobs, the level of
approved capital to support additional remediation work ultimately will control the
number of inspections that can be completed. The more inspections we can
complete, the better the data will be to be able to fine tune the scope and timeline for
the remaining program in Oregon. It is estimated, with the requested level of capital
funding, that the program will require approximately 7-10 additional years to complete.
The challenge with this program will be to manage the approved budget and the
resources required to complete the amount of required replacement work within the
required 90-day or 10-year timelines.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 8 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 314 of 535

DocuSign Envelope ID:33DE473C-7232-491E-811F-32AA475F77137
Gas Isolated Steel Replacement Program, ER 3007
2.2 Describe and provide reference to CIRRARR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits, or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
This business case is intended to address risk reduction and Avista's ability to
maintain compliance in the states we operate within. The program is aimed at
maintaining safe and reliable systems for our customers and not so much a cost
benefit or return on investment. As part of the original Stipulated Agreement with the
WUTC, Avista was required to address isolated steel at levels that were not known
prior to the establishment of the program. Like the Washington program proved, we
believe that isolated steel is a significant integrity issue in our Oregon system. We
believe this risk is significant enough that the investment should be made now to
maintain compliance and eliminate these risks. This is supported by thirteen years of
isolated steel inspections and data dating back to 2011. The ultimate threat is a
catastrophic event that would pose risk to life and property. That said, isolated steel
pipe and service replacements put new, more reliable plant in the ground as a capital
investment which improves the overall reliability of our system.
The requested funding amounts in this business case are being made based on the
number of remaining jobs in Idaho and Oregon, estimating the number of unknown
jobs in Oregon, comparing the average replacement costs in each state, and by
reviewing previous years' budgets along with the volume of work completed by the
program each year. As mentioned before, with the information we have currently, it is
estimated there may be anywhere between 1,500 and 2,000 replacement jobs in
Oregon that would require remediation within a 90-day period to re-establish cathodic
protection and compliance. We also estimate there may be 600-800 additional jobs
that would require remediation within 10-years from the date they are discovered.
In 2022, with an approved capital budget of$850K, additional approved requests of
$280K, and additional spend we were able to complete approximately 150
replacement jobs at a final cost of approximately$1.5M. In 2023, this level of
replacement increased to approximately 275 jobs at a final cost of approximately
$2.3M and we were able to perform 775 additional inspections on steel risers with the
increased level of capital funding.
Full service isolated steel replacement jobs are costing on average about $1 OK in
Oregon and we have seen single service replacement jobs as high as $25K
depending on the circumstances involved. These costs and the risk associated with
the issue are only increasing with time. Replacement at these quantities and cost
requires a significant capital investment ($20M to $30M) and additional resources to
complete the work in the required timeframes. This is work that will need to be
completed to stay in compliance and mitigate the risk. Deferring the work will only
increase the overall costs of replacement and place us at a greater compliance risk.
The data is constantly changing as more inspection and replacement cost information
is gathered. As this happens the forecasting will be improved, and the business case
updated to align requests moving forward with the amount of work required to mitigate
isolated steel in all Avista's service territories.
Business Case Justification Narrative Template Version: February 2023 Page 9 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 315 of 535

DocuSign Envelope ID:33DE473C-7232-491E-811F-32AA475F77137
Gas Isolated Steel Replacement Program, ER 3007
2.3 Summarize in the table and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital - $0 $0 $0 $0 $0
00 Reduced Costs of Inspection $0 $0 $0 $0 $150K
and 0&M Related Follow-Up
The program goal is to identify and mitigate all the isolated steel pipe in our system
which will eliminate the need to perform additional survey inspection work. We
estimate there will be approximately 58K inspections required at over 45K locations.
At current costs, this would be approximately $600K over the life of the remaining
inspection project or about $150K/year. Depending on the level of capital available,
we might be able to support completing the inspections in as soon as 3-4 years.
This is the assumption shown above.
Over time, the program will also reduce or eliminate the need to have Cathodic
Technicians performing isolated steel follow-ups created by the inspection orders.
At the volumes we estimate now, this could be a savings up to about $50K/year that
could be dedicated to other Cathodic Protection work within our systems. We could
potentially see these savings in as soon as 6-7 years. This would depend on the
rate at which we find isolated steel, the number of jobs we can complete each year,
as well as how long it would take for the Cathodic Technicians to complete all the
follow-up work orders generated from the inspections.
Over the long term, this investment will help to reduce operating and maintenance
costs for Avista as we will no longer be required to spend time and money locating
and mitigating unknown isolated steel facilities.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2023 Page 10 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 316 of 535

DocuSign Envelope ID:33DE473C-7232-491E-811F-32AA475F77137
Gas Isolated Steel Replacement Program, ER 3007
2.4 Summarize in the table and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital N/A $0 $0 $0 $0 $0
0&M Cathodic Protection $5000 $5000 $5000 $5000 $5000
Most of the offsets that would result by completing the isolated steel replacement
work are direct and are described in Section 2.3. The program, however, will reduce
the number corrosion leaks on isolated steel pipe as well as the number of issues
encountered when identifying and repairing the cathodic protection system allowing
Cathodic Technicians to focus on long term cathodic protection of the pipelines and
not locations where we have inadequate protection. The estimated savings of$50K
per year would apply in this case as well since it would enable the labor charges to
go to higher priority work on the cathodic system. It is not likely these costs would
be observed within the next 5-years of the program.
This program will also reduce the risk of outages caused by corrosion related leaks.
Most outages related to a corrosion leak on isolated steel would only impact a
single customer or service line at a time. It is estimated a single outage might cost
$51K, but the probability of an outage being caused by a corrosion leak is relatively
low.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those
additional risks to Avista that may occur if an alternative is selected.
Alternative 1
One alternative to the proposed solution is to locate and remediate isolated steel in
Idaho and Oregon at reduced funding levels. The inspection program, over the past
three years in Oregon, has focused on clearing and verifying PE riser locations (not
isolated). It has been limited on the number of steel inspections completed in order to
limit the number of follow-up jobs created to be within approved capital funding
levels. In 2-3 years, there will only be steel risers left to inspect. Maintaining reduced
funding levels will serve to perpetuate a reduced quantity of steel inspections each
year as costs continue to increase. We will only be able to complete inspections until
the maximum level of created jobs is met based on the level of program funding. This
will, in effect, delay the identification of isolated steel in Oregon, which already exists
in our systems, thus deferring our ability to identify and fix the problem.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 11 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 317 of 535

DocuSign Envelope ID:33DE473C-7232-491E-811F-32AA475F77137
Gas Isolated Steel Replacement Program, ER 3007
Deferring the costs to replace or remediate these integrity issues will extend the
program above and beyond the estimated timeframe. The identification and
mitigation of these facilities is inevitable as they are not in compliance with Federal
and State codes until they are cathodically protected. The longer we wait to identify
the location of these isolated steel pipes, the higher the risk becomes that the
unprotected steel pipes will corrode, develop leaks, and become hazardous to life,
property, and the environment. Delaying the Oregon program would not align with
Avista's current practice of mirroring the Washington program timeframe for Idaho
and Oregon and would put Avista at a much higher risk of being increasingly out of
compliance.
Estimated Cost of Alternative 1: $20M to $30M plus inflation and increased costs of
replacement over the deferred timeframe. In addition, any additional O&M costs
related to deferring the work.
Alternative 2:
An additional remediation alternative is to install temporary anode protection on
service pipes to meet the compliance requirements of 49 CFR 192.465 around re-
establishing cathodic protection within 90-days. It was determined in 2023 that the
installation of anodes on service piping can be capitalized. Installing anode
protection may allow for additional inspections to be completed because it could
extend the remediation timeframes. Anode installation may be a way to meet
compliance, however these pipes will likely still need to be replaced within 10-15
years, depending on their condition and future cathodic evaluation. We do not know,
and are not able to determine, the current condition of steel pipe in the ground or
how long these pipes have been unprotected. The only way to know this would be to
spend O&M dollars to dig all of them up and perform direct assessment on them,
which would be very costly and disruptive.
In 2023, we performed a pilot program in Medford, OR to install anodes on services
lacking proper cathodic protection. The goal was to complete more inspections on
steel pipe and to better understand the use of anodes and the installation process.
The average cost of mitigation using an anode was approximately $2500 - $3500,
50%-90% higher than originally expected. We estimate additional capital costs in the
range of$7M to $10M would be required to mitigate the estimated number of
isolated locations using anodes. In general, anode installation is a viable alternative
in locations where we need to buy time (e.g., moratorium streets) prior to a full
replacement. However, since most of these locations would require eventual full
replacement, this would be additional cost to the proposed alternative described in
Section 2.1. It is recommended that anodes be used as a mitigation tool available to
our Construction Districts, but not as a primary long-term solution.
Business Case Justification Narrative Template Version: February 2023 Page 12 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 318 of 535

DocuSign Envelope ID:33DE473C-7232-491E-811F-32AA475F77137
Gas Isolated Steel Replacement Program, ER 3007
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
The Gas Isolated Steel Replacement Program will be successful if the unknown
isolated steel riser/service count drops to zero in all Avista's service areas. This was
a Washington requirement and is a best practice for Idaho and Oregon.
The Washington program eliminated all known isolated steel and Idaho has 3 open
10-year isolated steel service replacement jobs remaining. Oregon has about 700
known isolated steel service replacement jobs open, but it is important to note that
Oregon's numbers only reflect the number of isolated steel replacement jobs
currently open in our Maximo system. The ongoing inspection program is continuing
to identify isolated steel in Oregon. Therefore, the job count in Oregon will increase
as the inspection program and replacements continue. Newly identified sites will be
added to the Oregon number for remediation. Approximately 89K services were
identified in Avista's GIS system, which have been flagged for inspection in Oregon.
The data shows that there are approximately 45K service locations that still require
inspection. This data and information are housed and processed through an MXD
system in AFM that is monitored by the Gas Programs department. The capital jobs
or work orders created under ER 3007 are documented in Maximo and monitored by
Gas Compliance Specialists.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Idaho mitigation projects should be completed in the next year or two. However,
there is currently not a set completion date for the Oregon program. It is estimated,
with the requested level of capital funding, that the program will require
approximately 7-10 additional years to complete. Ideally, we would pattern Oregon
after Washington and establish a 10-year plan to complete the work, however the
volume of work that may result from the Oregon inspections, may require more time.
Business Case Justification Narrative Template Version: February 2023 Page 13 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 319 of 535

DocuSign Envelope ID:33DE473C-7232-491E-811F-32AA475F77137
Gas Isolated Steel Replacement Program, ER 3007
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight
of the business case, and how such oversight will occur.
The governing committee for the program consists of the Manager of Gas Programs,
The Isolated Steel Program Coordinator, the Manager of Gas Compliance (1354), the
Manager of Gas Engineering (1351) and the Cathodic Protection group. This team
helps to determine the direction of the program as it relates to both inspection work
and capital replacement work.
The Manager of Gas Programs (R08) and the Isolated Steel team are responsible for
this business case as well as monitoring and administering ER 3007— Gas Isolated
Steel Replacement Program. Gas Programs is also responsible for monitoring and
administering the inspection process. The inspections are completed on a separate
O&M budget, but they generate the jobs that are created as part of this capital
replacement program. The data and information for the inspection program is
documented in the ArcGIS system as part of an MXD program. The capital jobs or
work orders created under ER 3007 are documented and tracked in Maximo.
Each new year, Gas Programs and the Isolated Steel team distribute the approved
capital spend to each of the local construction districts to complete replacement
projects in their respective areas. As these replacement projects are completed the
costs are reported back through Gas Programs each month. This information is used
to forecast current and expected remaining program spend for the year. These
results are reported back to accounting and the Capital Planning Group through the
Manager of Gas Engineering. This monthly reporting is used to identify whether
budget targets are met and to track overall completion levels in each area. Changes
to the business case or any funds returns/requests are also submitted through Gas
Engineering. All these groups report to the Director of Natural Gas.
Business Case Justification Narrative Template Version: February 2023 Page 14 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 320 of 535

DocuSign Envelope ID:33DE473C-7232-491E-811F-32AA475F77137
Gas Isolated Steel Replacement Program, ER 3007
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Isolated Steel Replacement
Program and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.
LY;
5'g a by:
Signature: WW Date:May-03-2024 1 9:24 AM PDT
TF F7LZSB3
Print Name: Jeff Webb
Title: Mgr Gas Engineering
Role: Business Case Owner
Signature: EL60, bbs Date:May-03-2024 1 9:39 AM PDT
Print Name: Alicia Gibbs
Title: Director of Natural Gas
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 15 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 321 of 535

DocuSign Envelope ID:39C1 1A1 8-5DEC-41A3-AC8E-27F1 B65FF2D3
Non-Revenue Program, ER 3005
EXECUTIVE SUMMARY
The work completed under this Business Case is typically unscheduled and is initiated
by either customers or Avista maintenance crews. Gas Engineering establishes the
overall budget based on historical spend patterns and reports monthly updates to the
Capital Planning Group based on feedback from the Local Districts. Gas Engineering is
responsible for projects under ER 3005 that require substantial design efforts such as
farm tap retirements, highway or river crossings, and replacing steel pipelines with
plastic pipe, but the local Districts manage the work.
The work in this annual program is mostly reactionary, unscheduled work and is difficult
to predict aside from using historical trends. The following situations are typical triggers
for work in the program: shallow facilities found by excavation (the excavation may or
may not be related to gas construction), relocation of facilities as requested by others
(except for road and highway relocations), leak repairs on mains or services, farm tap
elimination, and overbuilds. Gas Overbuilds (ER 3006) are now part of this Business
Case starting in 2024. The previous Business Case supporting overbuilds is ending,
since all known overbuilds in Oregon have been remediated with the exception of the
projects in the Medford District. Unforeseen overbuild projects will likely only come up
occasionally, which is why this category of work is being added to this Business Case.
Customer related benefits include reduced operations and maintenance (O&M) costs
and improved safety and reliability. Ensuring facilities are installed at the proper depth
and in locations where maintenance can be performed improves safety for customers
and company personnel. Leak rates are reduced when new plastic pipe is installed,
versus leaving the older steel pipe in-place. When reducing leak rates, it also reduces
unscheduled outages due to performing leak repairs and therefore raises customer
satisfaction. The business needs and solutions identified in this Business Case impact
gas customers across all of Avista's service territories.
Business Case Justification Narrative Template Version: February 2023 Page 1 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 322 of 535

DocuSign Envelope ID:39C1 1A1 8-5DEC-41A3-AC8E-27F1 B65FF2D3
Non-Revenue Program, ER 3005
VERSION HISTORY
Version Author Description Date
1.0 Jeff Webb Initial draft of original business case 311612017
1.1 Jeff Webb Updates to initial draft 4/05/2017
2.0 Jeff Webb Revised for Oregon 2020 GRC filing 211712020
3.0 Jeff Webb Updated to the refreshed 2022 Business Case Template 513112022
3.1 Shontelle McGrath Updated to the refreshed 2023 Business Case Template 8/14/2023
3.2 Jeff Webb Updated data for 2024 411512024
BCRT Team
BCRT Member Has been reviewed by BCRT and meets necessary requirements 4122124
GENERAL INFORMATION
YEAR PLANNED SPEND PLANNED TRANSFER TO
AMOUNT ($) PLANT ($)
2025 10,580,000 10,580,000
2026 10,897,400 10,897,400
2027 11,224,322 11,224,322
2028 11,561,052 11,561,052
2029 11,907,883 11,907,883
Project Life Span Ongoing
Requesting Organization/Department B51 /Gas Engineering
Business Case Owner I Sponsor Jeff Webb I Alicia Gibbs
Sponsor Organization/Department B51 /Gas Engineering
Phase Execution
Category Program
Driver Failed Plant& Operations
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
Business Case Justification Narrative Template Version: February 2023 Page 2 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 323 of 535

DocuSign Envelope ID:39C1 1A1 8-5DEC-41A3-AC8E-27F1 B65FF2D3
Non-Revenue Program, ER 3005
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
The work in this annual program is mostly reactionary, unscheduled work and is
therefore difficult to predict aside from using historical trends. The following
situations are typical triggers for such work: shallow facilities found by excavation
(the excavation may or may not be related to gas construction), relocation of
facilities as requested by others (except for road and highway relocations), leak
repairs on mains or services, remediation of cathodic protection (CP) issues, farm
tap elimination, and overbuilds. Each of these work types have different concerns
that are being addressed and are further described below. Customer related
benefits include reduced operations and maintenance (O&M) costs and improved
safety and reliability from having facilities at the proper depth and from reduced
leak rates of new plastic pipe versus older steel. The business needs and potential
solutions identified in this Business Case impact gas customers across all of
Avista's service territory.
When shallow facilities are discovered, an appropriate response to the situation is
determined by Local District Management. A shallow gas facility is defined as not
buried to the proper depth (having less cover and protection than is required by
Federal Rules). If the response to the situation is capital in nature, then the repair
is funded from this program. These types of projects allow Avista to remain in
compliance and operate the gas facilities in a safe and reliable manner. 15% of the
dig-in damages on Avista's gas system are on pipes that are less than 18" deep.
If requested by others (typically customers) to relocate facilities, Avista is bound by
state tariffs to do so at the customer's expense. Under certain circumstances,
Avista may choose these opportunities to perform additional work beyond the
immediate request to improve or update the gas system. Local District
Management and field personnel will evaluate the circumstances and make an
appropriate decision based on a holistic view of the situation. Guidance to help
evaluate the scenario is established in the Company Gas Standards Manual. An
example might be to replace an entire existing steel service with modern plastic
material instead of just replacing a section of the steel service that conflicts with a
customer's home improvement project. This would eliminate the possibility of
future deficiencies with the cathodic protection system on the steel pipes and
reduce future maintenance related to that steel service. The charges for this
additional work are put against this program.
When leaks are found on the gas system, it is sometime advantageous to replace
a section of main or service as opposed to repairing the leak with a temporary leak
clamp. The Local District considers the long term impacts when possible, not just
addressing the immediate concern when determining the right thing to do in each
of these situations. This type of betterment falls under this program.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 324 of 535

DocuSign Envelope ID:39C1 1A1 8-5DEC-41A3-AC8E-27F1 B65FF2D3
Non-Revenue Program, ER 3005
If a section of steel main is found to be isolated electrically from the CP system, a
CP Technician will evaluate the situation and give directions to the district to fix. If
the solution is a capital main replacement, it will fall under this program. Isolated
steel services fall under ER 3007.
A single service farm tap (SSFT) installed on a high pressure main is a common
way to provide gas service to a small number of customers. The alternative is to
install distribution main from an adjacent distribution system to serve the customer
which may be cost prohibitive at the time. Many of these farm taps are reaching
the end of their service life or need to be replaced for maintenance reasons. In
areas of high concentrations of farm taps that have maintenance concerns, it is
sometimes advantageous to rebuild one of them as a traditional regulator station
(pressure reduction station), install distribution main to the other services from the
adjacent farm taps, and then retire the other farm taps. This reduces O&M by
having fewer stations to maintain and increases safety by having fewer above
grade facilities that are exposed to potential vehicular damage.
Overbuild conditions normally occur when a structure is placed or constructed over
an existing gas pipe. The close proximity of these structures makes gas system
maintenance and inspection difficult, can be against state and federal code, and
can be a potential safety hazard for the occupants. Except for the Medford District,
starting in 2024 Overbuild remediation work was transitioned to this Business
Case. This was done because all known Overbuild projects had been completed
and any future projects in the other districts, should they be discovered, will likely
be minor in scope. The known Overbuild remediation work in the Medford District
will continue under the Business Case associated with ER3006.
Figure 1 shows how the budget is typically spread across the different project
types discussed above.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 325 of 535

DocuSign Envelope ID: 39C11A18-5DEC-41A3-AC8E-27F1B65FF2D3
Non-Revenue Program, ER 3005
Shallow Leak Repair
Facilities Isolated Mains
Other (CP)
Customer
Requested
Farm Tap
Elimination
Services, Misc
Mains, Misc
Figure 1. ER 3005 Spend by Project Type
1.2 Discuss the major drivers of the business case.
Due to most of this work being unscheduled replacement, the major driver is
Failed Plant & Operations. The percent of Customer Requested work is small
compared to the other work in this program.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
Each different type of problem addressed under this Business Case mitigates
different risks.
Shallow facilities — Lowering gas mains and services is not required by Federal
Rules, but it is prudent to ensure the gas pipes are buried to a safe depth. It
reduces the risks of damage caused by excavation over and around the gas
facilities. This is critical because damage from excavation is the highest risk to gas
facilities. Excavators are expecting gas pipes to be at the depths they are originally
installed at. When they are shallow because of grade changes that have been
caused by others since installation, there is an increased risk of damage and
threat to public safety.
If not approved, Avista would experience higher instances of pipe damages and
associated gas leaks. As noted above, approximately 15% of dig-in damages
occur when the gas pipes are less than 18" deep.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 326 of 535

DocuSign Envelope ID:39C1 1A1 8-5DEC-41A3-AC8E-27F1 B65FF2D3
Non-Revenue Program, ER 3005
Requested bV others & leak repair— Betterment of the gas system when
opportunities arise is the prudent way to operate a gas distribution system.
Mobilizing crews and equipment to a site often covers the bulk of the costs for
small projects, so making the most of their time once on-site is a practical way to
operate. Betterments as described above are driven by Company Standards and
best practices.
If not approved, Avista would miss the opportunity to better the system while crews
are already on-site doing work. This is shortsighted because we increase the
chances of having to be back at the site to remedy other maintenance items later
that could have been taken care of the first time we were there. The decision to
simply repair the leak or perform the customer requested work (quickest and
easiest thing to do) eliminates the opportunity to improve the system while already
onsite to do work and increases the chances of having to be back at the site later
to fix another leak or maintenance concern. If leaks are not repaired, the release of
greenhouse gases can negatively impact the environment and the leaks must be
monitored and re-evaluated on a periodic schedule to ensure they are not
becoming a greater hazard to the public.
Isolated mains (CP) — Electrically isolated portions of steel main will be replaced
as required to meet the requirements of Federal code 49 CFR 192.455 & 192.457.
This is a safety related requirement as a steel pipe will corrode if it does not have
sufficient Cathodic Protection on it.
If not approved, Avista will be at risk of fines for being out of compliance and the
steel piping system will not be safe for the employees and customers.
Farm tap elimination —When there are many farm taps located near each other
and when those stations have reason to be rebuilt, then it is wise to rebuild just
one of them and install distribution main to the other stations to provide a new
source of gas. This allows the adjacent (old) farm taps to be retired, reducing O&M
and improving public safety. Triggers for rebuilding a farm tap may include:
replacement of inadequate or obsolete equipment that is no longer supported,
poor location of station (safety concerns), replacing leaking threaded connections
with welded connections, inability to perform proper maintenance, and capacity
constraints. Customers benefit from these types of projects by having a safer, well
maintained distribution system. Also, this is a prudent way to manage resources
because many deficiencies at stations can be remedied under just one project. If
Avista is not allowed to optimize the gas distribution system by reducing the
number of farm taps that are maintenance intensive, then eventually more staff will
be required to perform this federally mandated maintenance work. On average,
one field technician can maintain only four of these stations in an eight-hour day.
Additionally, farm taps are normally located between the driving lane and the
property line, are low profile, and are sometimes difficult for the public to see. This
puts them at risk of vehicle damage, so having fewer of them on the system helps
to improve safety.
Overbuilds — Overbuilt gas pipes pose a safety risk for occupants in the area.
Leaking gas can accumulate under mobile homes and storage sheds. If the
Business Case Justification Narrative Template Version: February 2023 Page 6 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 327 of 535

DocuSign Envelope ID:39C1 1A1 8-5DEC-41A3-AC8E-27F1 B65FF2D3
Non-Revenue Program, ER 3005
overbuilt pipe is not relocated, Avista could also be at risk of fines due to being in
violation of state or federal codes.
1.4 Discuss how the proposed investment, whether project or program,
aligns with the strategic vision, goals, objectives and mission statement
of the organization. See link.
Avista Strateizic Goals
This program aligns with Avista's values of being Trustworthy and Innovative.
Each project completed under this program addresses a customer or safety
concern while simultaneously bettering the gas system. Completing these types of
projects shows that Avista makes wise, long-term decisions and takes steps to
optimize the gas system when the opportunities arise. We prioritize customers
through this work because it results in a safer, more reliable gas system. In
addition, by completing customer requested work, we let customers know that their
interests are important to us.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 328 of 535

DocuSign Envelope ID:39C1 1A1 8-5DEC-41A3-AC8E-27F1 B65FF2D3
Non-Revenue Program, ER 3005
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
The work completed under this Business Case is reactionary. Projects are
discovered throughout the year and resolved promptly thereafter. Most of this work
is managed at the local district level and Gas Engineering is not involved with the
scope and schedule of the individual projects. The budget for this Business Case
is based on historical spend. The graph below shows the annual spend for the last
five years.
ER 3005 Gas Non-Revenue
$14,000,000
$12,000,000
$10,000,000
$8,000,000
$6,000,000
$4,000,000 —
$2,000,000 —
$-
1 2 3 4 5 6 7 8 9 10 11 12
—2019 2020 2021 2022 2023
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative(e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Each project and solution are unique. Below are common solutions to each
type of project.
' Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 8 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 329 of 535

DocuSign Envelope ID:39C1 1A1 8-5DEC-41A3-AC8E-27F1 B65FF2D3
Non-Revenue Program, ER 3005
Shallow Facilities: For gas facilities that are discovered to be shallow, the
solution is to lower the facilities. This is typically achieved by either lowering
the facility in-place or installing new facilities at an appropriate depth and
abandoning the shallow facilities. This ensures adequate protection of gas
facilities to reduce the risk of excavation damages. If lowering existing facilities
chosen over installing new, this would be an O&M expense and not fall under
this Business Case.
Requested bV Others & Leak Repair: When customer requested work and leak
repairs come in, the request is reviewed, and the local gas system is looked at
to see if there are any recommended improvements. If there are potential
improvements, the Local District Manager uses their judgment, the Company
Standards, and best practices to develop an appropriate resolution.
Oftentimes, improving the system by installing new gas facilities is a better
option than simply repairing or relocating a small section of pipe. This
improves the safety of the gas system and reduces the chances of returning to
the same location to address additional safety or maintenance concerns in the
future.
Isolated Mains (CP): When electrically isolated portions of main are
discovered, the solution is to install a method of cathodic protection (CP) to
ensure the pipe is protected. The method of CP remediation depends on
where the isolated main is located and is determined by the CP Technician.
Ensuring steel pipe is properly protected from corrosion is required by Federal
Code. By addressing isolated mains, we reduce the risk of steel pipe corroding
and leaking. In addition, not addressing isolated mains would result in Avista
being subject to fines for not meeting Federal Code requirements.
Farm tap elimination: When there are several farm tap stations located near
each other and one or more are due to be rebuilt, the most beneficial solution
is to rebuild one station and install distribution main to the other station
locations. This allows the other farm tap stations to be retired, reducing future
O&M and improving public safety. Many deficiencies can be addressed
through one project using this approach.
Overbuilds: When pipe is discovered under a mobile home, building, carport,
or other structure that may entrap gas, the solution is to relocate all facilities
that are overbuilt and abandon the overbuilt facilities (assuming the structure
causing the condition can't be moved). This reduces the safety risk of gas
entrapment and ensures gas facilities are installed in compliance with federal
codes and best practices.
Business Case Justification Narrative Template Version: February 2023 Page 9 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 330 of 535

DocuSign Envelope ID:39C1 1A1 8-5DEC-41A3-AC8E-27F1 B65FF2D3
Non-Revenue Program, ER 3005
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
Each type of project completed under this program reduces risk, and some also
reduce future O&M costs.
Shallow facilities: The risk of damage to gas facilities is higher for shallow
facilities. Excavators expect gas facilities to be at the current, standard burial
depths. This is not always the case for facilities in locations where grade
changes have occurred since installation. External damage by excavation is one
of the highest risks to gas facilities. By lowering shallow facilities when they are
discovered, the risk of damage by excavators is reduced. This also reduces the
potential for greenhouse gas emission related to gas leaks associated with dig-
in damage.
Requested by others & leak repair: By completing system enhancements when
company crews are already onsite completing work requested by others, the risk
of customer dissatisfaction is reduced. If only the bare minimum work were to be
completed, there is a risk of having to return to the same site later for additional
maintenance. This is also a more cost-effective way to operate, as the cost of
mobilizing a crew can be most of the project cost. Similarly, with leak repairs, it
is likely that if the leak is simply patched that a crew will need to visit the same
location in the future for additional maintenance. By improving the system in
response to a leak, the risk of having to revisit the same site in the future is
reduced. Again, this also reduces future O&M costs and the potential for
greenhouse gas emission related to gas leaks.
Isolated Main (CP): By addressing isolated steel main, we reduce the risk of
pipe corroding. In addition, ensuring steel pipe is protected is mandated by
federal code. Avista would be at risk of federal fines if isolated mains were not
addressed.
Farm tap elimination: There are different reasons a farm tap may be due for
replacement. These include: inadequate or obsolete equipment that is no longer
supported, poor location of station (safety concerns), replacing leaking threaded
connections with welded connections, inability to perform proper maintenance,
and capacity constraints. By rebuilding and/or eliminating station locations that
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 10 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 331 of 535

DocuSign Envelope ID:39C1 1A1 8-5DEC-41A3-AC8E-27F1 B65FF2D3
Non-Revenue Program, ER 3005
face these concerns, several types of risk can be reduced. If a station has
inadequate or obsolete equipment and it were to fail, there is a risk of an
unplanned customer outage due to the station failure. There are a few risks
associated with stations in poor locations, many of these sites are located just
off the roadway, between the traffic lane and property line. For these stations,
there is a risk of vehicular damage to the station, as well as a safety risk to
Avista personnel while performing required maintenance. If proper maintenance
cannot be performed, Avista is at risk of fines for not being compliant with
mandated maintenance requirements. If a station has capacity constraints, there
is a risk of unplanned customer outages if a station cannot support all
downstream customer loads. In addition, by eliminating farm tap locations,
future O&M costs associated with required station maintenance can be reduced.
Overbuilds: For gas facilities that are overbuilt, there is a safety risk. Gas can
accumulate under structures, which poses a risk to public safety.
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $0 $0 $0 $0 $0
0&M $0 $0 $0 $0 $0
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $0 $0 $0 $0 $0
0&M Temporary Leak Repair $2,287,000 $2,287,000 $2,287,000 $2,287,000 $2,287,000
If the capital funding under this Business Case was not available, a portion of
Avista labor and transportation would likely be charged to expense work. 32% of
the annual spend is associated with labor and transportation. The O&M cost
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 11 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 332 of 535

DocuSign Envelope ID:39C1 1A1 8-5DEC-41A3-AC8E-27F1 B65FF2D3
Non-Revenue Program, ER 3005
offsets were calculated assuming those charges would be split 50/50 between
capital and expense. This is estimated to be $2,287,000 per year.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those
additional risks to Avista that may occur if an alternative is selected.
Alternative 1:
For shallow facilities, the only alternative is to leave them in place. This is not
recommended. The risk of excavation damage is higher for shallow facilities,
and excavation damage remains one of the highest risks to gas facilities.
Alternative 2:
For work requested by others & leak repair, the alternative is to do the
absolute minimum and only address the gas facilities that are either in conflict
or leaking. This is not recommended because it is not a prudent way to
operate a gas system. If system enhancements are not completed while crews
are already mobilized and onsite, it is likely that crews will have to return to the
same site to perform additional maintenance in the future on these aging
facilities.
Alternative 3:
There is no alternative to addressing isolated steel main. This work is
mandated by federal code and would result in regulatory fines if not
completed. Regulatory fines can be up to $225,134 per day per violation, up to
a $2,251,334 total.
Alternative 4:
The only alternative to farm tap eliminations is to rebuild each farm tap in place
as the need arises. This alternative is not advised. Farm tap stations require
regular O&M maintenance. If Avista is not allowed to optimize the gas system
by strategically eliminating farm taps where it makes sense, additional
personnel may need to be hired to perform the federally mandated
maintenance.
Business Case Justification Narrative Template Version: February 2023 Page 12 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 333 of 535

DocuSign Envelope ID: 39C11A18-5DEC-41A3-AC8E-27F1B65FF2D3
Non-Revenue Program, ER 3005
Alternative 5:
There is no alternative to replacing known overbuilds. Leaving known
overbuilds in place would be a violation of code and standard practices.
Regulatory fines can be up to $225,134 per day per violation, up to a
$2,251,334 total.
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how
will success be measured).
Each individual project under the different project types supported by this
Business Case has a Maximo work order. Success can be measured by
tracking all the completed work orders. Here are additional metrics for a few of
the project types:
Shallow facilities: When damages occur on Avista's gas facilities, the cause for
damage is documented. As shallow facilities are discovered and fixed, less
damages should be correlated with improper depth of cover.
Requested bV others & leak repair: Customer satisfaction, or lack of complaints,
due to not having multiple visits to the same address would indicate we are
managing the system properly by bettering it when we have the opportunity.
Lower leak rates over time due to newer gas facilities can also be tracked.
Farm tap elimination: As farm tap stations are eliminated, success can be
measured through lower O&M costs associated with station maintenance.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
The work in this program is comprised of small projects that are typically
completed within the same month they are started. As such, the funds transfer to
plant each month throughout the year. The graph in section 1.5 shows a
relatively steady spend throughout the year.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of
the business case, and how such oversight will occur.
Gas Engineering monitors the spend and reports back to the District Managers
monthly. The oversight occurs through email and Gas Engineering will prepare
the appropriate documents for the Director of Natural Gas to present at the CPG
should changes be needed throughout the year.
Business Case Justification Narrative Template Version: February 2023 Page 13 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 334 of 535

DocuSign Envelope ID:39C1 1A1 8-5DEC-41A3-AC8E-27F1 B65FF2D3
Non-Revenue Program, ER 3005
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Non-Revenue Program, ER 3005
and agree with the approach it presents. Significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
E
Sg dby:
Signature: ew add Date: May}ffltfM28 12:25 PM PDT
E1 ffRE458JdEf...
Print Name: Jeff Webb
Title: Mgr Gas Engineering
Role: Business Case Owner
Signature: FD­Signedby:
(aaa GiW Date: May-04-2024 1 11:z8 AM PDT
c9B4Y8559d9E989...
Print Name: Alicia Gibbs
Title: Director of Natural Gas
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 14 of 14
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 335 of 535

DocuSign Envelope ID: D311AD81-9D31-47AE-AFA4-AD3DB44CB764
Gas PMC Program, ER 3055
EXECUTIVE SUMMARY
Avista is required by state commission rules and tariffs in WA, ID, and OR to annually test gas
meters for accuracy and ensure proper metering performance. Execution of this program on an
annual basis ensures the continuation of reliable and accurate gas measurement for our
customers and compliance with the applicable state tariffs. Customers benefit from this
program because it ensures that they are not overpaying for gas consumption if their meter's
accuracy is out of specification. In some situations, a customers' meter could measure higher
energy usage than the customer is actually using, resulting in the customers' bill being too high.
Avista also benefits from this program because it helps identify slow meter families, which are
meters that are registering under 100% accuracy. In these situations, the meter is
undermeasuring the energy that is being used by the customer; therefore, the customer is being
billed for less energy than they are actually using.
The Planned Meter Change-out (PMC) Program uses a statistical sampling methodology based
on ANSI Z1.9 "Sampling Procedures and Tables for Inspection by Variables for Percent
Nonconforming". Sample sizes and acceptance criteria are defined in the ANSI standard. The
annual test results of gas meters that have been removed from the field are analyzed and a
determination of the accuracy of each meter family is made. If the analytics determine a meter
family, defined as a manufacturer year and model/size, is no longer metering accurately enough
to meet the tariff, then that entire meter family will be replaced. Conversely, if the analytics
determine a meter family is testing well, the sample size can be reduced. The sample size is
defined as the number of meters in that family required to be tested. These analytics help
control costs and remove meters quickly that are not performing well.
This testing and replacement approach controls the cost of the program to provide the best
value for customers compared to other meter replacement strategies, for example replacing
meters after a prescribed number of years. Statistical analysis has proven that older meter
families can retain their accuracy and perform like a new meter; therefore, there is no benefit to
customers to replace older meters that are performing within the accuracy specifications.
The program also provides Avista with the statistical data necessary to identify drifts in meter
accuracy. If a meter family shows a consistent drift in mean accuracy, the meter reading may
be corrected by adjusting the entire family's Installation Constant value in the Meter Data
Management system, rather than removing the meters from service. This approach allows
Avista to adjust and leave meters in service that would have otherwise needed to be replaced,
while still accurately billing customers.
This program includes only the labor and minor materials associated with the PMC Program.
Major materials (meters, pressure regulators, and Encoder Receiver Transmitter (ERT)) will be
charged to the appropriate Gas Growth Programs. The annual cost for the program varies
depending on the results of the previous year's statistical analysis. Yearly budgets are projected
using a calculation based on the estimated number of failed family meters, PMC's, and
overpulls for the year, as well as the average cost per meter based on the previous year's data.
Avista would not be in compliance with state commission rules and tariffs in WA, ID, and OR if
this program is not completed annually. This would put Avista at risk of receiving a public
violation, which would result in the erosion of public trust and potential fines. State fines are not
prescribed, and it is up to each state to determine the fine amount.
Business Case Justification Narrative Template Version: February 2023 Page 1 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 336 of 535

DocuSign Envelope ID: D311AD81-9D31-47AE-AFA4-AD3DB44CB764
Gas PMC Program, ER 3055
VERSION HISTORY
Version Author Description Date
1.0 Jeff Webb Initial draft of original business case 311612017
1.1 Jeff Webb 410712017
2.0 Dave Smith Revised for 2020 Oregon GRC Filing 211712020
2.1 Dave Smith Updated to the refreshed 2020 Business Case Template 612412020
2.2 Dave Smith Updated to the refreshed 2022 Business Case Template 5/05/2022
2.3 Shontelle Wilson Updated to the refreshed 2023 Business Case Template 3/20/2023
2.4 Dave Smith Updated per BCRT Feedback 3/29/2023
2.5 Doug Brummett Updated 2.6 411612024
BCRT Team
BCRT Member Has been reviewed by BCRT and meets necessary requirements 412512024
GENERAL INFORMATION
YEAR PLANNED SPEND PLANNED TRANSFER TO
AMOUNT ($) PLANT ($)
2025 4,300,000 4,300,000
2026 3,600,000 3,600,000
2027 3,700,000 2,600,000
2028 3,800,000 3,800,000
2029 3,800,000 3,800,000
Project Life Span Ongoing
Requesting Organization/Department B51 —Gas Engineering
Business Case Owner I Sponsor Doug Brummett/Jeff Webb I Alicia Gibbs
Sponsor Organization/Department B51 —Gas Engineering
Phase Execution
Category Mandatory
Driver Mandatory& Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
Business Case Justification Narrative Template Version: February 2023 Page 2 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 337 of 535

DocuSign Envelope ID: D311AD81-9D31-47AE-AFA4-AD3DB44CB764
Gas PMC Program, ER 3055
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
Avista is required by state commission rules and tariffs in WA, ID, and OR to test meters
for accuracy and ensure proper metering performance. Execution of this program on an
annual basis ensures the continuation of reliable gas measurement and compliance with
the applicable tariffs. If Avista does not complete this annual program, we will be out of
compliance with state rules and tariffs which could result in a violation (which is made
public) and erosion of public trust.
1.2 Discuss the major drivers of the business case.
This program is a mandatory requirement to be in compliance with state commission rules
and tariffs in WA, ID, and OR.
The following state rules regulate Avista's PMC Program:
Oregon:
o OAC 860-023-0015 "Testing Gas and Electric Meters"
o Tariff Rule #18
Idaho:
o IDAPA 31.31.01.151 through .157 "Standards for Service"
Washington:
o WAC Chapter 480-90-333 through -348 "Gas companies—Operations"
o Tariff Rule #170
Being out of compliance with these rules and tariffs could result in a violation and potential
fines. State fines are not prescribed and it is up to each state to determine the fine
amount.
The customers benefit from this program because it assures that natural gas consumption
is measured accurately in all jurisdictions. Accurate measurement ensures accurate
customer billing.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
Avista would not be in compliance with state commission rules and tariffs in WA, ID, and
OR if this program is not completed annually. Also, the accuracy of measurement of our
customers' natural gas usage could not be assured. See below for breakdown of these
risks:
Business Case Justification Narrative Template Version: February 2023 Page 3 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 338 of 535

DocuSign Envelope ID: D311AD81-9D31-47AE-AFA4-AD3DB44CB764
Gas PMC Program, ER 3055
Risk Probability Definitions:
Risk event expected to occur
High(H) Risk event more likely to occur than not
Probable(P) Risk event may or may not occur
Low(L) Risk event less likely to occur than not
Very Low(VL)_ Risk event not expected to occur
Risk Avoidance Over Time and the Cost of Doing Nothing:
Risk Over Time(years)
# Risk 1 tH
5 10 15+ Cost Estimate
1 Regulatory Fines* H $257,664 per day per violation(Max)
$2,576,627 Total(Max)
2 Pipeline Leak Not Applicable Not Applicable
3 Pipeline Failure&Outage Not Applicable Not Applicable
4 Negative Reputation H H Erosion of PUC and Public trust
5 Employee&Public Safety Not Applicable Not Applicable
*State fines are not prescribed and it is up to each state to determine the fine amount. Federal
regulatory fines present a daily and overall maximum value per violation in accordance with 49
CFR Part 190.223. However, these values are not necessarily an accurate representation of how
much Avista would be fined for any specific violation. The actual amount is likely to be much lower
since Avista has an ongoing reputation and history of investing in programs related to safety and
non-compliance issues. However, it is a bookend reminder from which to characterize the
regulatory risk associated with chronic and/or egregious non-compliance, especially in the event of
a pipeline safety incident(i.e., failure). Therefore, Avista must continue to demonstrate an ongoing
commitment to compliance and pipeline safety to ensure favorable future outcomes with respect to
regulatory penalties (actual penalty amount is at the discretion of the state or federal agency).
1.4 Discuss how the proposed investment, whether project or program,
aligns with the strategic vision, goals, objectives and mission statement
of the organization. See link.
Avista Strategic Goals
This program aligns with Avista's Strategic Goals of Reliability and Trustworthiness for our
customers. When meter accuracy is outside of the 2% tolerance customers may be
overcharged. This would cause customer dissatisfaction and could hurt the reputation of
Avista. "Our word is reliable; we do what is right." The PMC Program aligns with Avista's
focus on giving customers a high quality of service.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 339 of 535

DocuSign Envelope ID: D311AD81-9D31-47AE-AFA4-AD3DB44CB764
Gas PMC Program, ER 3055
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
• Gas PMC Program Standard Operating Procedure
o This procedure covers the methodology, testing requirements, and annual
reporting guidelines for Avista's gas meter measurement performance
testing program (PMC Program) for new and in-service meters.
• ANZI Z1.9 "Sampling Procedures and Tables for Inspection by Variables for
Percent Nonconforming"
o This is the methodology for sample sizes and analysis for the meter testing
program.
• The following state rules and tariffs require Avista to administer a meter sampling
program:
Oregon:
o OAC 860-023-0015 "Testing Gas and Electric Meters"
o Tariff Rule #18
Idaho:
o IDAPA 31.31.01.151 through .157 "Standards for Service"
Washington:
o WAC Chapter 480-90-333 through -348 "Gas companies—Operations"
o Tariff Rule #170
These documents are saved on the Avista network drive c01 d44 and can be made
available upon request.
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative(e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The program is completed between January and December of each year. Gas
Engineering, Gas Operations, Gas Meter Shop, and Technical Services work together to
administer the PMC program. Gas Operations and the Gas Meter Shop personnel
remove the meters from the customer's premise and install new ones. If a large meter
family fails, Avista may hire a contractor to assist in the removal of the meters. The Gas
Meter Shop completes physical calibration tests on the meters and the Technical Services
group then analyzes the test results at the end of the year to determine the status of each
family of gas meters. The results of this analysis will define the meter removal and testing
requirements for the following year. Gas Engineering develops an annual report which is
made available to the state commissions upon request.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 340 of 535

DocuSign Envelope ID: D311AD81-9D31-47AE-AFA4-AD3DB44CB764
Gas PMC Program, ER 3055
The program also provides Avista with the statistical data necessary to identify drifts in
meter accuracy. If a meter family shows a consistent drift in mean accuracy, the meter
reading may be corrected by adjusting the entire family's Installation Constant value in the
Meter Data Management system rather than removing the meters from service.
Execution of this program on an annual basis ensures the continuation of reliable gas
measurement and compliance with the applicable tariffs, which is state mandatory in WA,
ID, and OR. The recommended solution is to complete this mandatory programmatic
work. Completion of this program will keep Avista in compliance with state rules and
tariffs and assure that our customers' natural gas use is measured accurately. Partial
completion of this program will result in Avista being out of compliance with state rules
and tariffs.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
The PMC Program uses a statistical sampling methodology based on ANSI Z1.9
"Sampling Procedures and Tables for Inspection by Variables for Percent
Nonconforming". Sample sizes and acceptance criteria are defined in the ANSI standard.
The annual test results of gas meters that have been removed from the field are analyzed
and a determination of the accuracy of each meter family is made. If the analytics
determine a meter family (defined as a manufacturer year and model/size) is no longer
metering accurately enough to meet the tariff, then that entire meter family will be
replaced. Conversely, if the analytics determine a meter family is testing within tolerance
(close to 100% accurate), the sample size (number of meters in that family required to be
tested) can be reduced. These analytics help control costs and remove meters quickly
that are not performing well.
The meter accuracy testing results collected annually from the program are documented
and analyzed in an Excel spreadsheet. This spreadsheet performs calculations based on
ANSI Z1.9 to determine the following year's sampling requirements and identify which
meter families do not meet the accuracy standards and must be removed. This analysis
also checks that the Installation Constant value assigned to meters that have a consistent
drift in mean accuracy are measuring within the specified accuracy range, and the
Installation Constant value adjusted as necessary. All results are saved and then
presented on the annual Gas Meter Measurement Performance Report. This can be made
available upon request.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 341 of 535

DocuSign Envelope ID: D311AD81-9D31-47AE-AFA4-AD3DB44CB764
Gas PMC Program, ER 3055
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $0 $0 $0 $0 $0
0&M $0 $0 $0 $0 $0
No direct offsets could be identified for this program.
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital Avoid Meter Replacements by $5.2MM $5.3MM $5.5MM $0* $0*
Adjusting the Installation
Constant
0&M $0 $0 $0 $0 $0
*Per the PMC Program Standard Operating Procedure failed family replacement
timelines, 25% of the total 87,000 meters would need to be replaced each year starting
in 2024 and ending in 2027.
Completing the annual PMC Program provides indirect savings. The program provides
Avista with the statistical data necessary to identify drifts in meter accuracy. If a meter
family shows a consistent drift in mean accuracy, the meter reading may be corrected by
adjusting the entire family's Installation Constant value in the Meter Data Management
system rather than removing the meters from service. This approach has allowed Avista
to adjust and leave approximately 86,000 meters in service that would have otherwise
needed to be replaced. See the file titled ER 3055 PMC Program Offset Calculations
2023.xlsx showing the calculations for the indirect savings.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those
additional risks to Avista that may occur if an alternative is selected.
Alternative 1:
The only alternatives are to either partially fund this program or to not fund it at all. If this
program was not completed fully, Avista would be out of compliance with state rules and
tariffs and could be exposed to fines from the various state utility commissions. There are
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 342 of 535

DocuSign Envelope ID: D311AD81-9D31-47AE-AFA4-AD3DB44CB764
Gas PMC Program, ER 3055
not prescribed fine ranges for state violations, and it is up to state staff to determine the
amount of any fines. Also, the accuracy of measurement of our customers' natural gas
usage could not be assured.
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how
will success be measured).
All the meters in the random sampling program will be identified by a "flag" in Avista's
Service Suite mobile application at the beginning of a calendar year. Meters shall be
chosen at random and in sufficient quantities to meet the guidelines for sampling as
detailed in the standard. Once the required number of meters in each family is removed
for testing the "flag" will be removed in Service Suite indicating that no more meters in that
family are required for testing.
Meters identified as a failed family meter will have a Maximo work order created to
remove them from service. These work orders are used to track progress throughout the
year.
There is a Gas PMC FF Meters dashboard available from the gas wiki site that will be
replacing the previous weekly Cognos report MR 130121 Gas PMC FF Meters Pulled and
Tested.xlsx. The dashboard contains the total number of failed families broken up by
district along with how many meters have been pulled and how many are remaining.
Additionally, there is a tab for the PMC meters that shows all the meter families and the
sampling requirement for that family. Lastly, the final tab tracks the meters that have been
pulled and tested and how many remain to be tested. This is broken up by meter family.
Below is a screen shot of the dashboard showing the representative content.
Failed Family °a�$01fP"AdO"1O
Meters Pulled By Office Due to 2024 Total Meters Pulled Due In 2024
e ❑
4
8wo
aao
F aaa
� mo
es�� o-s o'er ef; Pre"J°a6� .6-" xe ,"'e
Business Case Justification Narrative Template Version: February 2023 Page 8 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 343 of 535

DocuSign Envelope ID: D311AD81-9D31-47AE-AFA4-AD3DB44CB764
Gas PMC Program, ER 3055
�u�apa
Total Meters Pulled-Excluding Over Pulls sampling Group Assets sampeng Template peal IAelers Putteo Mele+s Rems-9
■Total Meters Pulled 59_1960 50 11 39
Remaining Meters 58_1%2 35 11 za
AC25o 19W ]5 9 M
gC25o 1985 ]5 6 29
AC350 1986 W 16 Js
AC250 198) 35 8 2)
Remaining Meters gQ50_l%8 W 111 32
2.335 Total Meters Pulled AC2W 1990 15 70 5
47% 2602 Total Over-Pulls- .2,440
53% AC2%-1991 IS 5/ t8
AC250 199a 100 39 61
AC250 1995 35 12 I3
AC25019% t00 W 3)
AC25o_2001 100 2) 13
AC250 2003 100 81 19
AC250 2004 n 2) B
Total Meters Pulled,Remaining Meters AC250_2012 1m 136
AC250 2013 10o so ao
Meters Pulled By Office Including Over-Pulls AC250 2011 100 28 n
®Meters Pulled by Office AC250 2015 75 11 61
AC250_2016 15 21 Ss
G 1,000 AC250_2017 5o 8 12
AC2502o1B too W 1)
600 1a
AC25o_2019 ]5 _ Tt
AC250 202o 15 21 5s
AC630_1998 20 ) 13
AC630 1999 15 3 12
AC630 00_20 25 1 24
A� e�� �0
�F,O�J OPP�4. �"GS P 6P ACAM2001 1s o is
Ac6w2002 15 o 15
PMC/FF Weekly Summary Meters Tested
Gas Meters tested by Meter Family.The Total Remaining shown includes all Failed Family meters due in 2024 and 2026
'•1na families will a�splay wnen at yeast 1 Meter rs Tested"
fptl CMIMue u
Total Meters Tested ■Total Meters Tested
s as. 3.151 ■Told Remaining
19%
..'sal
5.
zs
Acsu+oeo
nczso+ae] soAria u e n
Acao-+9ea -
Ac +oas ass Ar+ 35 3 a1.ss
ncno_�aes +asB -All. - -so - u, al 2o+s
ACYA+te) tea) AC250 35 9 M MA
ACISo+eat 1 AC259 5o tt l9 22%
ACM_+939 AC250 5o 17a61
Af13p_+aao +99a All. 11 s) ?t )t> ,-
AC25o_+.1 last AL250 )5 )5 al (rf
.cm.-,- +spz Aczso 3s 1
1 2z "1 Total Remaining
Ac2sa+sa] + Acxsp 100 ss as ssw 13.009
Aczso_+aaa 1 Aczw too m al 1" 81%
Aczso 1ws vas - 31 a 11 n._ Total Meters Tested.Total Remaining
eosa_swo Two All.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
This is an annual program that needs to be completed every year to maintain compliance
with WA, ID, and OR state commission rules and tariffs. The Gas Meters are purchased
under ER 1050.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight
of the business case, and how such oversight will occur.
Gas Engineering, Gas Operations, Gas Meter Shop, and Technical Services work
together to administer the PMC Program and ensure compliance with the various state
rules and tariffs related to gas meter testing. Gas Engineering is responsible for
developing the annual Gas Meter Measurement Performance Report which defines future
work under the program. Gas Engineering then determines the annual budget
requirements based on the number of meters that need to be removed to satisfy the
program requirements.
Business Case Justification Narrative Template Version: February 2023 Page 9 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-13-25-01
J. DiLuciano,Avista
Schedule 3,Page 344 of 535

DocuSign Envelope ID: D311AD81-9D31-47AE-AFA4-AD3DB44CB764
Gas PMC Program, ER 3055
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas PMC Program, ER 3055 and
agree with the approach it presents. Significant changes to this will be coordinated with
and approved by the undersigned or their designated representatives.
Doc S'g d by:
Signature: ;-z Date: Apr-30-2024 1 10:55 PM PDT
Print Name: Jeff Webb
Title: Mgr Gas Engineering
Role: Business Case Owner
Signature: F40-5
uux'G�Ws Date: May-01-2024 8:49 AM PDT
aesebssae.....
Print Name: Alicia Gibbs
Title: Director of Natural Gas
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 10 of 10
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 345 of 535

DocuSign Envelope ID:35775496-6BA9-40DE-892C-B2DB717DABCB
Gas Regulator Station Replacement Program, ER 3002
EXECUTIVE SUMMARY
This annual program will replace or upgrade existing, at-risk Gate Stations, Regulator
Stations, Single Service Farm Taps, and Industrial Meter Sets (collectively referred to
as "stations") located throughout Avista's gas territory in WA, ID, and OR that are at the
end of their service life and/or not meeting current Avista standards. Additionally, it will
address enhancements that will improve system operating performance (such as
increasing the capacity of stations to meet our growing system demands), enhance
public and employee safety, replace inadequate or antiquated equipment that is no
longer supported, and ensure the reliable operation of metering and regulating
equipment.
Proper functioning of these stations is required to ensure safe, reliable delivery of
natural gas to all Avista customers. All stations require maintenance per 49 CFR
192.739. If the equipment at the station is obsolete and replacement/maintenance parts
are no longer available, then proper maintenance cannot be completed. Incomplete
maintenance could cause Avista to be out of compliance. When Avista is out of
compliance, we are exposed to fines from multiple state utility commissions:
Washington, Idaho, and Oregon'.
Another common driver for these upgrade projects is public and employee safety. Many
stations that are upgraded are also moved to a safer location. For example, moved
further from the roadway where they are less likely to be hit by a vehicle and where
Avista employees can have a safe parking area to access the station for maintenance.
Many old stations do not have a parking space, forcing Avista employees to park on the
shoulder of the road to access the station. This puts the employee and the traveling
public at greater risk of an accident.
Avista's gas customers from all jurisdictions benefit from these types of projects by
having a safer, more reliable, and well-maintained distribution system. Performing these
upgrades is a prudent way to spend resources because many deficiencies at a station
can be remedied under just one project, and proactive replacements cost less than
reactive replacements.
There is already a backlog of stations needing replacement; therefore, this work is
needed now. The list of stations needing replacement continues to expand as stations
meet the end of their service life. Postponing this replacement program will cause the
list of stations needing replacement to outpace the number of stations remediated.
Annual cost to fund this program has historically been approximately $1,000,000. The
cost to rebuild a station varies greatly from project to project based on several factors,
some of which include the type of station, size of station components, location, and
State fines are not prescribed and it is up to each state to determine the fine amount. Federal regulatory fines
present a daily and overall maximum value per violation in accordance with 49 CFR Part 190.223.
Business Case Justification Narrative Template Version: February 2023 Page 1 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 346 of 535

DocuSign Envelope ID:35775496-6BA9-40DE-892C-B2DB717DABCB
Gas Regulator Station Replacement Program, ER 3002
crew resources (company crews or contractor crews). Below are estimated average
costs to rebuild each type of station based on historical projects:
Gate Station: $500,000
District Regulator Station: $100,000
Industrial Meter Set: $ 50,000
Single Service Farm Tap: $ 5,000
Proactive replacement of these stations is much more cost effective than reactive
replacement. A recent station replacement that was completed as an emergency
response to a station that was damaged by a vehicle cost approximately five times more
than a planned replacement project. In addition, proactive replacement is preferred due
to material availability. Long lead-times on materials necessary for these rebuild
projects may mean that if stations run to failure, we may not have the materials
necessary for replacement.
Updated stations are also typically easier to maintain than older designs; therefore,
future maintenance costs are reduced. On average, a new station takes about 1 hour
less to maintain than an obsolete station, which is a direct O&M savings. These O&M
savings compound each year as more stations are rebuilt. Over 40 years, the average
lifespan of a station, these O&M savings are estimated to be $3,250,000.
VERSION HISTORY
Version Author Description Date
1.0 Jeff Webb Initial draft of original business case 311712017
1.1 Jeff Webb 410712017
2.0 Jeff Webb Revised for 2020 Oregon GRC filing 211712020
2.1 Dave Smith Updated to the refreshed 2020 Business 612412020
Case Template
2.2 Dave Smith Updated to the refreshed 2022 Business 5/5/2022
Case Template
2.3 Shontelle Updated to the refreshed 2023 Business 3/9/2023
Wilson Case Template
2.4 Dave Smith Updated per BCRT Feedback 3/31/2023
2.5 Jarriq White Updated per BCRT Feedback 4/12/2024
Has been
BCRT reviewed by
BCRT Team BCRT and 4/3/2023 BCRT Team Has been reviewed by BCRT and meets 4/17/2024
Member meets Member necessary requirements
necessary
requirements
GENERAL INFORMATION
YEAR PLANNED SPEND PLANNED TRANSFER TO
AMOUNT ($) PLANT ($)
2025 1,110,000 1,110,000
Business Case Justification Narrative Template Version: February 2023 Page 2 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 347 of 535

DocuSign Envelope ID:35775496-6BA9-40DE-892C-B2DB717DABCB
Gas Regulator Station Replacement Program, ER 3002
2026 1,135,000 1,135,000
2027 1,170,000 1,170,000
2028 1,205,000 1,205,000
2029 1,240,000 1,240,000
Project Life Span Ongoing
Requesting Organization/Department B51 —Gas Engineering
Business Case Owner I Sponsor Jarriq White/Jeff Webb Alicia Gibbs
Sponsor Organization/Department B51 —Gas Engineering
Phase Execution
Category Program
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
Existing stations located throughout Avista's gas territory in WA, ID, and OR have
a finite service life. If they are not periodically replaced and updated, the stations
will no longer meet Avista's current design standards, the equipment will become
obsolete, and the stations may develop operational or safety issues that need to
be addressed to deliver safe and reliable gas service to customers.
Public and employee safety is another common driver for these upgrade projects.
Many stations that are upgraded are also moved to a safer location. For example,
moved further from the roadway where they are less likely to be hit by a vehicle
and where Avista employees can have a safe parking area to access the station
for maintenance. Many old stations do not have a parking space, this causes
Avista employees to park on the shoulder of the road to access the station for
maintenance. This puts the employee and the traveling public at greater risk of an
accident.
Gas Engineering maintains a Station Evaluation Spreadsheet that summarizes the
condition of each station. This spreadsheet is used to help identify which stations
are the highest risk and assists in prioritizing the work under this program. Below
is a partial screen shot example from that list.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 348 of 535

DocuSign Envelope ID:35775496-6BA9-40DE-892C-B2DB717DABCB
Gas Regulator Station Replacement Program, ER 3002
9latblsl-1 SW Asseasat kore -Sun- lecadon - Palm =Corrosl-_IM41dsPm VW- ThsN.WPRIR,-1 9"— -SessseU-Cosdlp.W-i H-Wd -Pipe SeW- Suppeos EldmW Posy-Psessu
232 2010 56 GS Goad N.- No Yes HP,Yes on IP Single Valve Isolation Blank To.Shon Nan. s.Non Adlust Malor Adequ
33 2011 55.5 OR CrecYing/FWYIng Mlswr Ho Yes on HP,Yes on IP Hard Short Requires ladder/platform None Not Needed None Adequ
13 1111 54.5 OR Cracking/Flaking Mlror No %s on NP.Yes en lP None Short Adequate None Not Needed None Blank
2T8 2020 5e OR Cracking/FNking None Blank %s on HP.Yes on IP Single Valve Holatlon Blank Adequate None Not Needed Mina Not Ad
28 2021 51.5 OR CracYing/Flaking Mlswr No No Hard Short Requires ladder/plef—None Not Needed None Ad—
36 2021 a9 OR —cking/Pls-,Mirror No No Hard Shon Requires Latlder/Platf—None Not Needed None Blank
33 3B?k `j8 MI fnekMe(FbNngMare No No Nard s4— iea5her! Nane nee,.e.e.e Nane --
33 1111 AT OR Cr,-,,/Flaklr None No No Hard Shon Adequate None Not Needed None Adequ
1T 1811 KS OR EeeMnfRMkinf Acinaa No Ws, keetlke! flsM RepuiwebddeNPMfara Nane NaeNeerkd None Adeaa
3d 202, s5 OR Cracking/P4klnf Mlmr No No Ha.d short Requires Ladder/PWf—None Not Needed None Adequ
13A3 1011 dd.5 SSFT 5509W IJertm Cracking/FlaYing Significant Blank ,eson HP.—..lP Soh Blank adequate None Not Needed None Adequ
26N05 2020 43 G5 Good None Blank Yes on HP,Yeson IP None Blank Too Shon None Blank None Not Ac
1.2 Discuss the major drivers of the business case.
This program's primary driver is asset condition. By proactively replacing obsolete
stations, we will continue to deliver safe and reliable gas service to customers. On
average, a typical station has a useful life of approximately 40 years2. This is
because when equipment is antiquated, parts are no longer readily available
causing station reliability to be diminished. Obsolete stations are often more
difficult and take longer to maintain, which increases O&M costs to the company.
On average, an obsolete station takes approximately 1 hour longer to maintain
than a new station. This additional 1 hour of labor is entirely O&M. See section
2.2 for O&M savings calculations.
Public and employee safety is another common driver for these upgrade projects.
Many stations that are upgraded are also moved to a safer location. For example,
moved further from the roadway where they are less likely to be hit by a vehicle
and where Avista employees can have a safe parking area to access the station
for maintenance. Many old stations do not have a parking space, this causes
Avista employees to park on the shoulder of the road to access the station for
maintenance. This puts the employee and the traveling public at greater risk of an
accident. In a severe case, vehicle damage to a station may cause a customer
outage. It is hard to predict the severity of the outage because the number of
customers downstream of each station varies greatly across the system.
The cost of an outage is estimated at $2,960 per customer3. This cost includes the
cost for Avista to restore service and the potential economic impacts to the
customer. The calculation assumes that restoration will be completed within 24
hours, which is Avista's restoration goal. A severely damaged station may take
longer than 24 hours to repair and bring back into service.
z The average life of a typical station was estimated by looking at the age of historical stations that were rebuilt
under this program
3 The Interruption Cost Estimate(ICE) Calculator was used to estimate the economic impacts to the customer
at $116 per hour per customer. An estimated restoration cost of$176 per customer is based on the actual
restoration costs incurred during the 2022 Crestline outage in Spokane. Therefore the total cost per customer
is estimated to be$116 x 24 hours+$176=$2,960.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 349 of 535

DocuSign Envelope ID:35775496-6BA9-40DE-892C-B2DB717DABCB
Gas Regulator Station Replacement Program, ER 3002
Below are potential outage costs for varying degrees of customer outages:
Number of Customers Potential Cost
Out of Service
1 $2,960
10 $29,960
100 $296,000
1,000 $2,960,000
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
This work is needed now because, according to our Station Evaluations
spreadsheet, there is already a backlog of approximately 50 stations deemed high-
risk and in need of replacement. Additionally, the list of stations needing
replacement continues to grow by an estimated 2-5 stations per year as stations
meet the end of their service life. Postponing the work will cause the list of
stations needing replacement to outpace the number of stations remediated.
When this happens, there becomes a greater risk to having equipment fail due to
outdated/unsafe conditions or an employee or public safety incident.
Risk Probability Definitions:
Risk event expected to occur
High(H) Risk event more likely to occur than not
Probable(P) Risk event may or may not occur
Low(L) Risk event less likely to occur than not
Very Low(VL) Risk event not expected to occur
Risk Avoidance Over Time and the Cost of Doing Nothing:
Risk Over Time(years)
# Risk 1 2 5 10 15+ Cost Estimate
1 Regulatory Fines* $257,664 per day per violation(Max)
$2,576,627 Total(Max)
2 Pipeline Leak P P H $5,000 to$150,000 per site(site dependent)
3 Pipeline Failure&Outage P P H $150,000 to$3,000,000 per site(site dependent)
4 Negative Reputation P P Erosion of PUC and Public trust
5 Employee&Public Safety P P H H Lost time,lawsuits,healthcare,etc.(varies)
*State fines are not prescribed, and it is up to each state to determine the fine amount. Federal
regulatory fines present a daily and overall maximum value per violation in accordance with 49
CFR Part 190.223. However, these values are not necessarily an accurate representation of how
much Avista would be fined for any specific violation. The actual amount is likely to be much lower
since Avista has an ongoing reputation and history of investing in programs related to safety and
non-compliance issues. However, it is a bookend reminder from which to characterize the
regulatory risk associated with chronic and/or egregious non-compliance, especially in the event of
a pipeline safety incident (i.e., failure). Therefore, Avista must continue to demonstrate an ongoing
Business Case Justification Narrative Template Version: February 2023 Page 5 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 350 of 535

DocuSign Envelope ID:35775496-6BA9-40DE-892C-B2DB717DABCB
Gas Regulator Station Replacement Program, ER 3002
commitment to compliance and pipeline safety to ensure favorable future outcomes with respect to
regulatory penalties (actual penalty amount is at the discretion of the state or federal agency).
1.4 Discuss how the proposed investment, whether project or program,
aligns with the strategic vision, goals, objectives and mission statement
of the organization. See link.
Avista Strategic Goals
Mission Statement excerpt: "By delivering energy safely, responsibly, and
affordably, Avista helps empower our customers to live their lives to the fullest."
By proactively replacing obsolete or unsafe stations, we continue to provide safe,
reliable service for our customers and ensure that customers will not experience
an unplanned interruption of gas service.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.4
The Gate Station, District Regulator Station, SSFT, and Industrial MSA Evaluation
Form is filled out by Gas Operations who perform station maintenance. This form
helps to risk rank each station based on many criteria including station condition,
equipment, location and access, and inlet and outlet valves. The data from these
forms is consolidated into a master spreadsheet which then calculates a score for
each station. The higher the score, the higher priority the station is for
replacement. Below is what the Evaluation Form looks like.
4 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 351 of 535

DocuSign Envelope ID:35775496-6BA9-40DE-892C-B2DB717DABCB
Gas Regulator Station Replacement Program, ER 3002
Gate Station,District Reaulator Station.SSFT.and Industrial MSA Evaluation Form
Station# Station Type: Location-
Overall Station Condition
Paint :]Good ❑Cracking/Flaking
Corrosion -None []Minor DSrgnificant(provide comment below)
Welds Pass Visual Inspection Oyes ONo
Threaded Fittings ❑Yes on HP OYes on IP []No
Bypass -Full[]Partial[]LeadlLag[]Hard[]Soft_None-Single Valve Isolation
Sense Line Cont. -Standard OShort []Underground
Height ❑Adequate DRequires Ladder/Platform-Too Short
Pipe Settling ❑Major []Minor L7None
Supports []Yes.AdjustEIYes.Non-Adjust ONot Needed ONo but Needed
External Forces []Major(provide comment below) []Minor ❑None
Pressure Parts []Adequate []Not Adequate(provide comment below)
Ability to Check Lockup[]Yes ONo
Comments:
Station Equipment
Regulator(s) OStarldard []Non-Std []Obsolete ❑Flanged []Threaded
Relief Valve(s) []Standard []Nan-Std -Obsolete CN/A
Strainer/Fitter(s) OStandard ONon-Std []Obsolete ❑None
Valve(s) ❑Standard []Nan-Std []Obsolete ❑Non-Operable
Greasable Valve Upstream of Reg DYes ONo
Odor¢er OAdequate ONot Adequate(provide comment below) ❑N/A
Heater []Adequate DNot Adequate(provide comment below) =NIA
Comments:
Facility Access.Location,and Protection
Fence []Good[]Minor IssuesLISevere Issues OVandalism CN/A
Building ::]Good❑Minor Issues[]Severe Issues OVandalism ON/A
Barricade []Sufficient DNot Sufficient ❑Doesn't Need
Access []Drive-up DWalk-up ❑Un-Safe(provide comment below)
Location []Good ❑Poor(provide comment below) OEasement []Right-of-Way
Parking ❑Parking Space Don Street/Shoulder ONone
Overhead Power []Yes []No
Vault []Yes []No
Venting -Sufficient []Needs Venting OWA
Comments:
Inlet and Outlet Valves
Inlet Valve(s) :320'-50'Away 'Ma20' 0>50' ❑Inside Fence =No Valve
Outlet Vatve(s) ::120'-50'Away 0Q0' 0>50' 7—Inside Fence nNo Valve
Comments:
The Station Evaluation Spreadsheet is the master spreadsheet that contains the
evaluation scores for each station. A partial screenshot of this spreadsheet is
shown below.
Station ear ASfe�lnk-�Sm I-.Stwdw TlLllaWon LI Paint irnnod-INhldk Fi4 V19- TMaaded FMC-11 Dow -S4 Lim CaMpuad Height PI seldl- __ _ _ _ _ M Suyi�k'-Eldtllnl Fan-I hgm
232 Y 2020 S6 GS Good Hone No n HP,Yes on IP Angle Wft Isoladon Blank Too Sf None es.Non-Adi..Malor Ad..
22 2021 SS.s DR Cracking/naking Mi— No Yes on HR Yes on IP Hmd 51wrt Requires latlder/platform None Not Needed None Ade
13 2021 54.5 DA Cncking/Flaking Mhu, No Yes on P.Yeson lP None short Adequate None Not Needed N.- Blank
278 2020 54 DR Cracking/Flaking None Blank Yes on HP.Yeson IP Single Valve lsoladon Blank Adequate None Not Needed Minor Not Ad
29 2021 51.5 OR Cracking/Flakhl MI— No No Hard Short Requires ledd,,/pladq None Not Needed None Adego
36 2021 49 DR Cracking/Flaking Mina, No No Hard Short Requires Ladder/Pladorn None Not Needetl None Blank
33 2821 18 DA 6, 1,4 id"N Ne Ne Hard flser! ;e 5heek None NeFNeeded Nerx Adage
33 2021 42 DR Cracking/Flaking None No No Ha,d short Adequate None Not Needed None Adegp
22 2021 46.6 DN EKNng(r4Nwg MMer Ne Me kwd/bg Shen Rego:eekeddeepMtkarw None kkeaaleeded None A--
30 2021 45 DR Cracking/FWking Mi., No No Nerd short Requires ladder/Plefo None Nos Needed None Adequ
1343 2021 .5 SSFT 5509W L—M Cracking/Flaking SigniNean,Blank yes on HP.Yes on IP Soh Blank Adequate None No,Needed None Ade
26NM 2020 43 G5 Good None Blank Yes on HP,yes on IP None Blank Too Skort None Blank None Not Ac
Business Case Justification Narrative Template Version: February 2023 Page 7 of 13
Exhibit No. 10
Case Nos.AW-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 352 of 535

DocuSign Envelope ID:35775496-6BA9-40DE-892C-B2DB717DABCB
Gas Regulator Station Replacement Program, ER 3002
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative(e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The requested level of spending for this program allows the high priority projects to
be completed every year. The list of new requests continues to grow as stations
meet the end of their service life. The workforce available to do this type of work is
responsible for both maintenance of these stations and the rebuild efforts. This level
of spend complements their available time as well, without requiring additional labor
resources.
On average, 10 to 20 high priority projects get funded each year. The actual number
of projects completed per year vary based on the type of station and the scope of
the project. Some larger projects span multiple years to allow for long lead time
material planning as well as design.
This program is meant to be proactive (preventive) rather than reactive. These
stations are vital to providing customers with reliable gas service. Planned
replacement work is preferred over unplanned work. With proactive work, a plan
can be put into place to ensure that customers do not lose gas service while the
project is being completed. Reactive replacement work during times of high gas use
can be more difficult to perform, have negative impacts to customers, and can
inadvertently cost the company more money in resources spent than the preventive
measures would. Also, due to worldwide supply chain issues, some of the
equipment at these stations have very long lead times; therefore, taking a proactive
replacement approach helps maintain reliable service.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).5
Proactively replacing a station is much more cost effective than reactively
replacing one that has failed or was damaged by outside forces. To illustrate,
regulator station #66 located at the intersection of Regal St and Gordon Ave in
Spokane was hit by a car in 2018. The incident happened after normal business
hours and required an emergency response by Avista. This station is a typical
farm tap style station. The station needed to be replaced due to extensive
damage caused by the vehicle, and the cost to replace the station was
approximately five times higher than what it would have cost to replace the
station under a planned project. The major contributor to the cost being so
5 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 8 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 353 of 535

DocuSign Envelope ID:35775496-6BA9-40DE-892C-B2DB717DABCB
Gas Regulator Station Replacement Program, ER 3002
much higher is crew overtime, as these emergency events must be worked until
made safe and service restored. The cost to replace the damaged station was
approximately $15,000 whereas the cost to proactively replace the station would
have been approximately $3,000 in 2018.
Emergency repair or replacements can also increase the risk of a customer
outage versus a planned replacement project. Public and employee safety is of
utmost importance during a gas emergency, therefore under most
circumstances quickly isolating the affected system takes priority over
maintaining service to customers. If a station failed or was damaged by an
outside force resulting in a gas leak or a system abnormal operating condition, it
is likely that first responders will isolate the system which may result in customer
outages. During planned worked there are measures taken to maintain gas
service to customers, for example installing a bypass around the work zone.
These measures to maintain service to downstream customers take additional
time to install in the field and therefore may not be appropriate or available
during a gas emergency.
Another risk associated with running a station to failure is equipment and
material availability. Many stations have long lead time equipment and
materials that may not be available when needed. If equipment or materials are
not available, temporary equipment or materials may have to be installed in
order to restore service to customers. These temporary items may have to be
replaced with the appropriate permanent items at a later date, further increasing
costs associated with the event.
2.3 Summarize in the table and describe below the DIRECT offsets6 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $0 $0 $0 $0 $0
0&M Reduced Station Maintenance $3,400 $5,300 $7,200 $9,300 $11,500
Time
Gas Engineering, Gas Operations, and the Gas Meter Shop work together to
prioritize and administer the work for the year. The work is generally
prioritized early in the year and then implemented throughout the spring,
summer, and fall. The work is typically comprised of several individual station
replacement projects.
s Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2023 Page 9 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 354 of 535

DocuSign Envelope ID:35775496-6BA9-40DE-892C-B2DB717DABCB
Gas Regulator Station Replacement Program, ER 3002
Completion of this work will reduce O&M costs because stations that are at the
end of the end of their service life and/or are not up to Avista's current
standards typically take longer to maintain. Refer to spreadsheet titled Offset
Calcs ER 3002.xlsx showing the calculations for the direct savings shown in
the table above.
2.4 Summarize in the table and describe below the INDIRECT offsets?
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $0 $0 $0 $0 $0
0&M Outage Avoidance $76,960 $76,960 $76,960 $76,960 $76,960
Completing this annual program will reduce the potential for a customer outage
due to equipment failure or a physically damaged station. The estimated cost of
an outage is estimated at $2,960 per customer$. This cost includes the cost for
Avista to restore service and the potential economic impacts to the customer. The
calculation assumes that restoration will be completed within 24 hours, which is
Avista's restoration goal. A severely damaged station may take longer than 24
hours to repair and bring back into service.
Below are the potential restoration and customer economic costs for varying
numbers of customer outages:
Number of Customers Potential Cost Likelihood of Event
Out of Service
1 $2,960 1
10 $29,960 0.5
100 $296,000 0.1
1,000 $2,960,000 .01
See spreadsheet Offset Calcs ER 3002— Reg Reliability 2023.xlsx for
assumptions and calculations.
Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
s The Interruption Cost Estimate(ICE) Calculator was used to estimate the economic impacts to the customer
at $116 per hour per customer. An estimated restoration cost of$176 per customer is based on the actual
restoration costs incurred during the 2022 Crestline outage in Spokane. Therefore the total cost per customer
is estimated to be$116 x 24 hours+$176=$2,960.
Business Case Justification Narrative Template Version: February 2023 Page 10 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 355 of 535

DocuSign Envelope ID:35775496-6BA9-40DE-892C-B2DB717DABCB
Gas Regulator Station Replacement Program, ER 3002
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those
additional risks to Avista that may occur if an alternative is selected.
Option Capital Cost Start Complete
Recommended Solution: Replace at risk stations at $1,070,000 January December
requested funding level —Reduce Backlog
Alternative Solution 1: Replace at risk stations at a $500,000 January December
reduced funding level —Maintain Backlog
Alternative Solution 2: Replace at risk stations at a $250,000 January December
reduced funding level — Increase Backlog
Alternative 1:
This alternative solution would be to replace at risk stations at a reduced
funding level. There is already a backlog of approximately 50 high-risk stations
that need to be replaced throughout our entire system. Meanwhile, an
estimated 2-5 new stations are upgraded to high-risk every year due to aging
infrastructure. This alternative would only allow us to maintain the current
backlog of 50 stations (depending on how many stations were upgraded to
high-risk status that year). This alternative is not advised since no progress
could be made in reducing the backlog of high-risk stations. When this
happens, there becomes a greater risk of running equipment to failure. The
implications of this are discussed in Sections 1.3 and 2.2.
An alternative to rebuilding the entire station would be to replace only the
individual components that are antiquated or outdated. If this short-sided
course were chosen, the work would be less productive and the opportunity to
bring the entire station up to current standards would be lost. Often, older
stations that have antiquated or outdated equipment are also difficult to
maintain due to outdated configurations, for example: short sensing lines,
limited valve locations, and equipment being installed high above ground or in
vaults. This option is not recommended. Another downside to this approach
would be the loss of opportunity to right size the capacity of the rebuilt station.
Often, station capacity is increased when the station is rebuilt to support future
demands.
Alternative 2:
This alternative is similar to Alternative 1, except the further reduction in
funding would likely cause an increase in our backlog of high-risk stations. Not
only limiting our ability to maintain our current system, but likely causing the
overall health of the system to decrease each year that it's funded at this level.
If the program were to be funded at this level, Avista would be forced to
Business Case Justification Narrative Template Version: February 2023 Page 11 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 356 of 535

DocuSign Envelope ID:35775496-6BA9-40DE-892C-B2DB717DABCB
Gas Regulator Station Replacement Program, ER 3002
operate at-risk stations in an unsafe, unreliable, and sometimes non-code
compliant manner. Like Alternative 1, this alternative increases the risk that
equipment will run to failure. The risk associated with Alternative 2 is higher
than Alternative 1, since more high-risk stations will be operating. The many
implications associated with this increased risk are discussed in Sections 1.3
and 2.2. This option is not recommended.
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how
will success be measured).
Success can be measured through the Station Evaluation Spreadsheet, which is
the master spreadsheet that contains the evaluation scores for each station. A
partial screenshot of this spreadsheet is shown below.
Subw-Year Antose,•kI e -Station Ty-location IsaM[ •_CorsOsi-Welds pass VW- Threaded FNtin,- Bypass •Seale IMeCatflryratl Neiplt Pipe SM - Supports-EstenW Fon•PNow
232 HIM 56 GS Good None No Yes on NR,Yes on IP Single VI,,Isoladon Blank Too Sh., None Yet,Non AClus[Ma,or Adequ
22 2021 55.5 OR Crxklry/F4Nrp Mlnor No Yes on NP,Yes on lP Nxd Shxt Requkez Nddx/plxtorm N. IN ssded None Adequ
23 20 S4.5 M Crxklry/Fleking MI- No Yes on NP.Its en lP Nq Short Ade .I. Norw Not Needed None Blank
278 M20 S4 OR Cw•1dt�g/�Fele1�kIM None Blank Yes on HP.Yes On UP Single Valle Isolation 66M Adequate None Not Needed Mlnx Not At
28 2021 11.5 OR Cwkh,, .kIW Mi., No NO Nxd Short Requires laddx/platform None No[Needed None Adequ
36 2021 49 GR C-11d.&TUM gMirror No No Nxd Shxt Requires ladder/PlatForn None N.[Needed None Blank
31 3B?k a8 Im Caekk iking Rare Ne Ne Nard store ieeil+ert Nave NetMeeded Nerve A.-
33 2021 42 OR Cracking/Fleking None No No Nard Show Adequate None Not Needed None Adequ
27 202s KS OR G N O'(Nasiwt_ No No keadkeg stow Aegweslalder/PNNxn Neee NeeNeerled Nerve Adeea
3d 2021 45 OR Ml No No Nxd dart Requires ladder/Platform None Not Needed None Adequ
1343 2021 M.5 SSR SSW law Crackm,,/Flasing Significant Blai,4 yes on N P.yes on lP Soh Blank Adequate None Not Needed None Adequ
26N05 2020 43 GS Good None BIan4 Yes on Hp,Yes on IP None Blank Too Shon None Blank None Not Aq
Station scores typically range from 0-60+, with the following categorization:
Low risk/priority: 0-20
Medium risk/priority: 20-40
High risk/priority: 40 and above
Some examples of recently rebuilt stations and their updated scores include:
Station Original Score Rebuild Date New Score
(risk level) (risk level)
#27 45.5 — High 2022 0 — Low
#31 48 — High 2022 1 — Low
#562 21 — Medium 2023 0 — Low
#36 49 — High 2023 0 — Low
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
The program will be completed between January and December of each year. The
investments become used and useful to the customer at the completion of each
station rebuild project.
Business Case Justification Narrative Template Version: February 2023 Page 12 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 357 of 535

DocuSign Envelope ID:35775496-6BA9-40DE-892C-B2DB717DABCB
Gas Regulator Station Replacement Program, ER 3002
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of
the business case, and how such oversight will occur.
Gas Engineering, Gas Operations, and the Gas Meter Shop work together to
prioritize and administer the work for this program. The project engineer puts
together the project estimate which is then approved by the gas design manager
and director. Monthly budget updates are completed in Tablaeu to make sure the
program remains on budget throughout the year. The project engineer is also
responsible to update the Station Evaluation Spreadsheet with the station's new
score at the conclusion of the project.
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Regulator Station Replacement
Program, ER 3002 and agree with the approach it presents. Significant changes to this will
be coordinated with and approved by the undersigned or their designated representatives.
D 5g tlby:
Signature: g W.0 Date:May-03-zoz4 1 9:27 AM PDT
Print Name: Jeff Webb
Title: Mgr Gas Engineering
Role: Business Case Owner
E60,
si a cy:
Signature: ebbs Date:May-03-zoz4 1 9:41 AM PDT
Print Name: Alicia Gibbs
Title: Director of Natural Gas
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 13 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 358 of 535

DocuSign Envelope ID:OFCEDD45-8E82-491D-93A2-32825B605887
Gas Reinforcement Program, ER 3000
EXECUTIVE SUMMARY
Annually the Gas Planning department runs an analysis (load study) on Avista's gas distribution
system to identify areas of the system with insufficient capacity to serve existing Firm customer
loads on a design day. The design day is defined as the 30-year coldest average daily
temperature of a weather region with 99% probability of happening. These deficient areas are
given a risk ranking based on the severity and the number of customers impacted. The areas
with the highest priority are selected for remediation and the project is assigned to Gas
Engineering to evaluate options to provide sufficient capacity to meet firm gas demands on a
design day. Typical projects completed under this Business Case may include upsizing existing
gas mains, looping existing gas mains, and installing new, or upsizing existing regulator
stations. Options are reviewed with Gas Planning, Gas Operations, and other interested
parties. The pros and cons of each option are then reviewed with the Gas Engineering Manager
and a preferred alternative is selected to proceed with a funding request. The business needs
and potential solutions identified impact all gas customers in Avista's service territory. Spending
per jurisdiction changes each year, as the intent is to complete the highest risk projects first,
regardless of which State it is in.
The proposed annual budget is consistent with expenditures from past years to complete
several of the highest priority projects each year. Individual reinforcement projects completed
under this program can cost anywhere from approximately $1 OK, to upwards of$500K. Each
year, Gas Engineering develops estimates for the highest priority projects. The projects that can
be completed while keeping the total program spend at the budgeted amount are then identified
and completed. Some years, not all high priority projects are able to be completed and have to
carry over to the next year. There is currently a backlog of projects. Due to the number of
remaining proposed reinforcements, and the continued customer demand in Avista's service
territory, this is an ongoing program. The following table captures historical spend in this
program since 2019:
Table 1: Historical Spend in ER 3000
Year Spend
2019 $1,062,779
2020 $1,168,033
2021 $1,160,740
2022 $1,723,891
2023 $1,128,882
If these reinforcements are not completed, Avista's firm gas customers are at risk of a gas
outage on a cold winter day. The number of customers impacted by each reinforcement is
different; however, typically the highest priority reinforcements correlate to the highest number
Business Case Justification Narrative Template Version: February 2023 Page 1 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 359 of 535

DocuSign Envelope ID:OFCEDD45-8E82-491D-93A2-32825B605887
Gas Reinforcement Program, ER 3000
of customers at risk of an outage. The estimated cost of an outage is $2,960 per customer'.
This cost includes the cost for Avista to restore service and the potential economic impacts to
the customer. The calculation assumes that restoration will be completed within 24 hours,
which is Avista's restoration goal. On average, each high priority reinforcement area has the
potential to lose 1,400 customers during an outage if the reinforcement is not completed. An
outage response for 1,400 customers would cost approximately $4,144,000. Since peak gas
load occurs on the coldest days, a system capacity related outage would most likely occur on a
very cold day; therefore, customers who use natural gas as their primary heat source may also
be at risk for life and/or property damage (example: frozen pipes). Other risks to customers
include loss of revenue for commercial and industrial customers who rely on natural gas service
for business. Ensuring our firm customers have adequate gas supply for all planned and
unexpected weather conditions is part of being a prudent operator and is backed up in the work
we do with our Integrated Resource Plan (IRP). This program is in direct support of that effort.
VERSION HISTORY
Version Author Description Date
1.0 Jeff Webb Initial draft of original business case 311712017
1.1 Jeff Webb 4/06/2017
2.0 Jeff Webb Revised for 2020 Oregon GRC Filing 211712020
2.1 Tim Harding Updated to the refreshed 2022 Business Case Template 8/31/2022
Shontelle
2.2 Wilson/Rachael Updated to the refreshed 2023 Business Case Template 411012023
Anderson
2.3 Rachael Anderson Revised for 5-Year Capital Planning 4/19/2024
BCRT Team
BCRT Mememb Has been reviewed by BCRT and meets necessary requirements 4/19/2024
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2025 1,340,000 1,340,000
2026 1,380,000 1,380,000
2027 1,420,000 1,420,000
2028 1,465,000 1,465,000
2029 1,505,000 1,505,000
' The Interruption Cost Estimate(ICE) Calculator was used to estimate the economic impacts to the customer
at $116 per hour per customer. An estimated retoration cost of$176 per customer is based on the actual
restoration costs incurred during the 2022 Crestline outage in Spokane. Therefore the total cost per customer
is estimated to be$116 x 24 hours+$176=$2,960.
Business Case Justification Narrative Template Version: February 2023 Page 2 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 360 of 535

DocuSign Envelope ID:OFCEDD45-8E82-491D-93A2-32825B605887
Gas Reinforcement Program, ER 3000
Project Life Span Ongoing
Requesting Organization/Department B51 —Gas Engineering
Business Case Owner I Sponsor Rachael Anderson/Jeff Webb I Alicia Gibbs
Sponsor Organization/Department B51 —Gas Engineering
Phase Execution
Category Program
Driver Performance& Capacity
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
This annual program will identify and provide for necessary capacity reinforcements to the
existing natural gas distribution system in WA, ID, and OR. Avista has an obligation to serve
existing firm gas customers by providing adequate capacity on design day weather conditions.
The design day is defined as the 30-year coldest average daily temperature of a weather region
with 99% probability of happening. Periodic reinforcement of the system is required to reliably
serve firm customers due to increased demand at existing service locations and new customers
being added to the system. Execution of this program on an annual basis will ensure the
continuation of reliable gas service that is of adequate pressure and capacity. If these
reinforcements are not completed, Avista's firm customers are at risk of a gas outage on a cold
winter day. The risks and impacts associated with this are discussed further in Section 1.3.
Ensuring our firm customers have adequate gas supply for all planned and unexpected weather
conditions is part of being a prudent operator and is backed up in the work we do with our
Integrated Resource Plan (IRP). This program is in direct support of that effort.
1.2 Discuss the major drivers of the business case.
The major driver of this Business Case is Performance and Capacity. The intent of this program
is to add capacity to the gas distribution system to ensure firm gas customers can receive an
adequate supply of natural gas according to design day conditions. Without these
reinforcements, customers will remain at risk of losing natural gas service when it is needed
most, on the coldest winter days.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 361 of 535

DocuSign Envelope ID:OFCEDD45-8E82-491D-93A2-32825B605887
Gas Reinforcement Program, ER 3000
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
There are currently areas of the gas systems that are at risk during extreme cold weather
because the system capacity cannot meet peak demand. Currently, there are 34 identified
distribution deficiencies across our entire system. This means, we are at risk of some level
of customer outage in each of these areas at temperatures warmer than the design day
standard. For each distribution area, one or more reinforcements may be needed to
ensure all customers in the identified system can be served during a design day condtion.
By upgrading these systems, we reduce the chance of cold weather outages. At a
minimum, outages are an inconvenience to customers. They can, however, become a
serious health and safety concern because they tend to happen during extremely cold
weather. System outages that cause customers to be without heat during extreme cold
weather must be avoided. If we fail to perform the proper reinforcement then the number
of affected customers at risk of outages will increase. The number of customers impacted
by each reinforcement is different, ttypically the highest priority reinforcements correlate to
the highest number of customers at risk of an outage. On average, each high priority
reinforcement area has the potential to lose 1,400 customers during an outage if the
reinforcement is not completed. The estimated cost of an outage is $2,960 per customer2.
This cost includes the cost for Avista to restore service and the potential economic
impacts to the customer. The calculation assumes that restoration will be completed
within 24 hours, which is Avista's restoration goal. An outage response for 1,400
customers would cost approximately $4,144,000.
1.4 Discuss how the proposed investment, whether project or program,
aligns with the strategic vision, goals, objectives and mission statement
of the organization. See link.
Avista Strategic Goals
This proposed investment focuses highly on reliable service to customers. By reinforcing
Avista's natural gas infrastructure, we will be able to provide customers with reliable
energy and will be able to prevent our customers from having an interruption of service on
very cold days when they need it the most. Ensuring our firm customers have adequate
gas supply for all planned and unexpected weather conditions is part of being a prudent
operator and is backed up in the work we do with our Integrated Resource Plan (IRP).
This program is in direct support of that effort. Performing reinforcements keeps our
customer's safety and health in mind by preventing unnecessary outages during below
freezing temperatures.
z The Interruption Cost Estimate(ICE) Calculator was used to estimate the economic impacts to the customer
at $116 per hour per customer. An estimated retoration cost of$176 per customer is based on the actual
restoration costs incurred during the 2022 Crestline outage in Spokane. Therefore the total cost per customer
is estimated to be$116 x 24 hours+$176=$2,960.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 362 of 535

DocuSign Envelope ID:OFCEDD45-8E82-491D-93A2-32825B605887
Gas Reinforcement Program, ER 3000
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.3
Annually the Gas Planning department runs an analysis (load study) on Avista's gas
distribution system to identify areas of the system with insufficient capacity to serve
existing firm customer loads on a design day. The design day is defined as the 30-year
coldest average daily temperature of a weather region with 99% probability of happening.
These deficient areas are given a risk ranking based on the severity and the number of
customers impacted. On an annual basis, the Gas Planning group reviews system load
studies and prioritizes the reinforcement projects. Currently, there are 34 identified
distribution deficiencies across our entire system. This means, we are at risk of some level
of customer outage in each of these areas at a temperature above the design day
standard. For each distribution area, one or more reinforcements may be needed to
ensure all customers in the identified system can be served during a design day
condtion.The list of the above information can be found by Gas Engineering in N:\Gas
Load Study\Gas_Planning_MASTER_PLAN.
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative(e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The requested level of spending for this program allows some high priority projects to be
completed every year. The number of reinforcements completed each year varies as
reinforcements range in cost and scope. Individual reinforcement projects completed
under this program can cost anywhere from approximately $1 OK, to upwards of$500K.
Each year, Gas Engineering develops estimates for the highest priority projects. The
projects that can be completed while keeping the total program spend at the budgeted
amount are then identified and completed. Some years, not all high priority projects are
able to be completed and have to carry over to the next year. All projects completed under
this program involve installing new facilities in the gas distribution system to bring
additional gas flow to the areas that Gas Planning has identified are at risk of gas outages
during cold weather events. Typical projects completed under this Business Case may
include upsizing existing gas mains, looping existing gas mains, and installing new, or
upsizing existing regulator stations. When a reinforcement is done by looping a system,
there is a secondary benefit of higher reliability to the area. Most of these projects will
have a unique project number assigned to them, but the smaller scope, lower cost
projects may be completed under the blanket project numbers set up for each district.
3 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 363 of 535

DocuSign Envelope ID:OFCEDD45-8E82-491D-93A2-32825B605887
Gas Reinforcement Program, ER 3000
As the high priority reinforcements are completed, system deficiencies are reevaluated and
taken off the list if the reinforcements have appropriately addressed the deficiency.
Simultaneously, the list of new reinforcements continues to grow as system deficiencies are
discovered due to customer demand changes. At a reduced funding level, project backlogs will
increase and lead to a higher chance of a gas outage incidents. Each reinforcement that is
completed reduces the risk of an outage event occurring. Risks associated with this are
discussed more in Section 1.3.
2.2 Describe and provide reference to CIRRARR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).4
Gas Planning uses load studies to predict system pressures during design day weather
(extreme cold) conditions. These studies determine the likelihood of system outages, as
well as how many customers are impacted. Annually, the Gas Planning group reviews
system load studies and prioritizes the reinforcement projects. Currently, there are 34
identified distribution deficiencies across the entire system. This means, we are at risk of
some level of customer outage in each of these areas at temperatures warmer than the
design day standard. For each distribution area, one or more reinforcements may be
needed to ensure all customers in the identified system can be served during a design
day condtion. Gas Planning and Engineering then work together to develop
recommendations that will reinforce the area and greatly reduce or eliminate the risk of an
outage. Gas Planning is able to predict the benefit of any given reinforcement by modeling
it in the load study before construction. Reinforcements are only recommended and
completed after confirming that the proposed reinforcement reduces or eliminates the risk
of an outage. Reinforcements are then ranked from high priority to low priority, based on
the number of customers affected as well as the temperature at which we can expect an
outage to occur. These recommendations are refreshed and reprioritized on an annual
basis and given to Gas Engineering to complete.
Below is an example of a gas load study that identified a reinforcement is needed in order
to support firm customer loads on a design day:
4 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 364 of 535

DocuSign Envelope ID:OFCEDD45-8E82-491D-93A2-32825B605887
Gas Reinforcement Program, ER 3000
This is a pressure plot of an area. The red and purple pipes indicate the areas in the gas
distribution system that we can expect customer outages will occur at design criteria
temperatures due to low system pressures. Gas Planning is then able to simulate the
benefits of the proposed reinforcement. The model will then show the reduced risk of an
outage with the planned reinforcement in place. Here is an example of the same gas
system at the same temperature with a proposed reinforcement in place:
Business Case Justification Narrative Template Version: February 2023 Page 7 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 365 of 535

DocuSign Envelope ID:OFCEDD45-8E82-491D-93A2-32825B605887
Gas Reinforcement Program, ER 3000
We can immediately see the reduced risk of customer outages with the new reinforcement
in place (no red or purple pipes). All reinforcements are run through this analysis before
they are given to Gas Engineering to design and complete.
Business Case Justification Narrative Template Version: February 2023 Page 8 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 366 of 535

DocuSign Envelope ID:OFCEDD45-8E82-491D-93A2-32825B605887
Gas Reinforcement Program, ER 3000
2.3 Summarize in the table, and describe below the DIRECT offsets5 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $0 $0 $0 $0 $0
00 Cold Weather Action Plan $22,800 $22,800 $22,800 $22,800 $22,800
During cold weather events, the system must be monitored by Avista personnel.
This includes observing system pressures both in the field, as well as using
remote monitoring equipment. When system deficiencies exist, but have not yet
been completed due to competing projects that have a higher risk, field action
plans are assembled and activated to avoid outages, and to minimize the impact
of potential gas outages. See file Offset Calculations ER 3000 Gas
Reinforcement Program.xlsx for assumptions and calculation details.
2.4 Summarize in the table, and describe below the INDIRECT offsets6
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $0 $0 $0 $0 $0
00 Outage Response $414,000 $828,000 $1,243,000 $1,657,000 $2,072,000
Completing this project will reduce the risk of customer outages due to system
supply constraints. The costs shown in the table above are the estimated cost to
restore a customer outage and the potential economic impacts to the customer.
See file Offset Calculations ER 3000 Gas Reinforcement Program.xlsx for
assumptions and calculation details.
5 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
6 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 9 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 367 of 535

DocuSign Envelope ID:OFCEDD45-8E82-491D-93A2-32825B605887
Gas Reinforcement Program, ER 3000
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those
additional risks to Avista that may occur if an alternative is selected.
Alternative 1:
One alternative is to fund this program at $1,000,000, a lower level than what has
been requested. This is not advised as Avista will get further behind on projects that
are needing to be completed to avoid the risk of customer outages. The reduction in
funding by$300,000 equates to anywhere from 1 to multiple high priority projects that
are not able to be completed.There is already a backlog of projects and areas of the
gas distribution that are at risk. Reducing the funding will increase the risk to our
customers of being part of an outage during a cold weather event
Without a Reinforcement Program, Avista will not have sufficient capacity to meet our
obligation to serve existing firm customer load on a design day scenario.
It is important to note that if service is lost during severe cold weather, gas service
may not become available again for days until weather warms and customer demand
decreases. Depending on the length of the outage, this can cause severe injury up to
and including death to some customers. An outage response for an average of 1,400
customers would cost approximately $4,144,000.
Alternative 2:
An evaluation of non-pipe alternatives is considered against pipeline capacity
reinforcements. Non-pipe alternatives will only be considered when the cost of an
upgrade is at a level high enough where a non-pipe alternative may be cost-effective
(i.e., greater than $500,000), can be accomplished prior to the time the upgrade is
needed, and can lead to a great enough reduction of demand to defer or eliminate the
need for the upgrade. Possible non-pipe alternatives include, but are not limited to,
the following: uprating (raising) the existing pipeline pressure, energy efficiency efforts
including encouraging customers to adopt more efficient appliances and equipment,
and potentially electrification of natural gas appliances. A non-pipe alternative must
address any capacity concerns at a lower cost versus the pipeline reinforcement to be
considered a viable strategy.Thus far, a non-pipe alternative has never been able to
replace the need for a pipeline capacity reinforcement.
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how
will success be measured).
Using computer-based load studies that are based on actual customer usage, Gas
Planning identifies areas of concern that need reinforcement in order to reliably serve
all firm customers during cold weather. Those projects are ranked by severity and the
highest priority projects are sent to Gas Engineering to complete. Success can be
estimated before the project is constructed by modeling the gas system with the
proposed reinforcement in place. This analysis is done to ensure the proposed
reinforcement remedies the area of concern. These projects are managed by the Gas
Engineering group. Construction is completed by Gas Operations with company or
Business Case Justification Narrative Template Version: February 2023 Page 10 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 368 of 535

DocuSign Envelope ID:OFCEDD45-8E82-491D-93A2-32825B605887
Gas Reinforcement Program, ER 3000
contract resources. Gas Engineering monitors and ensures the reinforcements are
completed during the year.
Success is also measured by the monitoring of distribution pressures during the cold
winter months with electronic pressure recording devices. Annually, during the cold
winter months, Gas Planning assigns electronic pressure recording devices to different
parts of the distribution system. Looking at the historical data at these sites, we are able
to verify improved pressures in parts of the distribution system after reinforcements are
completed.
2.7 Please provide the timeline of when this work is schedule to
commence and complete, if known.
This is an ongoing program with multiple projects completed between January and
December of each year. Each project becomes used and useful once construction is
completed, typically this is the same year the project starts.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of
the business case, and how such oversight will occur.
The projects are managed by Gas Engineering and status updates are given to Gas
Planning several times a year to ensure that the highest priority projects are being
addressed first. The Business Case Owner manages the overall budget of the Business
Case. At the beginning of the year, Gas Planning provides the updated reinforcement
recommendation list. The reinforcements are assigned to the Gas Engineers to develop
a cost estimate. Gas Engineering has an annual meeting to identify if all of the
recommendations for the year fit within the approved budget. If not, lower priority
reinforcements are put on hold until the following year. The Business Case Owner
manages the budget closely throughout the year to ensure spending is in line with the
approved yearly amount. If any changes to the budget for the year are needed, the
Business Case Owner proposes a budget change and justification that must get
approval from the Business Case Sponsor before it is brought before the Capital
Planning Group. If additional funds are not approved, then the remaining work is
reduced to remain within budget.
Business Case Justification Narrative Template Version: February 2023 Page 11 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 369 of 535

DocuSign Envelope ID:OFCEDD45-8E82-491D-93A2-32825B605887
Gas Reinforcement Program, ER 3000
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Reinforcement Program, ER
3000 and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.
5'g a by:
Signature: Ly:;
WW Date:May-03-2024 1 9:26 AM PDT
iF F7fCII583
Print Name: Jeff Webb
Title: Mgr Gas Engineering
Role: Business Case Owner
-si a cy:
Signature: Q(Aua ebbs Date:May-03-2024 1 9:40 AM PDT
Print Name: Alicia Gibbs
Title: Director Natural Gas
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 12 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 370 of 535

DocuSign Envelope ID:0581ED12-F040-4FF8-A31E-211F297D4A21
Replacement Street & Hwy Program, ER 3003
EXECUTIVE SUMMARY
Nearly all Avista's pipeline systems are in public right-of-ways (R/W) that are
governed by local jurisdictional franchise agreements. Locating Avista's gas
facilities in R/W is beneficial to customers and is common practice for other utilities
as well, such as electric, water, sewer, and communications. Local jurisdictions
allow Avista to install facilities in this space with no upfront payment. In situations
when local jurisdictional projects create a conflict, Avista is mandated under these
agreements to relocate its facilities.
When conflicts are identified that may require relocating gas facilities, meetings
with the appropriate entities take place in an attempt to design around the conflict.
If relocation of the gas facilities is still required after meeting, then Avista must
complete the work at our cost per the applicable franchise agreement. If the
conflict cannot be designed around and the gas facility must remain in service,
then there are no other alternatives than to relocate Avista's pipes.
It is very difficult to forecast year-to-year what the financial impacts in this category
will be in each district and state as budgets change each year for the
municipalities. Some road projects are more impactful than others to the buried
gas facilities. The budgeted amounts for the next five years are based on average
expenditures in this budget over the last several years. The yearly spend in this
budget has ranged from $3.4 million to $7.7 million since 2019.The lower end of
this range occurred in 2020 when many project were halted or delayed due to the
COVID-19 Pandemic.
By completing the projects as requested, Avista meets the obligations under its
franchise agreements, remains in good standing with the municipalities, and
avoids financial penalties associated with project delays.
The work is generated by the various municipalities that Avista has franchise
agreements with. Gas Operations manages this category of work in each district.
The overall program budget is monitored by Gas Engineering closely throughout
the year. Regular check-ins are conducted with Gas Operations to update the
projected annual spend accordingly as new projects come up.
VERSION HISTORY
Business Case Justification Narrative Template Version: February 2023 Page 1 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 371 of 535

DocuSign Envelope ID:0581ED12-F040-4FF8-A31E-211F297D4A21
Replacement Street & Hwy Program, ER 3003
Version Author Description Date
1.0 Jeff Webb Initial draft of original business case 3/17/2017
1.1 Jeff Webb Revised 411712017
2.0 Jeff Webb Revised for 2020 Oregon GRC Filing 211712020
3.0 Jeff Webb Revised for new BC format 813012022
3.1 Shontelle McGrath Updated to the refreshed 2023 Business case template 8/2/2023
3.2 Jeff Webb Updated date for 2024 411812024
BCRT Team
BCRT Memember Has been reviewed by BCRT and meets necessary requirements 412412024
GENERAL INFORMATION
YEAR PLANNED SPEND PLANNED TRANSFER TO
AMOUNT ($) PLANT ($)
2025 5,500,000 5,500,000
2026 5,665,000 5,665,000
2027 5,834,950 5,834,950
2028 6,009,999 6,009,999
2029 6,190,298 6,190,298
Project Life Span Ongoing.
Requesting Organization/Department B51 /Gas Engineering
Business Case Owner I Sponsor Jeff Webb I Alicia Gibbs
Sponsor Organization/Department B51 /Gas Engineering
Phase Execution
Category Program
Driver Mandatory& Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
The problems that are being addressed through this program are the physical
conflicts between natural gas facilities and roadway projects or other utilities within
R/W.
Virtually all Avista's pipelines are in R/W that are governed by local jurisdictional
franchise agreements. Avista is mandated under these agreements to relocate
our facilities, at our cost, when local jurisdictional projects necessitate. Many of
Business Case Justification Narrative Template Version: February 2023 Page 2 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 372 of 535

DocuSign Envelope ID:0581ED12-F040-4FF8-A31E-211F297D4A21
Replacement Street & Hwy Program, ER 3003
these projects come to Avista without significant lead time by the local
jurisdictions. It is often the case that meetings are called in the spring season to
notify franchisees (natural gas, electric, cable, phone companies etc.) that they will
need to relocate their facilities that year. This makes accurate long term budget
forecasts challenging.
When conflicts are identified that may require relocating gas facilities, attempts are
made to design around the conflict. If conflicts cannot be resolved, then relocation
of gas facilities is required. Avista must then relocate the gas facility at its cost per
the applicable franchise agreement. If the relocation project is of significant
complexity, then Gas Engineering will take over the project to design and manage
it through completion; otherwise, the local districts typically manage the project.
The business needs and potential solutions identified impact all gas customers in
Avista's service territory.
1.2 Discuss the major drivers of the business case.
The major driver of the business case is Mandatory and Compliance. Per the
franchise agreements with local jurisdictions, Avista is required to resolve conflicts
within R/W at Avista's cost.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The nature of this work is considered "work in request of others". If the conflicts are
not resolved through design changes or relocation of the gas facilities, Avista
would not comply with its franchise agreements and could be charged with delay of
a project. This would not only be a financial burden on the company, but it would
also greatly damage the working relationship between Avista and the municipality.
1.4 Discuss how the proposed investment, whether project or program,
aligns with the strategic vision, goals, objectives and mission statement
of the organization. See link.
Avista Strateizic Goals
The projects within this Business Case align with Avista's values of being
Trustworthy and Collaborative. We are Trustworthy when we resolve conflicts
between our pipeline facilities and local jurisdictional projects since that is what
Avista agreed to in the franchise agreements. We are Collaborative when we work
together with local jurisdictions to either design around the conflict or come up with
a relocation plan that addresses the conflict.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 373 of 535

DocuSign Envelope ID:0581ED12-F040-4FF8-A31E-211F297D4A21
Replacement Street & Hwy Program, ER 3003
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
Here is an example of a road move project that Avista worked on with the Idaho
Transportation Department in Bonners Ferry. This is just one page of the project
plans that involved relocating approximately 700 feet of 2" PE main and 1,200 feet
of 4" steel main that were in conflict with the new roadway design.
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is just one example of the many road move projects that are completed under
this Business Case. Avista receives project plans like these from the different
municipalities to aid in project relocation designs. Oftentimes, Avista
representatives meet with the different municipalities in advance of the project to
assist in the relocation plan.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 374 of 535

DocuSign Envelope ID:0581ED12-F040-4FF8-A31E-211F297D4A21
Replacement Street & Hwy Program, ER 3003
Budget forecasting is primarily based on historical spend. Below is a chart showing
the actual monthly spend for the last five years and the large variation from year to
year.
ER 3003 Rd Moves Historical Spend
By Month and Year
$9,000,000
$8,000,000
$7,000,000
$6,000,000
$5,000,000
$4,000,000
$3,000,000
$2,000,000
$1,000,$0 -
1 2 3 4 5 6 7 8 9 10 11 12
2019 2020 2021 2022 111111111111111111112023 Average
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative(e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The projects within this program address and resolve conflicts between Avista's
gas facilities and projects within local jurisdictions. Each project is unique. When a
jurisdiction has a project where gas facilities are in conflict, efforts are made to
design around the conflict. If this is not possible, Avista works with the jurisdiction
to come up with a relocation plan to eliminate the conflict.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
By completing the projects as requested, Avista meets the obligations under its
franchise agreements. A major risk associated with not completing the work under
this Business Case is tarnishing Avista's good working relationships with the many
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 375 of 535

DocuSign Envelope ID:0581ED12-F040-4FF8-A31E-211F297D4A21
Replacement Street & Hwy Program, ER 3003
municipalities in its service territory. Additionally, Avista would be at risk of
financial penalties associated with project delays if gas facilities in conflict were not
relocated. The work done under this Business Case allows Avista to avoid these
risks.
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
0&M $ $ $ $ $
There are no direct offsets or savings associated with this Business Case.
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
0&M $ $ $ $ $
There are no indirect offsets or savings associated with this Business Case.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those
additional risks to Avista that may occur if an alternative is selected.
If the conflict cannot be designed around by the municipality and the gas facilities
must remain in service, then there are no alternatives for the resolution.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 376 of 535

DocuSign Envelope ID: 0581 ED12-F040-4FF8-A31 E-211 F297D4A21
Replacement Street & Hwy Program, ER 3003
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how
will success be measured).
Projects are either managed by Gas Engineering or local CPCs. Projects are
monitored by the responsible party from project initiation through construction
until the project is completed. Success can be measured by tracking completed
projects and work orders under this Business Case. To help monitor changes in
construction costs, annual cost per foot of gas pipe will start to be reported. See
below for historical spend per foot of pipe.
Annual spend per foot of pipe installed
$400.00
$350.00
$300.00
$250.00
$200.00
$150.00
$100.00
$50.00
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Projects are typically started and completed within the same calendar year and
are placed into service the same month they become used and useful.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of
the business case, and how such oversight will occur.
Gas Engineering manages this Business Case. Many of the projects are handled
by the local construction offices. For more complex relocation projects, Gas
Engineering will manage the relocation project. Throughout the year, Gas
Business Case Justification Narrative Template Version: February 2023 Page 7 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 377 of 535

DocuSign Envelope ID:0581ED12-F040-4FF8-A31E-211F297D4A21
Replacement Street & Hwy Program, ER 3003
Engineering conducts regular check-ins with the local construction offices to get
updates on the road move projects for the year.
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Business Case for ER3003
Replacement Street and Hwy Program and agree with the approach it presents.
Significant changes to this will be coordinated with and approved by the
undersigned or their designated representatives.
LY;
Sg a by:
Signature: Wu Date:May-02-zoz4 19:z7 AM PDT
F FRL35833CF...
Print Name: Jeff Webb
Title: Mgr Gas Engineering
Role: Business Case Owner
E60,
si a c,
Signature: Tibbs Date:May-03-zoz4 I 7:00 AM PDT
Print Name: Alicia Gibbs
Title: Director Natural Gas
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 8 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 378 of 535

DocuSign Envelope ID: CAFB1AD4-8C1C-411C-BCB3-F90A5075DD01
Gas Telemetry, ER 3117
EXECUTIVE SUMMARY
ER 3117 provides funding for additions and improvements to Avista's Gas Telemetry system.
Active equipment includes a population of over 250 flow computers, electronic volume
correctors, and electronic pressure monitors. The system provides safety related pressure
monitoring and alarms at Gate Stations, Regulator Stations, Pipelines, Odorizers, and
Transportation Customers. It also provides critical consumption/usage data for gas
procurement, billing, EPA emissions, engineering analysis, capacity load studies, and system
operations. Gas telemetry is critical for maintaining safe and reliable operation of our gas
system, as well as compliance with Federal Codes Title 49 Part 192.741 and Part 192.635.
A lack of sufficient monitoring points on the system can create blind spots in our understanding
of how the gas system is performing. These blind spots can decrease our ability to detect
abnormal, non-compliant, or unsafe system operating conditions in real time. They can also
create a data void, which makes it harder to analyze the system and justify new reinforcement
projects to ensure gas reliability. Conversely, more monitoring points can provide Avista with
more flexibility and confidence in deferring/delaying reinforcement projects.
Over the past year Avista has experienced two major system EOP events and one near-miss
EOP event. During the 2023 Palouse Outage and 2024 MLK Gas & Power Supply EOPs, the
telemetry system provided invaluable real-time gas system information to key stakeholders,
decision-makers, and company executives. The near-miss event at Medford Gate Station was
prevented from becoming an EOP largely because of Avista's telemetry system. If not for
Avista's alarm and subsequent phone call to TC Energy, it's possible that TC Energy would not
have responded in time to prevent a large-scale outage similar in size to the Palouse Outage.
Below is a summary of the estimated costs offsets for this Gas Telemetry program. Indirect
O&M cost offsets pertain to avoiding manual pressure readings and monetary risks from
regulatory fines, supplier fines, outages, and safety incidents.
ER 3117 Cost Offsets' 2025 2026 2027 2028 2029
Capital(Indirect) $0 $0 $0 $0 $0
00 (Indirect) $209,325 $217,117 $224,910 $232,702 $240,494
Capital(Direct) $0 $0 $0 $0 $0
0&M(Direct) $0 $0 $0 $0 $0
Gas Engineering is proposing a 5-year budget of$100,000 per year plus inflation, which is
consistent with historical annual spending for this scope of work. Proper funding is critical to
ensuring that telemetry system equipment is replaced/upgraded as needed and new sites are
installed as needed to monitor critical aspects of the system. Failure to fund or fully fund the
program could prevent critical monitoring equipment from being replaced or installed at new
sites, which negatively impact's Avista's risk with respect to safety, reliability, compliance,
operations, and finances.
ER 3117 Budget Proposal 2025 2026 2027 2028 2029
Capital $100,000 $103,000 $106,000 $109,000 $112,000
Reference Sections 2.3 and 2.4 of the document for offset details
Business Case Justification Narrative Template Version: February 2023 Page 1 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 379 of 535

DocuSign Envelope ID: CAFB1AD4-8C1C-411C-BCB3-F90A5075DD01
Gas Telemetry, ER 3117
VERSION HISTORY
Version Author Description Date
1.0 Jeff Webb Initial draft of original business case 3/17/2017
1.1 Jeff Webb 4/07/2017
2.0 Dave Moeller Revised for 2020 Oregon GRC Filing 211712020
2.1 Dave Moeller Updated to the refreshed 2020 Business Case Template 71212022
2.2 Dave Moeller Updated to the refreshed 2022 Business Case Template 7/15/2022
2.3 Mike Yang Updated to the refreshed 2023 Business Case Template 411712023
2.3 Mike Yang Overall refresh/Revised to remove MiniAT/ERX program scope 51312024
BCRT Team
BCRT Member Has been reviewed by BCRT and meets necessary requirements
GENERAL INFORMATION
YEAR PLANNED SPEND PLANNED TRANSFER
AMOUNT ($) TO PLANT ($)
2025 100,000 100,000
2026 103,000 103,000
2027 106,000 106,000
2028 109,000 109,000
2029 112,000 112,000
Project Life Span 5 years
Requesting Organization/Department B51 —Gas Engineering
Business Case Owner I Sponsor Mike Yang &Jeff Webb I Alicia Gibbs
Sponsor Organization/Department 1351- Gas Engineering
Phase Execution
Category Program
Driver Performance& Capacity
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
Business Case Justification Narrative Template Version: February 2023 Page 2 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 380 of 535

DocuSign Envelope ID: CAFB1AD4-8C1C-411C-BCB3-F90A5075DD01
Gas Telemetry, ER 3117
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
Ongoing funding for new gas telemetry equipment is required for situational
awareness, safety, compliance, Transportation Customers, capacity analysis, and
system improvements. Telemetry equipment includes flow computers, electronic
volume correctors, and electronic pressure monitors installed at both permanent and
temporary locations around the gas system. This equipment provides system
performance, safety and compliance related pressure monitoring, and alarms
throughout the gas system at Gate Stations, Regulator Stations, Pipelines, Odorizers,
and Transportation Customers. It also provides critical consumption/usage data for
gas procurement, billing, EPA emissions, engineering analysis, capacity load studies,
and system operations. Avista's telemetry system currently consists of approximately
250 permanent device locations and 50 seasonally deployed device locations.
Code of Federal Regulations (CFR)Title 49 Part 192 has multiple requirements
governing gas pipeline monitoring. CFR Title 49 Part 192.741 requires monitoring at
regulator stations and CFR Title 49 Part 192.635 requires notification of potential
rupture. Telemetry equipment installed and funded under this program are critical to
staying in compliance with these code requirements.
Failure or malfunctioning telemetry equipment, or an inadequate number of
monitoring points can impact Avista's ability to maintain efficiency, regulatory
compliance, and reliability of the gas operations monitoring system. Lengthy outages
due to failed or malfunctioning equipment increases the risk that Avista would not be
able to detect abnormal, non-compliant, or unsafe system operating conditions (i.e.,
pressure and flow conditions) at key facilities or areas of the system that experience
low pressures. Failed equipment also impacts Avista and the agents for Avista's
transportation customer who rely on timely gas consumption data for accurate daily
gas supply nominations to avoid contractual fines.
A lack of sufficient monitoring points on the system can create blind spots in our
understanding of how the gas system is performing. These blind spots can decrease
our ability to detect abnormal, non-compliant, or unsafe system operating conditions
in real time. They can also create a data void, which makes it harder to analyze the
system and justify new reinforcement projects to ensure gas reliability. Conversely,
more monitoring points provides Avista with more flexibility and confidence in
deferring/delaying reinforcement projects.
Over the past year Avista has experienced two major system Emergency Operating
Plan (EOP) events and a near-miss EOP event. During the 2023 Palouse Outage
and 2024 Gas & Power Supply EOPs, the telemetry system provided invaluable real-
time gas system information to key stakeholders, decision-makers, and company
executives. Without this information, critical awareness and operational decisions
would have been severely hindered. Data provided by the gas telemetry system
provided key information when responding to these events. The near-miss event at
Medford City Gate was caused when TC Energy's gas facility shut down
unexpectedly in the middle of the night. Avista's telemetry system eventually
triggered a low-pressure alarm and Avista was able to contact TC Energy about
getting the station back online. If not for Avista's alarm at this facility, it's possible that
Avista would have experienced a large gas outage similar in size to the Palouse
Outage.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 381 of 535

DocuSign Envelope ID: CAFB1AD4-8C1C-411C-BCB3-F90A5075DD01
Gas Telemetry, ER 3117
1.2 Discuss the major drivers of the business case.
The major drivers of this business case are "Performance & Capacity" and
"Mandatory & Compliance". ER 3117 provides capital funding for additions,
improvements, and replacements to the Gas Telemetry system. The system provides
monitoring (including safety related alarms and history) of pressure, temperature, gas
volumes, rupture detection, and gas flow rates at Gate Stations, Reg Stations,
pipelines, odorizers, and for Transport Customers where applicable.
Continued investment in our Gas Telemetry System is a benefit to our customers
since it allows us to continue operating our gas system safely, efficiently, and
compliantly. It is also critical in providing accurate and timely billing data for our gas
schedulers and customers.
Code of Federal Regulations (CFR) Title 49 Part 192.635 & 192.741 outline the
requirements for gas pipeline monitoring. Telemetry equipment installed and funded
under this program are critical to staying in compliance with these code requirements.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The requested funding is needed now to ensure there is capital funding necessary to
keep Avista's gas telemetry system of over 300 devices operational, effective, and
compliant. As mentioned previously, the inability to detect real-time conditions
increases the risk associated with abnormal, non-compliant, or unsafe operating
conditions. Inaccurate or untimely billing data can also result in fines, customer
complaints, and/or regulatory scrutiny. Work required to keep the system operational
includes both planned and unplanned work, so it is critical to have funding available
every year for projects.
Deferring funding is not recommended, but it's possible that the monetary and
operational risks mentioned above could be mitigated for a short period of time. There
would still be elevated risk of existing sites going offline without the funding to replace
them, but depending on the situation it may be possible to implement a temporary
work-around solution until funding is restored. New sites needed for critical monitoring
and/or compliance could also be delayed causing a similar increase in risk, but again
there could be short-term work-around solutions. The short-term solutions would not
provide the full benefits such as real-time data monitoring.
If funding is not approved, Avista runs the risk of falling out of compliance with federal
codes and losing the ability to maintain remote monitoring capabilities at critical gas
facilities. Failure to fund this program could create non-compliance situations and the
inability to monitor critical infrastructure in real time. This would result in an elevated
risk of regulatory fines, supplier fines, outages, and prolonged unsafe operating
conditions. Fines could be up to $50,000/day from suppliers and up to $257,664/day
from state regulatory commissions. System outages typically cost around $2,960 per
customer outage.z
Reference Section 2.4 for more detail on the gas outage cost of$2,960 per customer.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 382 of 535

DocuSign Envelope ID: CAFB1AD4-8C1C-411C-BCB3-F90A5075DD01
Gas Telemetry, ER 3117
1.4 Discuss how the proposed investment, whether project or program,
aligns with the strategic vision, goals, objectives and mission statement
of the organization. See link.
Avista Strategic Goals
Maintaining and improving upon the gas telemetry system has a direct impact on
those customers who rely on having accurate, timely, and reliable billing data for their
own internal processes and operations. More importantly having accurate, timely, and
reliable information about gas system conditions throughout the service territory
allows Avista to respond quickly to potentially unsafe or abnormal operating
conditions that could have an impact on the safety of our customers and/or the public.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.
Gas Planning regularly performs an analysis of the gas system to predict future
performance and identify areas of concern with respect to system capacity (i.e. low
pressure areas). These locations require seasonal (i.e. temporary) and/or permanent
telemetry devices to be installed so that the system can be monitored in real time to
avoid outages. More details regarding this periodic analysis can be provided upon
request.
In addition, the real-world data collected by the telemetry system is used as a
baseline to ensure that the department's modeling program (Synergi) is an accurate
depiction of the system. The real-world data is used to validate the model and identify
areas of the model that need to be updated/revised.
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative(e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Proposed 5-year funding for capital work to the gas telemetry system maintains our
ability to replace existing failed/malfunctioning equipment and install gas monitoring
equipment in new areas of the system as needed. The behavior and performance of
the gas system is not static, so it is critical to maintain the flexibility to install new
equipment as needed. New telemetry sites are typically determined by known gas
stream quality issues that impact pressure regulation (e.g., dithiazine) or by the
identification of low-pressure locations on the system using advanced modeling
software (i.e., Synergi models). There are also new compliance related telemetry sites
required when a gas system goes from having a single source of gas supply to having
multiple supply sources (CFR Title 49 Part 192.741) or when rupture detection
monitoring/notification is required (CFR Title 49 Part 192.635).
COST ESTIMATE BREAKDOWN: It is expected that this program will fund
approximately 3 to 10 capital projects a year depending on project complexity and
company need. Projects can range from the replacement of a reusable temporary
portable pressure recorder (—$4,000 each) to a comprehensive gate station flow
computer installation, which can include electrical work, power service, transmitters,
buried conduit, site work, and a climate-controlled building (—$75,000 each). The
Business Case Justification Narrative Template Version: February 2023 Page 5 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 383 of 535

DocuSign Envelope ID: CAFB1AD4-8C1C-411C-BCB3-F90A5075DD01
Gas Telemetry, ER 3117
median cost project is approximately $15,000 to $25,000 depending on the ability to
use solar power or not. If solar is not an option, $25,000 includes the installation of a
dedicated secondary power service or a microgenerator if grid power is not available.
The proposed budget of$100,000 per year plus inflation is based on historical
spending data, which has been sufficient in the past to meet all telemetry system
needs with respect to compliance and other telemetry system improvements.
2.2 Describe and provide reference to CIRRARR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).3
In addition to the many qualitative benefits associated with improving safety,
operational awareness of the gas system, customer service quality, and compliance,
the work performed under this program will also provide indirect quantitative cost
offsets. No direct costs offsets were identified with this program. Detailed
explanations of these cost offsets can be found in Section 2.4, and below is a 5-year
summary of these offsets compared to the proposed annual cost of the program.
ER 3117 Cost Offsets4 2025 2026 2027 2028 2029
Capital(Indirect) $0 $0 $0 $0 $0
0&M(Indirect) $209,325 $217,117 $224,910 $232,702 $240,494
Capital(Direct) $0 $0 $0 $0 $0
0&M (Direct) $0 $0 $0 $0 $0
ER 3117 Budget Proposal 2025 2026 2027 2028 2029
Capital 1 $100,000 $103,000 $106,000 $109,000 $112,000
2.3 Summarize in the table, and describe below the DIRECT offsets or
savings (Capital and O&M) that result by undertaking this investment.
There are no direct offsets associated with this program.
2.4 Summarize in the table, and describe below the INDIRECT offsets
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
0&M Manual Pressure Readings $7,792 $15,584 $23,377 $31,169 $38,961
0&M See Risk Matrix Below $201,533 $201,533 $201,533 $201,533 $201,533
3 Please do not attach any requested items to the business case, rather be sure to have ready access to such
information upon request.
4 Reference Sections 2.3 and 2.4 of the document for offset details
Business Case Justification Narrative Template Version: February 2023 Page 6 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 384 of 535

DocuSign Envelope ID: CAFB1AD4-8C1C-411C-BCB3-F90A5075DD01
Gas Telemetry, ER 3117
Indirect offsets for O&M Manual Pressure Readings were determined by calculating
the cost to send out operator qualified gas personnel to all critical monitoring points
during a cold-weather event instead of using the telemetry system. Currently, the
telemetry system allows us to remotely monitor and automatically alarm without
human involvement. If the system is allowed to degrade by not replacing critical
monitoring points, the company will be forced to send out personnel with pressure
gauges to each of these critical locations during cold weather events. O&M
expenses increase over time as more telemetry equipment fails/malfunctions
without being replaced. Assumed 60 critical cold weather monitoring points, 3
devices fail per year (20-year life of devices), 10 days of monitoring per cold
weather event, and one cold weather event every 3 years'.
The risk matrix below represents a summary of the indirect cost offsets associated
with the work performed under this business case budget. The probabilities
associated with the risk increase over time if nothing is done to address existing
obsolete or broken equipment, as well as the need for new monitoring sites as the
gas system operating behavior continues to evolve. The budget proposed in this
business case seeks to mitigate this risk matrix by providing a financially
responsible plan to address these needs over a reasonable amount of time.
The cost of an outage was estimated at $2,960 per customer 6. This cost includes
the cost for Avista to restore service and the potential economic impacts to the
customer. The calculation assumes that restoration will be completed within 24
hours, which is Avista's restoration goal. A severely damaged station may take
longer than 24 hours to repair and bring back into service.
s Reference"Offset Calculations&Assumptions_ER 3117 2024.xlsx"document for details on indirect costs
6 The Interruption Cost Estimate(ICE)Calculator was used to estimate the economic impacts to the customer
at $116 per hour per customer. An estimated restoration cost of$176 per customer is based on the actual
restoration costs incurred during the 2022 Crestline outage in Spokane. Therefore the total cost per customer
is estimated to be$116 x 24 hours+$176=$2,960.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 385 of 535

DocuSign Envelope ID: CAFB1AD4-8C1C-411C-BCB3-F90A5075DD01
Gas Telemetry, ER 3117
Risk Probability Definitions: Risk Probability for Calculating Indirect Offsets:
-Risk event expected to occur 75%
High(H) Risk event more likely to occurthan not 50%
Probable(P) Risk event may or may not occur 25%
Low(L) Risk event less likely to occur than not 10%
Very Low(VL) Risk event not expected to occur 1%
Risk Avoidance OverTime and the Cost of Doing Nothing:
Risk Over Time
10 15+ Worst Case Cost
# Risk 1 Year 2 Years 5 Years Years Years Cost Estimate Estimate
1 Regulatory Fines in response VL VL L P H $257,664 per day perviolation(Max) $ 2,576,627
to a preventable incident $2,576,627Total(Max)
2 Customer Outage VL L P H $2,960/outage(ex.-$1.5 million for $ 1,500,000
500 outages)
3 Innaccurate billing L P H $50,000/dayfine forAvista or $ 350,000
Customer Agent
$250,000 to$2 Mil lion for Lost ti me,
4 Customer&Public Safety VL VL L P H healthcare,lawsuits,system damage, $ 2,000,000
etc.
O&M Indirect Cost offsets over the next 5 years:
0&M Annual Indirect Offsets*
# Risk 2025 2026 2027 2028 2029 Total Cost per Risk Item
1 Regulatory Fines $ 51,533 $ 51,533 $ 51,533 $ 51,533 $ 51,533 $ 257,663
2 Customer Outage $ 75,000 $ 75,000 $ 75,000 $ 75,000 $ 75,000 $ 375,000
3 Innaccurate billing $ 35,000 $ 35,000 $ 35,000 $ 35,000 $ 35,000 $ 175,000
4 Customer&Public Safety $40,000 $40,000 $40,000 $40,000 $ 40,000 1 $ 200,000
TOTALS $201,533 $201,533 $201,533 $201,533 $201,533 $ 1,007,663
*Took probability at 5 year mark,multiplied by worst case cost,and then divided by 5 for cost/year over 5 years
Business Case Justification Narrative Template Version: February 2023 Page 8 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 386 of 535

DocuSign Envelope ID: CAFB1AD4-8C1C-411C-BCB3-F90A5075DD01
Gas Telemetry, ER 3117
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those
additional risks to Avista that may occur if an alternative is selected.
See below for list of alternatives. None are recommended by Gas Engineering. The
recommended funding of$100,000 is enough to complete critical work while also
being a manageable workload for Avista's limited telemetry engineering and technical
labor resources.
Alternative 1: Reduce 5-year program funding to $50,000/year
Reducing funding and replacing equipment at a slower rate increases the probability
of failed equipment and the potential consequences associated with not being able to
monitor the system and provide timely billing data to customers. This a reasonable
alternative that could be absorbed over a short period of time (e.g. one year), but it's
still not recommended. In addition to creating more risk, deferring projects can create
future workload imbalances for Avista's limited Gas Telemetry resources.
Alternative 2: Defer all program funding for a year
Deferring all program funding to a future year creates more risk than alternative 1 and
is not recommended for the reasons stated above. Long term this could be less
disruptive than alternative 1 assuming full funding is restored the following year, but in
the short term it is more risky and impactful than alternative 1 (Alternative 1 is
reduced funding for all five years).
Alternative 3: Eliminate all 5-year funding (i.e. do nothing)
Eliminating all funding and doing nothing over the next five years is not a reasonable
option and poses significant safety, operational, reliability, financial, regulatory, and
public relations risk. There are also resource concerns with the potential of having
severely imbalanced workloads in the future if all work has been put off for multiple
years.
Option 2025 Capital Cost Start Complete
Recommended: Fund program at $100,000 January December
proposed budget of$100,000/year
Alternative 1: Reduce 5-year program $50,000 January December
funding to $50,000/year
Alternative 2: Defer all program funding $0 January December
for one year
Alternative 3: Eliminate all 5-year funding $0 January December
Business Case Justification Narrative Template Version: February 2023 Page 9 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 387 of 535

DocuSign Envelope ID: CAFB1AD4-8C1C-411C-BCB3-F90A5075DD01
Gas Telemetry, ER 3117
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
Tracking of program effectiveness will be accomplished using Gas Engineering's
DNV Synergi models, compliance audits, monthly alarm reviews, telemetry
meetings, and event/incident after-action reviews (e.g. EOPs, cold weather events,
etc.). The Synergi model is used to proactively identify existing or future needs for
telemetry with respect to system reliability and model validation. Internal and
external audits help to ensure compliance with telemetry regulatory requirements.
Monthly alarm reviews and telemetry meetings provide regular forums for subject
matter experts to review safety and alarm related events on the system, which can
bring awareness to monitoring gaps in the system. Event/incident after-action
reviews provide real-world feedback on the performance of the telemetry system
and whether there are any gaps in what is being monitored. All these qualitative
and quantitative metrics provide feedback into the overall effectiveness of the
program.
2.7 Please provide the timeline of when this work is schedule to
commence and complete, if known.
It is expected that this budget will continue indefinitely since the gas telemetry
system will continue to need new sites and replacement equipment as long as the
gas system is operational. Existing telemetry devices have a range of vintages and
performance, so there is continuous need to replace failed/malfunctioning
equipment as well as obsolete/end-of-life equipment.
Field work completed under this budget occurs throughout the year as equipment is
delivered and the projects are scheduled. As a result, multiple sites are expected to
be installed every quarter under this program and are typically used and useful
immediately upon installation.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of
the business case, and how such oversight will occur.
Gas Engineering in consultation with other groups such as Gas Operations, Gas
Control, Gas Supply, and Billing develops the planning, implementation, and
performance of the telemetry system. Gas Engineering is responsible for identifying
and prioritizing the work, getting approval via the Capital Project Request (CPR)
procedure, and initiating changes via the Gas Management of Change (GMOC)
process where applicable such as any instrumentation sending data to SCADA for
use by Gas Control.
If any changes to the budget for the year are needed, the Business Case Owner
proposes a budget change and justification that must get approval from the
Business Case Sponsor before it is brought before the Capital Planning Group.
Business Case Justification Narrative Template Version: February 2023 Page 10 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 388 of 535

DocuSign Envelope ID: CAFB1AD4-8C1C-411C-BCB3-F90A5075DD01
Gas Telemetry, ER 3117
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed ER 3117 Gas Telemetry and agree with
the approach it presents. Significant changes to this will be coordinated with and approved
by the undersigned or their designated representatives.
D. s d by.
Ma 1
Signature: g�w� Date: y-
21-2024 10:07 AM PDT
.F
Print Name: Jeff Webb
Title: Mgr Gas Engineering
Role: Business Case Owner
Signature: Q�iaa by.
Date:May-21-2024 12:54 PM PDT
d�d'dZ9STT3d5Ed8'_.
Print Name: Alicia Gibbs
Title: Director of Natural Gas
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 11 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 389 of 535

DocuSign Envelope ID:B75BA67A-8C3F-4287-9A80-EC520F9E53EE
Gas Transient Voltage Mitigation Program, ER 3010
EXECUTIVE SUMMARY
Federal code CFR 49.192.467(F) requires that pipelines located near electric transmission
systems must be protected from damage caused by faults on the transmission system. Avista
has experienced safety issues, including fires at regulator stations and damaged equipment,
due to electrical arcing caused by faults on adjacent electric power systems. Fault events of
electric distribution or transmission systems can create momentary high voltage levels on
nearby steel gas piping. This is due to either power system current arcing onto the pipe, or
more typically, through electromagnetic induction. Sometimes gas systems experience `steady-
state' voltage. In these situations, there is an induced voltage on the pipe at all times that
comes from nearby electric lines. These situations don't cause arcing, but the voltage level can
be high enough to be a personnel safety concern, as well as a cause of pipeline corrosion.
The purpose of this program is to identify high pressure gas piping systems that are at risk of
these conditions, identify gas systems that have high steady state voltage, and to then install
mitigative measures to reduce the risk from these hazards. These efforts will protect the pipeline
and equipment from being damaged, while also reducing employee exposure to touch voltage
hazards. Common approaches to mitigation include the installation of grounding systems,
gradient control mats, and other equipment that reduces the presence of dangerous voltage
differentials on pipeline facilities.
This work is a direct effort to prioritize the safety of Avista's employees. Avista's customers and
contactors also benefit from the improved safety of these systems as some of Avista's
infrastructure is aboveground and therefore accessible to the general public.
VERSION HISTORY
Version Author Description Date
1.0 Jeff Webb Initial draft of original business case 1211712021
1.2 Tim Harding Updated to the refreshed 2022 Business Case Template 910112022
1.3 Shontelle Wilson Updated to the refreshed 2023 Business Case Template 4/6/2023
2.3 Tim Harding Updated to the refreshed 2023 Business Case Template 4/18/2023
2.4 Tim Harding Updated for 2024 Business Case 4115124
BCRT Team
BCRT Member Has been reviewed by BCRT and meets necessary requirements 4117124
Business Case Justification Narrative Template Version: February 2023 Page 1 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 390 of 535

DocuSign Envelope ID:B75BA67A-8C3F-4287-9A80-EC520F9E53EE
Gas Transient Voltage Mitigation Program, ER 3010
GENERAL INFORMATION
YEAR PLANNED SPEND PLANNED TRANSFER TO
AMOUNT ($) PLANT ($)
2025 250,000 250,000
2026 250,000 250,000
2027 250,000 250,000
2028 250,000 250,000
2029 250,000 250,000
Project Life Span 10 Year
Requesting Organization/Department B51 —Gas Engineering
Business Case Owner I Sponsor Tim Harding /Jeff Webb Alicia Gibbs
Sponsor Organization/Department B51 —Gas Engineering
Phase Execution
Category Mandatory
Driver Mandatory& Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
Buried steel natural gas pipes in close proximity to electric conductors can have high AC
voltage present. The power lines induce this voltage on the pipe, either constantly, or
during fault conditions. Industry standards, including AMPP Standard Practice SP0177
suggests that, for safety reasons, steady-state pipeline voltages should not exceed 15
volts. Systems experiencing voltages higher than this should be studied, and mitigation
measures put in place to reduce system voltages.
Federal code CFR 49.192.467(F) requires that pipelines located near electric transmission
systems must be protected from damage caused by faults on the electric transmission
system. The mitigation schemes and equipment used to address fault voltage concerns
often overlaps what is used to address steady-state voltage hazards. Fault incidents on
nearby electric systems can lead to a significant voltage rise on the gas main — hundreds
or thousands of volts. Gas systems are not designed to support these voltage levels, and
because of this, electric arcing between components can occur. This arcing damages
equipment, and can burn holes through gas-carrying components, leading to gas leaks
and fires. Personnel working on these gas systems during a fault event can be exposed
to fatal voltage levels.
Business Case Justification Narrative Template Version: February 2023 Page 2 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 391 of 535

DocuSign Envelope ID:B75BA67A-8C3F-4287-9A80-EC520F9E53EE
Gas Transient Voltage Mitigation Program, ER 3010
Between 2017 and 2021, there were five electric fault incidents that caused arcing on gas
facilities, resulting in blowing gas and fire. Each one of these incidents caused equipment
damage and required emergency response from company personnel.
The constant presence of AC voltage on a pipeline can also lead to corrosion. AMPP
Standard Practice SP21424 addresses this issue and gives guidance on testing,
monitoring, and mitigation of this issue. AC corrosion can occur on pipelines with less
than 15 volts, so systems without shock hazard risks may still have this issue. Because of
this, AC corrosion risks must be monitored separately from the other two risks listed
above.
1.2 Discuss the major drivers of the business case.
The primary driver for this business case is Mandatory & Compliance. This program
addresses safety hazards and integrity concerns on high pressure steel gas mains. This
benefits customers by reducing corrosion risks, as well as eliminating hazardous voltage
levels on above-ground gas facilities —facilities that sometimes are accessible to the
general public.
Based on Federal code CFR 49.192.467(F) "Where a pipeline is located in close proximity
to electrical transmission tower footings, ground cables or counterpoise, or in other areas
where fault currents or unusual risk of lightning may be anticipated, it must be provided
with protection against damage due to fault currents or lightning, and protective measures
must also be taken at insulating devices." This business case supports this federal code
requirement. Federal fines for not meeting code requirements are not prescribed but can
range to a maximum daily fine of$257,664 per day and a maximum total of$2,675,627
per violation.
Fault events cause damage to the gas system and can also cause unsafe conditions
when gas is released and is ignited. By mitigating areas that are prone to damage, the
likelihood of these incidents occurring is reduced. The installation of mitigation equipment
reduces O&M expenses. The two main reductions in these costs are due to fewer fault
damage incidents that require emergency response, and the reduced need to follow
special safety procedures when doing construction or maintenance on the system. The
average cost savings per year in O&M is $7,200.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
There are multiple gas systems with known high-voltage hazards present. Between 2017
and 2021, there were five electric fault incidents that caused arcing on gas facilities,
resulting in blowing gas and fire. Not mitigating these systems will result in the continued
prevalence of electric fault incidents, as well as exposing employees to potentially
hazardous steady-state pipeline voltages. Mitigation methods described in this program
are a proven way to resolve these issues. This work must be done, and delaying the
process puts system integrity and workers at an increased level of risk for each year of the
delay.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 392 of 535

DocuSign Envelope ID:B75BA67A-8C3F-4287-9A80-EC520F9E53EE
Gas Transient Voltage Mitigation Program, ER 3010
1.4 Discuss how the proposed investment, whether project or program,
aligns with the strategic vision, goals, objectives and mission statement
of the organization. See link.
Avista Strategic Goals
This program aligns with Avista's organizational focus to maintain safe and reliable
infrastructure to achieve optimum life-cycle performance, in a safe manner for our
customers. As stated in the summary, equipment damage and fires have resulted in an
unsafe environment. This program focuses on pipelines that may be damaged by nearby
electric systems, or those that will expose employees and the general public to unsafe
voltage levels.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 393 of 535

DocuSign Envelope ID:B75BA67A-8C3F-4287-9A80-EC520F9E53EE
Gas Transient Voltage Mitigation Program, ER 3010
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
As previously stated, five electric fault incidents have already occurred on Avista's gas
system. The following image is of pipe damage that occurred from a fault incident that
occurred on or around the date of 1/24/14.
Image 1. Pipe Damage from Fault Incident
The next image documents the ignition that occurred as a result a different fault incident in
2017.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 394 of 535

DocuSign Envelope ID:B75BA67A-8C3F-4287-9A80-EC520F9E53EE
Gas Transient Voltage Mitigation Program, ER 3010
7� .., ' . .
rt
S i {
K
r
Image 2. Ignition from Fault Incident
Similar photographic evidence documents the results from the other four fault incidents. To
date, two studies have been performed by consulting engineering firms on the specific gas
systems that have experienced multiple arcing incidents due to electric system faults.
These studies have yielded reports and mitigation designs.
These studies use computer models to simulate the interaction between power lines and
nearby buried steel pipelines. The computer models take into account the locations and
characteristics of the power and gas systems, as well as the soil characteristics. The
software simulates both steady-state conditions and fault events that occur on the electric
system. It then determines the AC (Alternating Current) voltage levels that will be on the
pipeline at these times.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 395 of 535

DocuSign Envelope ID:B75BA67A-8C3F-4287-9A80-EC520F9E53EE
Gas Transient Voltage Mitigation Program, ER 3010
For the two studies conducted, the computer simulations showed worst-case pipeline
voltages of 2,000 Vac and 4,000 Vac on the two different systems. Voltage levels of this
magnitude can cause arcing at gas equipment and represent a fatal shock hazard.
The second part of each study involved putting together a mitigation design. High voltage
hazards can be mitigated in different ways. There are three general schemes that are
used to reduce these hazards:
1. Grounding —Steel gas pipes are coated to reduce corrosion. The better the coating on
the pipe, the higher voltage the pipe will experience due to nearby power lines. By
grounding the steel pipeline to the adjacent soil, the voltage rise on the pipeline is
reduced. Gas systems have cathodic protection systems, which aren't compatible with
a traditional grounding system. It's beyond the scope of this document to describe the
details but note that special grounding designs are required.
2. Equipotential Mats —At above-ground gas facilities, such as regulator stations,
personnel can come in contact with gas piping. If the piping is at a high voltage level,
a hazard can exist when the piping is touched. The danger exists because there is a
voltage difference between the pipe surface (hand contact) and the ground (foot
contact). This voltage difference causes current to flow through the body, resulting in
a shock. Equipotential mats are a metal grid that is placed 6-12" below ground in
areas around above-ground gas pipes. The grid is connected to the pipe with wires. If
the pipe voltage rises, the grid will rise to the same level. This eliminates the high
voltage difference between the hands and feet, eliminating the shock hazard.
3. Insulation —Similar to the example above, this is another way to reduce shock hazards
that can occur when contacting gas systems. In this case, 6-12" of high resistance
gravel is added in areas around above-ground gas pipes. The resistance of the gravel
is high enough that only a non-lethal current level would flow through the body if the
gas pipe was touched.
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The requested level of spending for this program allows the high priority projects on
systems with known hazards to be completed. Outside consulting engineering firms have
performed studies and helped identify which mitigation approach is appropriate for each
known hazard area. As previously stated, mitigation approaches include: grounding,
equipotential mats, and insulation. These projects are addressing serious system integrity
and safety issues. A reduced level of funding will slow the installation of mitigation
equipment, and delay resolving known system integrity and safety risks. For projects to be
considered in this program, they must exhibit symptoms that would put them in violation of
the Codes and Standards listed in Section 1.1 of this document. As projects are
completed, these systems will become compliant with these requirements. As more
systems are addressed, fewer will require mitigation and the program budget can be
reduced.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 396 of 535

DocuSign Envelope ID:B75BA67A-8C3F-4287-9A80-EC520F9E53EE
Gas Transient Voltage Mitigation Program, ER 3010
2.2 Describe and provide reference to CIRRARR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
Execution of this program ensures that Avista avoids the risk of federal fines resulting
from noncompliance with Federal code CFR 49.192.467(F). Federal fines for not meeting
code requirements are not prescribed but can range to a maximum daily fine of$257,664
per day and a maximum total of$2,675,627 per violation.
This program will also directly reduce O&M expenses related to extensive safety
procedures currently required each time an employee works on a gas system that has
potential voltage hazards, and the O&M labor that results when fault damage occurs.
These are expanded on further in section 2.3, but average approximately $9,075 each
year.
This business case is intended to address risk reduction and Avista's ability to maintain
compliance in the states we operate within. The program is aimed at maintaining safe and
reliable systems for our employees and our customers. Additional risk mitigation that is not
currently quantified is the serious potential of Avista employee or customer contact with
fatal voltage levels that may be present on the gas system.
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital None $0 $0 $0 $0 $0
0&M Labor related to extra safety $5,200 $5,400 $5,600 $5,700 $5,900
procedures
0&M Labor and materials to respond $3,500 $3,600 $3,700 $3,800 $3,900
to fault damage events and
make repairs.
The installation of mitigation equipment reduced O&M expenses. The two main
reductions in these costs are due to fewer fault damage incidents that require emergency
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2023 Page 8 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 397 of 535

DocuSign Envelope ID:B75BA67A-8C3F-4287-9A80-EC520F9E53EE
Gas Transient Voltage Mitigation Program, ER 3010
response, and the reduced need to follow special safety procedures when doing
construction or maintenance on the system.
When a fault event occurs that damages equipment, immediate response is needed by an
Avista First Responder. There is then follow-up required by Gas Engineering to determine
the cause of the incident.
In gas systems with known high voltage hazards, special safety procedures are required
when contacting gas facilities that have not been mitigated. These safety procedures can
include the use of rated rubber gloves, or the use of portable equipotential mats. These
mats reduce touch voltage hazards and are similar to the gradient mats described in
section 1.5. Setting up these mats is time consuming and once a facility has had
permanent mitigation installed their use is no longer required. In addition, safety
procedures require ongoing training for every employee working on the affected system.
2.4 Summarize in the table, and describe below the INDIRECT offsets
(Capital and OW) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $0 $0 $0 $0 $0
00 Labor and materials to repair $3,700 $3,800 $3,900 $4000 $4,200
system leaks caused by AC
corrosion
The installation of mitigation systems reduces pipeline voltage. This decreases the
chance of AC corrosion occurring, thereby reducing the chance of leaks from occurring
on the pipe. High voltage hazards on pipelines create system integrity and safety risks.
The costs associated with some of these risks can be hard to predict. Below are
estimated cost ranges related to different risks.
Risk Probability Definitions:
Risk event expected to occur
High(H) Risk event more likely to occurthan not
Probable (P) Risk event may or may not occur
Low(L) Risk event less likely to occurthan not
Very Low(VL) Risk event not expected to occur
Risk Avoidance Over Time and the Cost of Doing Nothing:
Risk Over Time
1 2 5 10 1 15+
# Risk Year Years Years Years Years Cost Estimate
1 Regulatory Fines L L P p H $257,664 perday perviolation(Max)*
$2,576,627 Tota I (Max)*
2 Pipeline Leak L P I P H H $5,000to$150,000 per site(site dependent)
3 Pipeline Failure&Outage VL L L H H $150,000to$3,000,000 per site(site dependent)
4 Negative Reputation L L P H H Erosion of PUC and Public trust
5 Employee&Public Safety H H H Lost time, lawsuits, healthcare,etc.(varies)
Business Case Justification Narrative Template Version: February 2023 Page 9 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 398 of 535

DocuSign Envelope ID:B75BA67A-8C3F-4287-9A80-EC520F9E53EE
Gas Transient Voltage Mitigation Program, ER 3010
*Regulatory fines present a daily and overall maximum value per violation in
accordance with 49 CFR Part 190.223. However, these values are not necessarily
an accurate representation of how much Avista would be fined for any specific
violation. The actual amount is likely to be much lower since Avista has an ongoing
reputation and history of investing in programs related to safety and non-compliance
issues. However, it is a bookend reminder from which to characterize the regulatory
risk associated with chronic and/or egregious non-compliance, especially in the event
of a pipeline safety incident (i.e. failure). Therefore, Avista must continue to
demonstrate an ongoing commitment to compliance and pipeline safety to ensure
favorable future outcomes with respect to regulatory penalties. (Actual penalty
amount is at the discretion of the state or federal agency).
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those
additional risks to Avista that may occur if an alternative is selected.
Alternative 1: Fund program at lower level
The current funding level per year is the minimum funding level required to address the
highest priority mitigation projects. Any funding level below this amount means that high
priority projects will not be addressed. Not mitigating the system will result in excessive
prevalence of electric fault incidents. During these incidents, electric arcing can occur
on gas facilities. This can, and has, lead to gas leaks and fires. Knowingly allowing
dangerous incidents like this to continue is not acceptable and leads to increased risk to
employee and customer safety.
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how
will success be measured).
The completion of mitigation projects under this budget will have a positive impact on
Gas Operations. Due to the current known safety issue, additional burdensome
procedures are required when company personnel do construction and maintenance
work on these systems. After the mitigation projects are complete, many of these
additional safety procedures will no longer need to be required.
This program is being tracked and communicated through documentation updated by
Gas Engineering in the SharePoint site. Identified projects as well as the status of these
projects (complete, in progress, etc.) can be found on this document. Each completed
project documents the success of this program in reducing the risk of a fault condition
occurring, and/or of an individual coming into contact with potentially hazardous voltage
levels.
Business Case Justification Narrative Template Version: February 2023 Page 10 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 399 of 535

DocuSign Envelope ID:B75BA67A-8C3F-4287-9A80-EC520F9E53EE
Gas Transient Voltage Mitigation Program, ER 3010
2.7 Please provide the timeline of when this work is schedule to
commence and complete, if known.
This is designed as a 10-year program covering all three states. Projects that are
performed under this budget can be both large and small. Smaller projects will typically
transfer to plant monthly, while larger projects that take several months to complete will
transfer to plant upon project completion. As completion rates occur, the timeline and
forecasts will be updated accordingly.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of
the business case, and how such oversight will occur.
An engineer in the Gas Engineering group serves as the AC Mitigation Program Manager.
The Program Manager oversees projects designs, construction, and the program budget.
The Program Manager meets quarterly with representatives from Gas Engineering,
Cathodic Protection, and Gas Compliance to review current and planned projects. Project
are prioritized by the group. If any changes to the budget for the year are needed, the
Program Manager proposes a budget change and justification that must get approval from
the Business Case Sponsor before it is brought before the Capital Planning Group. If
additional funds are not approved, then the remaining work is reduced to remain within
budget.
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Transient Voltage Mitigation
Program, ER 3010 and agree with the approach it presents. Significant changes to this will
be coordinated with and approved by the undersigned or their designated representatives.
o i d by:
Signature: g;w.0 Date: May-01-2024 4:43 PM PDT
�5591FFR.,v5d5#�...
Print Name: Jeff Webb
Title: Mgr Gas Engineering
Role: Business Case Owner
o Si d by:
Signature: aUaa ebbs Date: May-02-2024 18:04 AM PDT
Print Name: Alicia Gibbs
Title: Director of Natural Gas
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 11 of 11
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 400 of 535

<Project Name>ckson Prairie Natural Gas Storage Facility
EXECUTIVE SUMMARY
Avista co-owns a natural gas storage reservoir, Jackson Prairie (JP) Underground Natural Gas
Storage Facility(JP). The JP natural gas storage facility is a critical component of Avista's overall
natural gas supply strategy. Avista does not own any natural gas wells or supply facilities. The
Company purchases all gas supply on behalf of its customers from multiple market trading hubs
including AECO, Sumas, and Rocky Mountains. Avista has also secured adequate gas pipeline
transport rights to ensure that all purchased gas can be reliably moved to serve customer load. In
order to reduce the exposure to market prices, Avista also owns a third of the overall storage
capacity at the JP gas storage facility in southwest Washington. Having gas storage allows Avista
to inject gas when prices are lower and then withdraw gas during the winter peak use months when
market prices are historically higher in order to keep customer rates affordable. All three owners
share equally in the annual expense costs to operate the facility and the capital investments to
improve operations, meet regulatory requirements and reduce future risks.
The three owners have contracted with PSE to operate the JP storage facility. The plant operations
management creates an annual and five-year capital budget plan to ensure the storage facility is
operated safely, reliably, and meets all federal and state regulatory requirements. Each owner has
a representative that meets at least quarterly with the operating staff to review current operating
performance, discuss current project spend and approve annual and five-year budget plans. The
Director of Energy Supply represents Avista on the Owners Committee and approves all annual
and five-year budgets after consulting with the Gas Supply department. The Manager of Gas
Design is Avista's alternate representative on the Owners Committee and is also consulted on all
budget decisions.
Without the JP gas storage facility, Avista customers would be completely exposed to market
conditions that can be extremely volatile at times. The ability to inject gas into storage during
lower priced time periods and withdrawal gas during high prices or peak load periods allows Avista
to reduce customers' exposure and risks to real-time market prices and improve reliable service to
customers. Avista's one third share of JP allows the utility to meet 100 percent of its customers'
peak winter demand with the facility's stored reserves.
Business Case Justification Narrative Template Version: February 2023 Page 1 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J.DiLuciano,Avista
Schedule 3,Page 401 of 535

<Project Name>ckson Prairie Natural Gas Storage Facility
VERSION HISTORY
Version Author Description Date
1.0 Scott Kinney Annual Business Case Update 811112023
2.0 Kevin Holland 2024 Business Case Update 9/27/2023
BCRT BCRT Team Has been reviewed by BCRT and meets necessary requirements Steve 9/28/2023
Member Carrozzo
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2024 $2,397,000 $2,397,000
2025 $2,386,000 $2,386,000
2026 $2,386,000 $2.386,000
2027 $2,371,000 $2,371,000
2028 $2,368,000 $2,368,000
Project Life Span 5 Years
Requesting Organization/Department Natural Gas Energy Resources
Business Case Owner I Sponsor Kevin Holland/Scott Kinney
Sponsor Organization/Department Energy Resources
Phase Execution
Category Program
Driver Performance & Capacity
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
i. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
This request is for the ongoing funding for the capital costs associated with the JP operations.
Avista is a one-third owner of the facility. The three owners have contracted with PSE to operate
the JP storage facility. The plant operations management creates an annual and five-year capital
budget plan to ensure the storage facility is operated safely,reliably, and meets all federal and state
regulatory requirements. Without the JP gas storage facility, Avista customers would be
Business Case Justification Narrative Template Version: February 2023 Page 2 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 402 of 535

<Project Name>ckson Prairie Natural Gas Storage Facility
completely exposed to market conditions that can be extremely volatile at times. The ability to
inject gas into storage during lower priced time periods and withdrawal gas during high prices or
peak load periods allows Avista to reduce customers' exposure and risks to real-time market prices
and improve reliable service to customers. Avista's one third share of JP allows the utility to meet
100 percent of its customers' peak winter demand with the facility's stored reserves.
1.2 Discuss the major drivers of the business case.
The drivers for funding JP are Performance and Capacity. JP provides solutions
for the following gas supply needs:
• Stored gas supply that enables Avista to reliably serve customers during peak load
demand.
• Risk mitigation for shielding customers from extreme daily gas price volatility during
cold weather or other events affecting the natural gas commodity market.
• A mechanism for purchasing gas at lower prices during off-peak periods for use during
high-cost periods.
All commodity price benefits resulting from the utilization of JP are passed along to the
customer through the annual PGA filings.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
JP is a functioning natural gas storage project that has critical ongoing capital funding
requirements for ensuring continuous safe and reliable operation of the facility. Not
funding JP at the requested levels increases a number of risks for plant operations
including, but not limited to, non-compliance with Pipeline and Hazardous Materials
Safety Administration's underground storage safety mandates, deliverability during peak
demand periods, reduced physical plant security, reduced efficiency of plant output, or
increased likelihood of component failure resulting in unplanned outages.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
JP is a critical integrated supply resource for our natural gas business. JP helps enable
the delivery of natural gas energy safely, responsibly, and affordably to our customers.
Without JP customers would be exposed to market price volatility risk and the need to
acquire more pipeline transport capacity to the different gas supply regions.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 403 of 535

<Project Name>ckson Prairie Natural Gas Storage Facility
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
The JP natural gas storage facility is a critical component of Avista's overall natural
gas resources for peak day events as discussed in the Avista 2023 Natural Gas
IRP. Without this resource and associated volumes, Avistas system is at risk of
unserved demand during these peak day events where cold weather and risk to
persons and property increase. Additionally, this facility is a least cost option and
without it would likely lead to much greater costs for our customers. The 2023
Natural Gas IRP also shows that if JP were removed from the resource mix, and
only currently viable technology was available to the system, load in Oregon and
Washington is removed through electrification as the least cost option. Also,
incremental RNG is purchased to supply peak day needs as the interstate pipeline
capacity is maxed out during these cold events and additional capacity is not
currently available for subscription on either major pipeline.
PRS from 2023 IRP (includes JP) $5 B
PRS (removes Synthetic $11 B
Methane and JP)
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 404 of 535

<Project Name>ckson Prairie Natural Gas Storage Facility
1,400,000
—PRS-No JP Storage + No Synthetic Methane
1,200,000
1,000,000
61>
u) 800,000
0
Y)
0 600,000
O
400,000
200,000
0
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N N N N N N N M C O C' O C CM M M M C` M C) C) CD C) CD CD
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N N N N N N N N N N N N N N N N N N N N N N N
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The JP natural gas storage facility is a critical component of Avista's overall natural gas
supply strategy to ensure reliable and affordable delivery of gas to meet customer needs.
Avista does not own any natural gas wells or supply facilities. The Company purchases
all gas supply on behalf of its customers from multiple market trading hubs including
AECO, Sumas, and Rocky Mountains. Having gas storage allows Avista to inject gas
when prices are lower and then withdraw gas during the winter peak use months when
market prices are historically higher in order to keep customer rates affordable.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 405 of 535

<Project Name>ckson Prairie Natural Gas Storage Facility
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
The benefits of JP are outlined in detail in the 2023 Natural Gas IRP. The chart above
shows the expected future demand, and available resources, including Jackson Prairie
costs and demand with a least cost selection in the Preferred Resource Strategy (PRS)
compared to the removal of JP as a resource choice. The ability to capture intrinsic values
from summer to winter commodity prices paired with the on-demand ability to provide
supply on peak days is apparent in the annual price differential. While extrinsic value can
be operationally available depending on strategy, at this time extrinsic value is not
specifically considered.
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
0&M $ $ $ $ $
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
0&M $ $ $ $ $
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 406 of 535

<Project Name>ckson Prairie Natural Gas Storage Facility
2.5 DESCRIBE IN DETAIL THE ALTERNATIVES, INCLUDING PROPOSED COST
FOR EACH ALTERNATIVE, THAT WERE CONSIDERED, AND WHY THOSE
ALTERNATIVES DID NOT PROVIDE THE SAME BENEFIT AS THE CHOSEN
SOLUTION. INCLUDE THOSE ADDITIONAL RISKS TO AVISTA THAT MAY
OCCUR IF AN ALTERNATIVE IS SELECTED.
No cost-effective alternatives exist for replacing JP. Because JP is a unique solution that
provides benefits/solutions for an array of supply needs, it would likely require multiple
business solutions to replace the resource functionality provided by JP, none of which
could fully duplicate the benefits of JP nor be cost competitive with JP.
Alternative 1:
N/A
Alternative 2:
N/A
Alternative 3:
N/A
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
The storage project is continually managed and monitored for optimal storage volume,
injection and withdrawal performance, and other key operational metrics. An operations
report is submitted to the JP Management Committee on a monthly basis. Additionally,
the report provides a current and projected budget status.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
The annual capital spending for JP includes multiple capital improvement investments,
which become used and useful at the end of each budget year.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 407 of 535

<Project Name>ckson Prairie Natural Gas Storage Facility
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
Internal stakeholders include the Director of Energy Supply, Gas Supply and Gas
Engineering. External stakeholders who directly interface with the business case include
the two other ownership partners; PSE and Williams-NWP. Additionally, the Pacific
Northwest (PNW) natural gas market and pipeline operation are directly affected by JP
operations. JP provides critical supply delivery functionality to the PNW pipeline grid,
especially during peak demand times.
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Jackson Prairie Natural Gas Storage
Facility and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.
Signature: Xlavl"� Date: Oct. 9, 2023
Print Name: Kevin Holland
Title: Director of Energy Supply
Role: Business Case Owner
Signature: cer-- � Date: October 9, 2023
Print Name: Scott Kinney
Title: Vice President of Energy
Resources
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 8 of 8
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 408 of 535

Docusign Envelope ID:825E3A90-F88A-407A-8DD3-5B461 133ADA81
New Revenue - Growth
EXECUTIVE SUMMARY
Avista defines these investments as "customer requests for new service connections,
line extensions, transmission interconnections, or system reinforcements to serve a
single large customer." We have often in the past referred to new service connects as
"growth," as in growth in the number of customers, however, these investments are
beyond the control of the Company, and as such they do not reflect a plan or strategy
on the part of Avista. Responding quickly to these customer requests is a requirement
of providing utility service. Typical projects include installing electric facilities in a new
housing or commercial development, installing or replacing electric meters, or adding
street or area lights per a request from an individual customer, a city, or county agency.
As would be expected, fluctuation in the number of new customer connections is largely
dependent on local economic conditions both in the housing and business sectors.
New customers are served for electric in WA and ID and gas in WA, ID, and OR.
Both connects forecast and 12-month rolling Cost Per Service information are used to
calculate costs directly related to providing service to customers. Electric and Gas
devices are also included in this business case - Meters, Transformers, Gas
Regulators, and ERTs (Encoder Receiver Transmitter). Many of these Meters,
Transformers, and ERTs are used as replacements for Wood Pole Management, and
Periodic Meter Changes, for example.
Growth Business Case Funds request:
ELEC&GAS 2025 1 2026 2027 2028 1 2029
Connects Forecast:Res&Comm 9,434 1 9,138 9,106 9,121 1 9,121
Extensions,Services 50,001,574 48,511,564 49,384,495 49,258,202 49,258,202
Lighting 2,471,078 2,471,078 2,471,078 2,471,078 2,471,078
Meters&Devices 12,678,791 13,291,389 13,641,025 14,306,324 15,046,589
Transformers&Network Protectors 20,750,000 21,750,000 23,850,000 26,160,000 28,701,000
Business Case Total 85,901,442 86,024,030 89,346,598 92,195,604 95,476,869
The 5 yr average annual spend for this business case has been around $89M.
Requests for service are variable in number and in cost, sometimes requiring significant
investment for system reinforcements such as gas regulator stations and electric
distribution infrastructure. This funds request is based on ordinary expectation as
supported by forecast and input from electric and gas operations engineers.
For 2025, there are updated impacts to Growth costs, see 2.2 for more detail.
VERSION HISTORY
Business Case Justification Narrative Template Version: February 2023 Page 1 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 409 of 535

Docusign Envelope ID:825E3A90-F88A-407A-8DD3-5B461 133ADA81
New Revenue - Growth
Version Author Description Date
1.0 Joe Wright Initial draft of original business case 5102124
BCRT Team
BCRT Memember-Joe Has been reviewed by BCRT and meets necessary requirements 5102124
Wright
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT($)
2025 $85,901,442 $85,901,442
2026 $86,024,030 $87,087,040
2027 $89,346,598 $89,089,306
2028 $92,195,604 $92,321,897
2029 $95,476,869 $95,476,869
Project Life Span 5 years
Requesting Organization/Department Energy Delivery
Business Case Owner I Sponsor Paul Good Josh DiLuciano
Sponsor Organization/Department Energy Delivery
Phase Execution
Category Mandatory
Driver Customer Requested
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
The New Revenue — Growth Business Case is driven by tariff
requirements that mandate obligation to serve new customer load when
requested within our franchised area.
Business Case Justification Narrative Template Version: February 2023 Page 2 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 410 of 535

Docusign Envelope ID:825E3A90-F88A-407A-8DD3-5B461 133ADA81
New Revenue - Growth
1.2 Discuss the major drivers of the business case.
Customer Requested: The New Revenue—Growth Business Case serves
as support of several focus areas in Avista. We seek to serve the interests
of our customers, in a safe and responsible manner, while strengthening
the financial performance of the utility. Our growth contributes to strong
communities, ongoing value to our customers, and the device portion of
the business case keeps our system safe and reliable.
All new customers on Avista's system are benefitted by this business
case. In addition, all customers who have their metering or regulation
changed, or who have transformers replaced, benefit from this business
case.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
Avista is required to serve appropriate new load, complying with our
Certificate of Convenience and Necessity, and as part of our Obligation to
Serve.
The New Revenue — Growth Business Case will provide funds for
connecting new Electric and Gas customers in accordance with our filed
tariffs in each state.
Our obligation to serve, mandates that we must extend service to new
customers in our franchised service areas. We do not currently have an
alternative to serving new customers. All projects are subject to our Line
Extension Tariffs, filed with each State Utility Commission.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
This business case is about connecting customers to Avista's facilities. The
work directly reflects our focus area for customers as well as our mission
statement."We must hold our customer's interests at the forefront of all our
decisions" and "We improve our customer's lives through innovative energy
solutions."
Business Case Justification Narrative Template Version: February 2023 Page 3 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 411 of 535

Docusign Envelope ID:825E3A90-F88A-407A-8DD3-5B461B3ADA81
New Revenue - Growth
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
N/A
2. PROPOSAL AND RECOMMENDED SOLUTION - Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Providing service to customers upon request is mandated. As needed
customer project coordinators (CPCs) and engineers review requests to
determine solutions that best meet the needs of the customer and Avista.
These extraordinary requests lend themselves to more visibility and
oversight.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
Avista uses a rolling 12-month Cost Per New Service spreadsheet to measure
ER1000, Electric New Revenue, and ER1001, Gas New Revenue spending.
Device blankets are subject to demand for both new revenue and non-revenue
installation and replacement.
Enclosed is a spreadsheet showing projected spend through 2029 with a
breakout by Expenditure Request for the New Revenue — Growth Business
Case. Connects forecast and 12 -month rolling Cost Per Service information are
used. Electric and Gas devices are also included, such as Meters,
Transformers, Gas Regulators, and ERTs (Encoder Receiver Transmitter).
Many of the Meters, Transformers, and ERTs are used as replacements for
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 412 of 535

Docusign Envelope ID:825E3A90-F88A-407A-8DD3-5B461 133ADA81
New Revenue - Growth
Transformer Change Out Program, Wood Pole Management, and Periodic
Meter Changes.
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
There are no identified direct savings associated with this business case. This
business case supports the installation of equipment to support new
customers.
There are no direct or indirect savings represented in the Growth business
case. The Growth Business Case is driven by tariff requirements that mandate
obligation to serve new customer load when requested within our franchised
area. The business case also includes initial purchase of transformers, as well
as electric and gas meters and devices which are on hand for immediate
response for reliability and customer response reasons. The work utilizing this
equipment is represented in various business cases.
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
There are no identified indirect savings associated with this business case.
This business case supports the installation of equipment to support new
customers.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 413 of 535

Docusign Envelope ID:825E3A90-F88A-407A-8DD3-5B461 133ADA81
New Revenue - Growth
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternative 1:
In some instances, there may be alternative ways to serve a customer.
Customer project coordinators and engineers determine the solution that best
serves the customer while considering subsequent customers and Avista's
infrastructure.
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
We periodically review and update the line extension tariffs to ensure we are
not creating excessive rate pressure in connecting new customers.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Work timeline is primarily driven by the request of the customer. The transfer
to plant occurs monthly.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
The Energy Delivery Director Team assumes the role of advisory group for
the New Revenue — Growth Business Case, with quarterly reporting to the
Board of Directors through the Financial Planning & Analysis department.
The appropriate extension and service tariffs are designed and updated by
the Avista Regulatory Affairs Department, in cooperation with Construction
Services, and the Financial Planning & Analysis department. All Customer
Project Coordinators are trained regularly, by Regulatory Affairs and
Finance, on tariff application.
For the Electric and Gas New Revenue Expenditure Requests (ERs):
Operations managers and directors receive monthly Cost of Service reports
providing 12-month rolling average costs for the construction areas. This
allows for review of trending of costs for decision-making regarding
processes and resources.
For the Metering and Devices ERs: Monthly Capital ER and project results
reports are distributed. These provide updated variance information
facilitating oversight by the Electric Meter Shop and Gas Engineering
department.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 414 of 535

Docusign Envelope ID:825E3A90-F88A-407A-8DD3-5B461 133ADA81
New Revenue - Growth
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the New Revenue — Growth and agree
with the approach it presents. Significant changes to this will be coordinated with and
approved by the undersigned or their designated representatives.
Signed by:
Signature: PAU Good, Date: Aug-31-2024 1 3:40 PM PDT
Print Name: Paul Good
Title:
Director of Electric Operations
Role: Business Case Owner
Signed by:
Signature: 56SL vtbtLial h Date: Aug-30-2024 1 12:02 PM PDT
Print Name: josh Di Luci ano
Title: VP Energy Delivery
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 7 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 415 of 535

DocuSign Envelope ID:918EE9FO-FB94-48CF-B274-9A14F77FOE36
Capital Equipment Program (ER7005/7006)
EXECUTIVE SUMMARY
The Capital Equipment Program (ER7005/7006) funds the essential tools required
for Avista employees to perform work efficiently and safely. This equipment is
necessary to construct, monitor, ensure system integrity, and properly repair and
maintain the Avista systems (electric, gas, communications, fleet, facilities, and
generation). This equipment needs to be fully functional and available for planned
work as well as emergency outage repairs on our facilities and equipment. Capital
tools are utilized in all service territories, and by all Crafts. Capital tools are
required to execute and support work across all business units, and it is
recommended to continually fund these tools at an annual level of $2.5M.
Capital tools benefit customers by reducing labor cost due to improved efficiency
and improving quality of the work by advanced performance of the tools.
Customers will also benefit from improved system reliability and reduced outage
duration enabled by diagnostic tools. It is critical that capital tools are consistently
and adequately funded year over year to maintain performance and ensure tool
availability. The risk of not funding capital tools is reduced work performance,
increased safety risk, reduced work quality, and increased outage time for
customers.
Business Case Justification Narrative Template Version: February 2023 Page 1 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 416 of 535

DocuSign Envelope ID:918EE9FO-FB94-48CF-B274-9A14F77FOE36
Capital Equipment Program (ER7005/7006)
VERSION HISTORY
Version Author Description Date
1.0 Gary Shrope Initial draft of original business case 4/28/2023
BCRT Team
BCRT Memember Has been reviewed by BCRT and meets necessary requirements
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT($)
2025 $2,500,000.00
2026 $2,500,000.00
2027 $2,500,000.00
2028 $2,500,000.00
2029 $2,500,000.00
Project Life Span 5 Years
Requesting Organization/Department Supply Chain
Business Case Owner Sponsor Cody Krogh Kelly Magalsky
Sponsor Organization/Department Supply Chain
Phase Monitor/Control
Category Program
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
Business Case Justification Narrative Template Version: February 2023 Page 2 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 417 of 535

DocuSign Envelope ID:918EE9FO-FB94-48CF-B274-9A14F77FOE36
Capital Equipment Program (ER7005/7006)
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Each year, the Capital Equipment Program has more requests for tools and
equipment funding deficit prevents the purchase of all submitted requests. In
addition, there is a trend of decreased funding for the capital tools. Over this
same time period, the tool complement has been expanding by replacing
manual tools with battery assist devices to increase safety and productivity.
These additional tools are much more expensive. This requires more funding
over time to support replacement costs, as well as ensure all areas of the
company can take advantage of this technology. Historically the budget has
not been fully funded resulting in reduced tool availability.
1.2 Discuss the major drivers of the business case.
The Capital Equipment Program (ER7005/7006) funds the essential tools
required for Avista employees to perform work efficiently and safely. This
equipment is necessary to construct, monitor, ensure system integrity, and
properly repair and maintain the Avista systems (electric, gas, communications,
fleet, facilities, and generation). Much of the capital equipment used in the utility
industry is very specialized and may not be readily available due to long lead
times. This equipment needs to be fully functional and available for planned
work as well as emergency outage repairs on our facilities and equipment.
Equipment failures contribute to injuries, slowdowns in work performance, and
increased customer restoration time.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
This work is needed to ensure that our workers have safe and reliable tools that
are necessary to complete their tasks, and also to ensure that if there are any
tools that are broken, they can be replaced in a timely matter to keep
projects/tasks on schedule. If this work is not approved/deferred the risks
include breakage of equipment that is critical to daily operations/projects leading
to longer lead times for repairs or project completion. Also, our employees need
safe tools to ensure there are no injuries on the job. By having these updated
through this program, we can increase our productivity by having tools that will
allow us to complete our work efficiently on time and increase the safety of our
employees.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 418 of 535

DocuSign Envelope ID:918EE9FO-FB94-48CF-B274-9A14F77FOE36
Capital Equipment Program (ER7005/7006)
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization.
Capital equipment benefits customers by reducing labor cost due to improved efficiency and
improving quality of the work by advanced performance of the tools. Customer will also benefit
from improved system reliability and reduced outage duration enabled by diagnostic tools. It is
critical that capital equipment is consistently funded year over year to maintain performance and
ensure equipment/tool availability. The risk of not funding capital equipment is reduced work
performance, increased safety risk, and reduced work quality.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
Attachment 1: Email by Tony Klutz describing the benefits of the Capital Equipment
Program
Attachment 2: Scoring Criteria &Weighting
Attachment 3: Capital Equipment Committee Board Charter
Attachment 4: Capital Committee Notes
Attachment 5: Business Case Model/Offset Costs
For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
The safety project for ergonomic related battery assist tools was widely implemented in
2016. Since that time this number has increased to over 100 tools. This equipment has
a 5-year warranty, so future failures for 5-year-old equipment will not be covered by the
warranty. Replacements for these out of warranty tools will need to be budgeted for within
the ER7006 budget each year, as per all additional "new" capital equipment.
2. PROPOSAL AND RECOMMENDED SOLUTION
- Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis).
Option Capital Start Complete
Cost
[Recommended Solution] Alternative#1 $2.5 M 01/2025 NA
[Alternative#1] (Fully fund) $2.5 M 01/2025 NA
[Alternative#2] (Partially fund based on priority) varies 01/2025 12/2029
[Alternative#3] Rent equipment(0&M-$5,700,000) O&M
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 419 of 535

DocuSign Envelope ID:918EE9FO-FB94-48CF-B274-9A14F77FOE36
Capital Equipment Program (ER7005/7006)
2.1 Please summarize the proposed solution and how it helps to SOLVE THE
BUSINESS PROBLEM IDENTIFIED ABOVE.
The proposed solution is to fully fund the capital equipment program. This ensures
employees have the proper equipment available at all times to safely and efficiently
perform their work. This will also improve system reliability and reduced outage duration
for our customers.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other information
that was considered when preparing this business case (i.e., samples of
savings, benefits or risk avoidance estimates; description of how benefits to
customers are being measured; metrics such as comparison of cost ($) to
benefit (value), or evidence of spend amount to anticipated return).2
On average, the Capital Tool Program has more requests for tools and equipment than
can be funded as shown below in Figure 1. The requests are prioritized, and tool selection
is completed as described in Section 2.8. The funding deficit prevents the purchase of all
submitted requests. In addition, there is a trend of decreased funding for the capital tools.
Over this same time period, the tool complement has been expanding by replacing manual
tools with battery assist devices to increase safety and productivity. Along with this, other
more technical equipment is now being used such as Drones. These additional tools
require more funding over time to support replacement costs.
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
00 $ $ $ $ $
*** Not Apliccable to this Busines Case.
2.4 Summarize in the table, and describe below the INDIRECT offsets (Capital
and O&M) that result by undertaking this investment.
Renting all equipment
Offsets Offset Description 2025 2026 2027 2028 2029
Capital Renting all Equipment $ $ $ $ $
0&M Renting all Equipment $3,900,000 $5,700,000 $5,700,000 $5,700,000 $5,700,000
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 420 of 535

DocuSign Envelope ID:918EE9FO-FB94-48CF-B274-9A14F77FOE36
Capital Equipment Program (ER7005/7006)
Repair all equipment
Offsets Offset Description 2025 2026 2027 2028 2029
Capital Continually Repair all ($2,500,000) $ $ $ $
Equipment
0&M Continually Repair all $640,000 $640,000 $640,000 $640,000 $640,000
Equipment
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternative 1: Fund Program at Current Level (Recommended)
It is recommended that this Program be funded, annually, at its current level to ensure Avista
has the proper capital equipment necessary to safely and efficiently perform all required work.
This funding level is to cover inflation of current pricing, support increased tool complement as
complement has increased in time, and support battery assist tools, drones, and other
increasingly complex tools that have a higher cost. This funding also supports emergency
replacement of tools due to mechanical failure, and unplanned tools needed to support changes
in crew work structure. Due to the specialized nature of utility equipment, it is most efficient for
Avista to equip employees with the necessary tools and equipment to safely perform timely
emergency repairs, while using the same tools and equipment to perform ongoing scheduled
work and maintenance. Furthermore, this specialized equipment is often only available directly
from the manufacturer, and is not typically available as a rental.
By funding this Program,Avista ensures that employees have the proper equipment to safely and
efficiently perform their work, while providing safe, reliable service to customers.
Option 1 will provide an approximate annual savings of$15M over Option 3 below, as shown in
Attachment 5: Business Case Model/Offset Costs.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 421 of 535

DocuSign Envelope ID:918EE9FO-FB94-48CF-B274-9A14F77FOE36
Capital Equipment Program (ER7005/7006)
Alternative 2: Partially Fund Program based on priority
This option is not the preferred approach over the long-term; however, it is exercised when
necessary. Each year, when the requests for tools and equipment are submitted, cuts to the
Capital Equipment Program are made by the business units to bring the projected cost of the list
of equipment and tools into line with the budgeted amount. Further modification of the funding
level for the Program is performed in concert with other business budget needs.
When the program budget needs to be reduced, reductions are first made to requests in the
category of enhanced productivity, then replacement. Replacement is intended to replace aging
units to achieve more predictable capital requirements and avoid replacement peaks caused by
large-scale failures. Cutting into these requests over an extended period leads to reduced
efficiency and may have safety impacts. This has caused excessive rollovers each year, which
build up extensively when they are not able to be purchased within the current budget cycle.
This leads to a buildup in capital equipment requests that cannot be adequately funded. For
2023 there were$1 M of requests that were not able to be funded due to budget reduction.
Having the ability to test and incorporate equipment that falls within the enhanced productivity
category helps support improved processes and leads to enhanced safety and longer equipment
lifecycles.
Alternative 3: RENT EQUIPMENT
Renting of the capital equipment was considered as a possible alternative. Considering the total
tools, only a small percentage are available to rent, while nearly all tools are needed on hand at
all times for emergency locates and repairs. This leaves very few items that qualifiy as potential
rental equipment (see Figure 3).
If equipment is rented, there is no guarantee of availability. Rental companies rent equipment on
a first-come,first-served basis, making equipment scheduling for specific time sensitive jobs very
difficult. Safety and compliance regulations are also affected when correct equipment is not
available for rent.
Equipment failure is often a concern with rental equipment, as it is uncertain what condition rental
equipment is in, or how it has previously been maintained. This can lead to safety issues for
equipment operators when failures occur, as well as lost production time.
Depending on the timeline of the rental equipment, it would not be cost effective to rent long-term
as the rental costs would exceed the base price of new equipment. An average rental price is
$700 per month or$8400 per year which exceeds the cost of the tool purchase.
Training on rental equipment would also be required, if different than standardized Avista
equipment. For example, Avista gas employees are only trained/qualified on specific equipment
Business Case Justification Narrative Template Version: February 2023 Page 7 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 422 of 535

DocuSign Envelope ID:918EE9FO-FB94-48CF-B274-9A14F77FOE36
Capital Equipment Program (ER7005/7006)
that has been standardized by Avista, which may or may not be what can be rented for specific
jobs. This can contribute to added time necessary to qualify employees on the operation of the
equipment, and safe operating procedures.
Due to the Department of Transportation (DOT) compliance, Avista is also required to maintain
maintenance and calibration records for all gas equipment, along with operations guides for all
on-site equipment. Avista would be out of compliance using various rental equipment as rental
companies are not required to provide this documentation for their equipment to their customers.
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how
will success be measured).
The Capital Tool Program has more requests for tools and equipment than can be
funded as shown below in Figure 1. The requests are prioritized, and tool selection is
completed as described in Section 2.2. The funding deficit prevents the purchase of all
submitted requests. In addition, there has been a trend of decreased funding through
2020. The decreased budget has also impacted the requested funds as departments
must be more judicious to align with budget. Over this same time period, the tool
complement has been expanding by replacing manual tools with battery assist devices
to increase safety and productivity. Along with this, other more technical equipment is
now being used such as Drones. These additional tools require more funding overtime
to support replacement costs.
Capital Tooling &Stores Equipment
ER 7005/7006
S4.0M
$3.5M
S3.0M
S2.5M
$2.0M
M '
$1.SM
S1.0M ~
S500K
$OK �
2015 2016 2017 2018 2019 2020 2021 2022
■Requested ■Budget ■Available
Figure 1
Business Case Justification Narrative Template Version: February 2023 Page 8 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 423 of 535

DocuSign Envelope ID:918EE9FO-FB94-48CF-B274-9A14F77FOE36
Capital Equipment Program (ER7005/7006)
The distribution of Capital Equipment funds by the Business Unit is shown below in Figure
2. The allocation is based on overall tool ranking and priority rather than a set allotment by
department. As a result, there is variation year over year (as noted in the graph) ensuring
that the most critical tools request by all departments are funded.
Capital Tools - Requests by Function
$700K
$600K
$500K
$400K
$300K
$200K
$100K
$OK
Production & Natural Gas Electric Shared Services Infrastructure
Generation Operations Operations Technology
■2021 ■2022 Summary
Figure 2
The 2022 capital tool breakdown by investment driver is represented below in Figure 3.
The highest percent of spend (39.5%) was for tools related to Safety and Compliance.
This category is also the highest-ranking investment driver. Spend in this area is related
to changing industry compliance standards and tools identified to improve safety or
ergonomics (improved body posture, reduced exertion of force, and reduction in
frequency).
Spending by Investment Driver
7.5%2.6/°° ■Asset Condition
26.2%
FAIA ■Customer Service Quality and
Reliability
■Failed Plant and Ops
W" 39.5%
■Mandatory and Compliance
24.2%
Performance and Capacity
Figure 3
Business Case Justification Narrative Template Version: February 2023 Page 9 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J.DiLuciano,Avista
Schedule 3,Page 424 of 535

DocuSign Envelope ID: 918EE9FO-FB94-48CF-B274-9A14F77FOE36
Capital Equipment Program (ER7005/7006)
2.7 Please provide the timeline of when this work is schedule to
commence and complete, if known.
An updated process outlined below was created in 2019, and is now fully implemented. The
program is projected for five (5) years to account for equipment/tool life cycle and replacements.
The planning and execution of the program is managed by the Supply Chain Department. Tools
are received and delivered to internal customers and immediately become used and useful, this
program has been ongoing for decades.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of
the business case, and how such oversight will occur.
The Capital Equipment Committee (CEC)ensures that the investment successfully addresses all
capital equipment requests to ensure each is warranted.The CEC also ensures that each request
is prioritized based upon importance of need and equal allocation of funds for capital equipment
requests.
An updated process was created in 2019 and was fully implemented in 2020. The process begins
by requesting Business Unit Managers to upload their tool needs into a SharePoint site. As part
of the tool submittal the Manager must complete several ranking criteria used to support the
business need for the tool. These criteria are Priority, Current State, Investment Driver, Strategic
Alignment, Stakeholder, and Demand Type. The Managers' requests are then routed to the
respective Business Unit Directors for approval. For a detailed breakdown of the criteria see
reference document"Scoring Criteria &Weighting" (see attachment 2).
The final list from each Business Unit is then reviewed by the CEC to ensure funding is distributed
fairly and impartially across the company. The equipment request list is ranked per the scoring
criteria ensuring all equipment is funded in order of ranking. This is required to prioritize spending
as the total equipment requests exceed the allocated budget. Decision records and meeting notes
are maintained on the SharePoint site once the CEC finalizes the list and purchasing is ready for
execution.
2.8.1 Capital Equipment Steering Committee
The final requested tool list from each Business Unit is then reviewed by the Capital Equipment
Committee (CEC) to ensure funding is distributed fairly and impartially across the company. The
tool list is ranked from the scoring criteria to make certain the tools are funded in order of ranking.
Ranking is required because the total tool requests exceed the allocated budget. Purchasing
begins executing purchases starting with the highest priority scoring.
Business Case Justification Narrative Template Version: February 2023 Page 10 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 425 of 535

DocuSign Envelope ID:918EE9FO-FB94-48CF-B274-9A14F77FOE36
Capital Equipment Program (ER7005/7006)
The governance process is documented in the Capital Equipment Committee Board Charter(See
attachment 3). In summary it is guided by the following scoring criteria:
Priority, Current State, Investment Driver, Strategic Alignment, Stakeholder, Demand Type and
Age of request. Each of these scoring criteria are weighted to help place the requests in order of
high to low importance.
Those who provide oversight will be those who make up the Capital Equipment Committee Board
(these members are nominated annually by Directors). These members will help to ensure that
the funding for capital equipment is distributed fairly and impartially based on the needs of Avista.
The following are those members that make up the board composition:
Tool Keeper(Gas): Voting Member
Tool Keeper(Elec): Voting Member
Safety& Health Coordinator: Voting Member
Electric Operations Manager: Voting Member
Gas Operations Manager: Voting Member
Generation & Production Manager: Voting Member
Capital Planning Group Member: Voting Member
Supply Chain Manager: (Non)Voting Member
Capital Equipment Sourcing Professional: (Non)Voting Member
Business Case Justification Narrative Template Version: February 2023 Page 11 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 426 of 535

DocuSign Envelope ID:918EE9FO-FB94-48CF-B274-9A14F77FOE36
Capital Equipment Program (ER7005/7006)
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Capital Equipment Program
(ER7005/7006) and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.
Signature: 0 Slg��y: Date: May-14-2024 1 9:21 AM PDT
�
Print Name: Cody Krogh
Title: Manager Supply Chain
Role: Business Case Owner
D 5'g tl by:
Signature: sty Date: May-14-2024 1 9:42 AM PDT
[!;
Print Name: Kelly Magalsky
Title: Director Shared Services
Role: Business Case Sponsor
by:
Signature: May-14-2024 1 7:01 AM PDT
LD11151111d
fht-(,0Y6W Date:
Print Name: Steve Carrozzo
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 12 of 12
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 427 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
EXECUTIVE SUMMARY
For decades, several of Avista's most critical operations have been located on the 4th floor of Avista's General
Office Building on the Mission Campus.This includes departments such as Transmission System Operations,
Supervisory Control and Data Acquisition, Distribution Operations, Gas Control, Network Operations,
Security Operations, and 24-hour Call Center Reps. Over time, as each of these departments experiences
new growth due to ever-changing utility requirements and/or initiatives, capacity has been reached in their
available square footage. Due to our current space constraints, we have handicapped our ability to manage
storm events, narrowly meet government regulations, and created an inaccessible and ergonomically
unfriendly working environment. These risks we run necessitate a need for a new space for our critical
operations group.
Meanwhile, our Generation Control Center, which monitors the 5 dams along the Spokane River, is in a
leased space at the Seehorn Building in downtown Spokane.The urban setting surrounding the control center
has led to a heightened risk of criminality and unauthorized access for our Seehorn Building operations and
employees. Located on the second floor of the commercial retail building, the control center only has one
layer of defense in the form of a controlled access man door. Employees need to park a couple of blocks
away from the building and their unsecured walk to the building is an employee security concern. Moving the
Generation Control Center to a safe and secure Avista-owned space alongside the other critical operations
group is imperative.
The recommended solution at this time is to relocate the GCC group to an Avista-owned facility and renovate
the 4th floor of Mission. Relocating the GCC will allow for a purpose-built control center facility, with ample
space for their current needs, reduce security risks, and remove us from a costly 0&M lease. Renovating the
4th floor will allow for each group to expand and upgrade our technology to meet industry standards.A rough-
order-magnitude estimate of approximately $8.5M spread over three years is estimated for design and
construction.The other solutions evaluated by an Advisory Group, are also listed in this business case. Since
this facility will support Avista functions in all service territories,the jurisdiction is slated to be Common Direct—
Allocated All.
The three-year timeline will provide the opportunity to design and execute the recommended solution. With
a project of this magnitude, many stakeholders and groups will be affected during the design phase in the
first year of the project, with construction/execution occurring over the last two years. It is recommended to
proceed with this business case as soon as possible to avoid any potential reliability risks that may occur in
the future. The Facilities Capital Steering Committee approved the submission of this Business Case.
Business Case Justification Narrative Template Version: February 2023 Page 1 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 428 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
VERSION HISTORY
Version Author Description Date
0.0 Vance Ruppert Executive Summary Only 07/10/2020
1.0 Vance Ruppert BCJN Update with 2021 Revisions 07/09/2021
2.0 Lindsay Miller BCJN Update with 2022 Revisions 05/24/2022
2.1 Conor Crai en BCJN Update 08/31/2022
3.0 Conor Crai ne Template+ BCJN Update 04/14/2023
4.0 Conor Crai en Template+ Solution Update 04/12/2024
Steve
BCRT Carrozzo
413012024
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT($)
2024 $516,500 $0
2025 $2,250,000 $0
2026 $2,250,000+ $3,500,000 $8,516,500
2027 $0 $0
2028 $0 $0
2029 $0 $0
Project Life Span 3 year
Requesting Organization/Department Facilities Management Group— H07
Business Case Owner I Sponsor Eric Bowles I Kelly Magalsky
Sponsor Organization/Department Shared Services
Phase Planning
Category Project
Driver Performance & Capacity
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
Business Case Justification Narrative Template Version: February 2023 Page 2 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 429 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
Avista's critical operations consist of Transmission System Operations (SO), Supervisory Control
and Data Acquisition (SCADA), Distribution Operations(DO), Gas Control (GC), 24-Hr Customer
Service Representatives (CSR), Network Operations Center (NOC), Security Operations, and
Generation Control Center (GCC). Currently, the majority of these groups are located on the 4th
floor of the General Office Building on the Mission Campus with the exception of the GCC. The
Generation Control Group is located in downtown Spokane in a rented space in the Seehorn
Building. Within these departments,there are staffing roles that are standard business hours, and
roles that require 24-Hr shifts. The standard business hour support staff are critical to the
department's functions and ideally, would be included in, or adjacent to, the secured space of the
24-hr operations staff, but this is not required.
There are several current problems that are meant to be addressed by this business case. The
primary business problem is space limitations within each group. Compounding the issue is that
departments have grown and plan to continue to grow. The 24-Hr shift jobs all have unique and
specific tasks that require"operator style"workstations that are larger and more complex than the
standard 6x9 (54 square feet) office cubicle. The modern operator workstation requires 600
square feet (SF) of total space. Due to this, and future growth, which will be expanded upon in
this business case, their current allocated square footage cannot be reconfigured or remodeled
to accommodate these future needs.
The SO control room was working comfortably in a space designed for a Transmission Operator
Desk, Reliability Operator Desk, and Backup Operator Desk. In 2022 Avista entered the Energy
Imbalance Market (EIM) which stuffed an EIM Operator desk into the middle of the SO control
room. The once workable room has now become overcrowded and non-ADA accessible. The
SO control room needs to be expanded and reconfigured to efficiently accommodate all four
operator desks.This cannot be achieved in its current location as all space within the building has
been utilized. Outside of the control room but still inside the physical security perimeter(PSP), all
space for offices and cubicles is utilized. The SO department has one Training Coordinator
responsible for about 2,000hrs/yr of training for the staff of 18. Similar-sized utility companies staff
2-3 Training Coordinators.The SO department also has only one Outage Coordinator responsible
for both transmission and generation outages, and writing/rewriting roughly 2000 documents per
year to support these outages. Like the Training Coordinator, similar-sized utility companies staff
2-3 Outage Coordinators. The EIM added additional work for the outage coordinator to update
with a third-party system, PCI Energy Solutions. Inaccurate or missed entries could result in lost
revenue or fines. The SO department would like to add a Training and Outage Coordinator, but
the space constraints within the PSP space will not allow for such growth.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 430 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
SCDA shares the same space within the PSP with the SO group. There are eight areas of
expertise within the SCADA department. The SCADA team is only staffed with 8 engineers/techs
supporting these eight areas. Similar-sized utility companies staff 16-20. The insufficiently staffed
SCADA department runs a risk to grid reliability by not being able to quickly restore functionality
in under 30 minutes. With a SCADA team staffed with knowledgeable and trained resources at
insufficient levels, Avista SCADA resources cannot adequately support the timely update of
SCADA infrastructure systems, placing grid cyber security at risk. In order for SCADA to get to a
sufficient and sustainable support staff for the eight areas of expertise, they need to hire 11
engineers by 2028. These engineers should be located in the PSP alongside the areas they
support. The current location will not allow for this growth.
The DO dispatch space is a second PSP location that has become overcrowded not because of
growth, but because half of their space was taken away in a space reconfiguration.A third of that
space was taken over by the SCADA office area which currently sites west of the DO, and the
remaining space was given to the CSRs to add two additional desks. In their reduced space the
DO is not set up for proper storm response.They currently could not support a similar 2015 storm
event if it were to happen today. In 2015 the DO could staff 6 dispatch operators and 6 assistants.
Today they can staff 6 dispatch operators and 2 assistants. During an event, solo operators run
the risk of losing a crew's locations in the field by not being able to keep them current in the
system. When a crew is discovered "lost", work stops and all crews in the field must return to the
campus and regroup. This could result in a lost day of work and an extended outage. A lost day
in a recent 2021 Windstorm event cost the company$5M. A worst-case scenario could happen if
a line is energized that an undiscovered "lost"crew is working on. The fatality of a lineman could
cost the company millions plus the incalculable toll on their family, friends, and colleagues. The
current space constraints would put the DO group in a difficult situation if they ever lost their
outage management tool (OMT) program, which does not have a backup system. They would
need to resort to 21 3'x4' printed maps of Avista's distribution system. There is no table or desk
space to view plans in the DO area. The DO is in the process of updating its OMT program to the
new Advanced Distribution Management System (ADMS). This new system will require new
employees to manage the system in an area with no room for expansion. The current forecast for
new employees required for the ADMS system sits at 15 (SCADA (6), DO (4), ET (3), GC (2)), all
being required to sit in the PSP with the possible exception of ET.
The GC group is in the PSP area alongside the DO group. Governed by the Pipeline and
Hazardous Materials Safety Administration (PHMSA), they have a long list of requirements
regarding fatigue, environmental setting, and ergonomic factors that need to be met. Even in their
cramped quarters next to the distractions of the DO dispatch group they are loosely compliant
with all PHMSA regulations. A separate dedicated space would allow the GC to better comply
with these PHMSA regulations. The GC group needs to add another Mobile Dispatch System
Administrator desk to support the upcoming expansion of digital workflow anticipated with the
ADMS. This will be difficult to achieve in a space with no room to expand.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 431 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
The second business problem being addressed is technology limitations and upgrades. The
existing SO control room was constructed in the 1950s. Several upgrades have been made over
time, but the Map Board Display Control System is from the 70s and requires a lot of manual labor
to maintain and update. It takes three staff members to update the map board. An operator has
to manually scrape off the tap of the old diagram, fill in the many light node holes, retape the new
diagram, and drill in new node light holes. Behind the map board,a tech engineer has to physically
rewire the new system,while SCADA updates their system. This labor-intensive process can take
up to 5+ days to complete. The SO group runs the risk of making a switching mistake during this
update process because an area of the system is depicted three times during the transition; the
old diagram,a temporary paper plan drawing depicting the new diagram posted on the map board,
and the newly tapped diagram. A single point in the system could be tagged three times during
this process. If the system gets mistagged, a switching mistake could be made which would lead
to damaged equipment and a customer outage. Replacing a damaged transformer ranges from
$5M-10M.. Outages could also lead to daily fines in certain service areas.
The parts for the old 70s map board are also becoming obsolete.The magnetic tiles that comprise
the face of the map board are no longer available. The SO has 10 spare tiles remaining.
I �
The positioning of the map board is also an issue as it sits low in relation to the workstations.
This results in poor sight lines for the operators to see critical information. The 9' ceiling height is
the highest elevation the building will allow. Current control room map walls today are using
central LED video display systems displaying critical information, at elevations of 15', providing
situational awareness from any point in the room.
Another issue is that a single operator desk commonly requires 12+ dedicated network drops to
run all the systems required. It is becoming increasingly difficult to expand desk space and
expensive to retrofit the technology to enhance these systems. Many operator desks require 8 to
12 computer monitors, which limits views to their shared department displays. These limited and
confined workspaces inhibit operator interactions, create ergonomic issues, and hinder
technology.
A third business problem is operation safety and security.The GCC group is located in the rented
Seehorn building in downtown Spokane. Having a critical operations control center in a public
building surrounded by urban development increases the security risk of our operations and our
employees.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 432 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
Security - Gap Analysis
— ► itAW
Present Conditions,,
Sianificant Gaps
• 2 different buildings house operations. Purpose-built,fully owned and operated Control The Mission Campus Main Building can be
GCC currently shares a building in Spokane city with and Data Center facility properly secured
non-Avista offices,a restaurant,and bar. The Steam Plant is not property secured due to co-
location of critical assets with public gathering
spaces.It was reported that unwanted guests are
at the doors of the GCC.
1.2 Discuss the major drivers of the business case.
The major driver of this business case is Performance&Capacity,with aspects of Service Quality
& Reliability and Asset Conditions. Avista's critical operations need to be at the forefront of
performance and reliability, especially during an outage, emergency, or customer event. It is
imperative that these critical functions remain operational and maximize effectiveness for the
benefit of all our customers. Due to our current space constraints, we have handicapped our
ability to manage storm events, narrowly meet government regulations, and created an
ergonomically unfriendly working environment. The outdated conditions of all these departments
to meet the growing needs and requirements of the system become another minor driver of this
business case.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
With the business problems described above, our critical operation groups are asked to carry a
heavy burden. We are currently not accommodating their needs well, let alone their future need
for growth. A new space specifically designed for their operations is needed. This new space
would improve our ability to manage major events, better meet government regulations, and
provide reliable support to our current/increasing systems. We currently run the risk of delaying
power outages, fines from untimely grid restorations, lagging behind cyber security threats, not
being able to meet government regulations, and physical harm to our employees.The longer the
business case is not implemented, the greater the risk that Avista will be forced to implement a
solution that would be reactive, and not proactive. Any reactive solution would probably have a
higher capital expense than the alternatives in the business case, and might even carry
significant 0&M expenses (i.e. rented space/building).
Business Case Justification Narrative Template Version: February 2023 Page 6 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 433 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
The major reason to perform this project is to align with Avista's strategic vision of customer
performance and reliability. It is also beneficial to new initiatives such as the Energy Imbalance
Market, who will be primarily housed within this new Critical Operations Facility.
A secondary reason, if a new facility solution is selected, is to recoup office space at the Mission
Campus to aid in the net employee growth that Avista has seen throughout the last 10 years.
Bringing Avista employees together in person provides a collaborative environment to grow and
work together. This might also provide relief from having to maintain other Avista sites no longer
needed or lease off-site office space in the years to come.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
- R.E. Lamb, Inc.'s 2023 Control Room Site Evaluation Final Report. Available upon request
(Facilities/Conor Craigen).
Avista hired Robert E. Lamb, Inc. to perform a study on our critical operations groups, available
existing buildings, and provided a report on their study. R.E. Lamb is a full-service planning,
design, and construction firm for industrial, manufacturing, utility, and transportation clients.They
have completed over 500 high-reliability utility control center projects in the United States. R.E.
Lamb's team interviewed our critical operations group listed above gathering information on their
operations, needs, and future growth. Their team toured five existing locations; Mission Main
Office 4th floor, Service Building, Ross Park, Spokane Valley Call Center, and the Downtown
Project Center. They looked into existing conditions, space layout, infrastructure, and security.
Arising out of R.E. Lamb's final report, we learned our critical operations group's space needs,
which existing locations are feasible, rough order magnitude budget estimates, and how we
compare with industry standards.
R.E. Lambs considered all the requests from the GCC, SO, SCADA, DO, GC, CSR, NOC, and
Security groups and created a space program. Their results suggested a new greenfield critical
operations facility meeting current industry standards would need to be 64,402 SF. The critical
operations spaces totaled 24,356 SF(GCC, SO, SCADA, DO, GC, &CSR).The current footprint
of these groups is around 14,500 SF. This space program is a good benchmark for space
planning but will be refined to better meet our needs.Lamb estimated this new greenfield building
would cost$55M+. The estimate did not include any land purchase or site work.
' Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 434 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
Based on the space program we know that the Mission 4th Floor and Spokane Valley Call Center
do not offer enough square footage for all our critical operations groups to expand or sufficiently
upgrade technology. Ross Park and The Downtown Network Project Centers locations in regard
to the general public raised too many security threats to be considered a good location for our
critical operations.The 1 st Floor of the Service Building was considered manageable, but it would
require space compromise, business disruptions, and accepted risks as compared to a purpose-
built greenfield option.
We took this knowledge and investigated three locations here on our main Mission Campus, as
well as a new offsite greenfield building. The onsite options are as follows; renovate the east half
of the Service Building's 1st floor, add a 2nd story to the east half of the Service Building, and
build a new greenfield building in the center of campus between the parking garage, auditorium,
and Service Building or at the location of the Warehouse yard.
- Wolfe Architectural Groups 2023 Critical Operations Facility Mission Campus Conceptual
Design and MACC Estimating Group Commercial Building Shell Cost Study Estimate. Available
upon request (Facilities/Conor Craigne).
A code study was performed and it was determined that a new building could be placed in the
center of our campus. Multiple new building renderings were created and generic commercial
building estimates were developed.
- 24-Hour Operations Facility - Major Requirements Matrix — July 2020 Update of a July 2018
document.Available upon request (Facilities/Conor Craigen).
- 2005 study of possible control center for 24-Hour operations, "Avista Utilities Facility Planning
Study". Available upon request (Facilities/Conor Craigen).
Business Case Justification Narrative Template Version: February 2023 Page 8 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 435 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The current proposed solution is divided into two plans. In place of a new facility housing and
expanding all our critical operations groups, the focus will be moving the GCC to an Avista-
owned space and renovating the Mission 41h Floor to improve the critical operations groups
space.
Part 1
The north annex building of the Downtown Project Center has sat vacant since acquired by
Avista. It offers ample room, 5,125 SF, for the GCC group which operates is 3,400 SF. The
building would require a major renovation to function as a control center. The building would
need to be gutted to the studs to allow for a proper layout. The electrical and HVAC systems
would need to be completely redone to bring them up to code and capacity. The perimeter
security fencing would need to be modified due to the fact the east side of the building sits
outside the secured perimeter.The fiber line and all IT components would need to be introduced
to the building. This renovation option will allow for optimal layout and security, and most
importantly remove Avista from an undesirably leased space. The initial high-level cost estimate
for the project is $4,987,500 broken out into $516,500 for design and $4,471,000 for
construction. Facilities is requesting design dollars in 2024 so that construction may begin in
2025. It should be noted that Avista needs to give a two-year notice to the Seehorn landlord to
break the lease.
Part 2
Mission 41h Floor houses the remainder of our critical operations groups. We propose to
completely renovate the 41h floor to create more space for each group and bring their technology
up to date. For this to work we would need to relocate 80 non-critical operations employees off
the 4th floor. Facilities request to retain the $3,500,000 allocated for this work to commence in
2026.
Business Case Justification Narrative Template Version: February 2023 Page 9 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 436 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
Proposed Capital Cost Start Complete
GCC DTPC North Annex Relocation $4,987,500 2024 2026
Mission 4t" Floor Renovation $3,500,000 2026 2026
Total $8,487,500 2024 2026
Notes:
1. See Appendix A for GCC North Annex estimate breakdown of proposed capital costs
shown in the table above.
2. Since there is no path forward, these values are considered a Class 4 estimate as per the
Cost Estimate Classification Matrix by the Association for Advancement of Cost Estimating
(AACE). See Appendix B for further information and a copy of the AACE Matrix. A Class 4 cost
estimate is considered to have only 1% to 15% of the project definition completed, with an
expected accuracy range 30% below to 50% higher of the capital cost shown.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
There are no additional analyses or metrics at this time.
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital N/A $ $ $ $ $
0&M Seehorn Lease $175,000 $175,000 $175,000 $175,000+ $175,000+
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2023 Page 10 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 437 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and OW) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital N/A $ $ $ $ $
0&M N/A $ $ $ $ $
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
See Appendix C for cost estimate breakdowns of Alternative 1- 3's capital costs shown in the
tables below.
Since there is no path forward, these $59M-$23M values are considered a Class 4 estimate as
per the Cost Estimate Classification Matrix by the Association for Advancement of Cost Estimating
(AACE). See Appendix B for further information and a copy of the AACE Matrix. A Class 4 cost
estimate is considered to have only 1% to 15% of the project definition completed, with an
expected accuracy range 30% below to 50% higher of the capital cost shown.
Alternative 1:
Alternative Capital Cost Start Complete
Option 1: Greenfield facility on new $59.9M 2025 2028
property.
Option 1 considers a new 45,000 SF building, on a newly acquired 40-acre piece of land
estimated at $15.6M. The most expensive option but all groups could be accommodated, all
security risks could be eliminated, and there would be no disruptions to other Avista operations.
Alternative 2:
Alternative Capital Cost Start Complete
Option 2: Service Building 211 floor east $30.9M 2025 2028
side addition.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 11 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 438 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
Option 2 considers a 30,000 SF 2nd Floor addition to the Service Building. All critical operations
groups would be accommodated, security risks would be limited, and existing
Mechanical/Electrical/Plumbing (MEP) infrastructure is already in place, but operations inside
the Service Building would be greatly affected. Employees would temporarily need to be
relocated or work from home during construction.
Alternative 3:
Alternative Capital Cost Start Complete
Option 3: Service Building 1st floor east $23.8M 2025 2028
side remodel.
Option 3 considers a 20,500 SF remodel of the Service Building 1st Floor. All critical operations
groups would be included, but not at the ideal capacity, and there would be little room for future
growth. Security risks would be limited, and existing MEP infrastructure is already in place.
Hundreds of employees utilizing this space would need to be relocated, and Avista currently
does not have enough office space to accommodate a relocation this size.
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
At this time,the only measure that can be used is to design solutions that provide room for growth,
expands technology requirements, and adheres to safety and security best practices. Some of
these solutions would include items such as:
1) Materials/Storage: Provide spaces that meet the needs of the Stores team and Operations
2) Environmental/ Compliance: Ensure that the building and site meet Avista's environmental
standards
3) Employee/Customer Impacts: Room for employee or operations growth
4) Operational Efficiency: Ensure that the operational needs of employees are being met
5) Asset Condition: Provide systems and materials that meet Avista standards
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
This business case is considered a project, as it is not intended to be an ongoing project beyond
2027. The major milestones and timeline of the project are estimated to be the following:
Complete Design Drawings: 2025
Business Case Justification Narrative Template Version: February 2023 Page 12 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 439 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
Note: Based on the technology selected and the operator station complexity of the control
room designs, completion for the overall design drawings could extend out at least a year.
Bidding/permits complete, General Contractor(GC) selection: 2025
GC begin construction: 2025-26
GC completed construction, and receive Certificate of Occupancy: 2027
Install Furniture, Fixtures, and Equipment: 2027
Testing of all systems: 2027
Move into the new facility: 2027
Note: Based on the technology selected and the operator station complexity of the control
room, completion of the control room IT/ET/SCADA systems and FF&E could extend out at
least a year.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
A. The Facilities Steering Committee (SteerCo) shall consist of the following: Kelly Magalsky,
Alicia Gibbs, Alexis Alexander, David Howell, Paul Good, Jeremy Gall, Mike Magruder, Vern
Malensky, and Bruce Howard.
B. Advisory Groups that assisted in shaping this Business Case consisted of the following
stakeholders:
• Facilities: Eric Bowles, Conor Craigen, and Annie Lundy
• Kelly Magalsky, Director of Shared Services
• Mike Magruder, Director of Transmission Ops & System Plan
• Alexis Alexander, Director of IT and Security
• Alicia Gibbs, Director of Natural Gas
• Clay Storey, Director of Security
• Jennifer Esch, Director of Customer Service
• Chuck Benson, Chief Systems Operator
• Reuben Arts, Manager of Distribution Operations
• Craig Figart, Manager SCADA/EMS
• Tim Mair, Manager of Gas Control and Service Dispatch
• Nicola Hostetler, Manager of Operations Support and Gas Control
• Ryan Bean, Manager Spokane River Hydro
• Mike Mecham, Manager Plant Ops Thermal
• Andrea Pike, Manager of Customer Service
Business Case Justification Narrative Template Version: February 2023 Page 13 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 440 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
C. The project shall use certain Project Management Professional (PMP) guidelines and
procedures during the course of this project.
A Project Execution Plan, consisting of the documents below, will be drafted and approved by
the SteerCo described in Section 2.8 (A).
• Project Charter, Change Management Plan, Communication Management Plan, Cost
Management Plan, Procurement Management Plan, Project Team Management Plan,
Risk Management Plan and Risk Register, Schedule Management Plan, Scope
Management Plan, and Project Execution Approval Form.
Each month, the project manager will provide the following information either at the scheduled
SteerCo meeting, or via email.
• Approved Yearly Budget, Accrued Yearly to Date, Year Estimate at Complete, Year
Variance at Complete,Approved Lifetime Budget,Accrued Life to Date, Lifetime Project
Estimate at Complete, and Lifetime Project Variance at Complete.
Each month, the SteerCo will make decisions on cost, scope, or budget items as required by the
Project Execution Plan. The project manager reserves the right to present items not outlined in
the Project Execution Plan if he/she determines its importance is relevant to SteerCo input.
D. The final decisions regarding these items, especially certain change requests as required by
the Project Execution Plan, will be presented to, and voted upon by the SteerCo. The decisions
will be documented in a monthly meeting minutes of the SteerCo for documentation and
oversight.
It will be the Project Manager's role to monitor the scope, budget, and schedule and present the
results to the SteerCo, regardless if they are within tolerances, or not.
Business Case Justification Narrative Template Version: February 2023 Page 14 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 441 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Central 24 HR Operations Facility business
case and agree with the approach it presents. Significant changes to this will be coordinated with
and approved by the undersigned or their designated representatives.
DocuSigned by:
Signature: Owb_S Date: May-02-2024 1 9:58 AM PDT
Print Name: anccSH61ftles
Title: Corp. Facilities Manager
Role: Business Case Owner
DocuSigned by:
Signature: S� Date: May-03-2024 3:18 PM PDT
Print Name: E'AOFT 69�Magalsky
Title: Director of Shared Services
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 15 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 442 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
Appendix A-Critical Operations Facility Level 4 Estimate
New Greenfield on Mission Campus6
Scope Cost
Site and Building Construction (40,500 SF) $17,875,000.00
Well water MEP' $222,040.00
SCADA& GCC Data Roomz $1,800,000.00
Backup Power $2,500,000.00
FF&E' $2,250,000.00
Tax(9%) $2,218,233.60
Control Room Designs $150,000.00
Building Design' $1,248,975.00
ET' $2,775,500.00
Avista Labor' $455,182.00
Benefits' $414,104.60
Overhead/Contingency/AFUDC (10%)' $3,190,903.52
Warehouse Relocation Project $2,000,000.00
Total $37,099,938.72
New Greenfield on New Property
Scope Cost
Site and Building Construction (45,000 SF) $20,627,000.00
Well water MEP' $222,040.00
Corp. Data Center, SCADA&GCC Data Room2 $5,400,000.00
Backup Power $2,500,000.00
FF&E' $2,250,000.00
Tax (9%) $2,789,913.60
Property4 (40 acres) $15,600,000.00
Control Room Designs $150,000.00
Building Design' $1,248,975.00
ET' $2,775,500.00
Avista Labor' $455,182.00
Benefits' $414,104.60
Overhead/Contingency/AFUDC (10%)' $5,443,271.52
Total $59,875,986.72
Business Case Justification Narrative Exhibiih 1
Case Nos.AVU-E-25-01/AVU- of 2
J. DiLuciano,Avista
Schedule 3,Page 443 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
Service Building 2nd Floor East Side Addition
Scope Cost
Building Construction (30,000 SF) $12,614,000.00
Existing Building Structural Retrofit $675,000.00
Well water MEP1 $222,040.00
SCADA& GCC Data Room2 $1,800,000.00
Backup Power $2,500,000.00
FF&E' $2,250,000.00
Tax (9%) $1,805,493.60
Control Room Designs $150,000.00
Building Design' $1,248,975.00
ET $2,775,500.00
Avista Labor' $455,182.00
Benefits' $414,104.60
Temp relo workers' $1,110,200.00
Overhead/Contingency/AFUDC (10%)' $2,802,049.52
Total $30,822,544.72
Service Building 1st Floor East Side Remodel
Scope Cost
Building Construction (20,500 SF) $7,394,000.00
Well water MEP' $222,040.00
SCADA& GCC Data Roomz $1,800,000.00
Backup Power $2,500,000.00
FF&E' $2,250,000.00
Tax(9%) $1,274,943.60
Control Room Designs $150,000.00
Building Design' $1,248,975.00
ET $2,775,500.00
Avista Labor' $455,182.00
Benefits' $414,104.60
Temp relo workers' $1,110,200.00
Overhead/Contingency/AFUDC (10%)' $2,159,494.52
Tota I $23,754,439.72
1. 2021 Business Case Estimate+Inflation
2. R.E. Lamb, Inc Estimate
3. MACC Estimating Group Estimate
4.Avista Real Estate ROM Estimate: $130k-650k/acre, used $390k/acre
5. Mauell Corporation ROM Estimate: $50k/Control Room
6. Located on north half of warehouse yard.
Business Case Justification Narrative Exhibiih 1
Case Nos.AVU-E-25-01/AVU- of 2
J. DiLuciano,Avista
Schedule 3,Page 444 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
Appendix B — Cost Estimate Classification Matrix per the Association for
Advancement of Cost Estimating (AACE)
Primary Secondary Characteristic
Characteristic
LEVEL OF EXPECTED PREPARATION
PROJECT END USAGE METHODOLOGY ACCURACY EFFORT
DEFINITION Typical purpose of Typical estimating
RANGE Typical degree of
ESTIMATE Expressed as%of estimate method Typical variation in effort relative to
CLASS complete definition low and high least cost index of
ranges[a] 1 [b]
Capacity Factored,
Class 5 0%to2% Concept Screening Parametric Models, L: -20%to-50% 1
Judgment,or H:+30/o to+100/o
Analogy
Equipment L: -15%to-30%
Class 4 1%to 15% Study or Feasibility Factored or H:+20%to+50% 2 to 4
Parametric Models
Budget, Semi-Detailed Unit o 0
Class 3 10%to 40% Authorization,or Costs with L: -10 Jo to-20 Jo 3 to 10
Control Assembly Level H:+10%to+30%
Line Items
Detailed Unit Cost
Class 2 30%to 70% Tender Control or Bid/ with Forced H -5°Jo to-15°!0:+5°Jo to+20% 4 to 20
Detailed Take-Off H
Check Estimate or Detailed Unit Cost L: -3%to-10%
Class 1 50%to 100% Bid/Tender with Detaaiiil d Take- H:+3%to+15% 5 to 100
Notes: [a] The state of process technology and availability of applicable reference cost data affect the range markedly.
The+/-value represents typical percentage variation of actual costs from the cost estimate after application of
contingency(typically at a 50%level of confidence)for given scope.
[b] If the range index value of"1"represents 0.005%of project costs,then an index value of 100 represents 0.5%.
Estimate preparation effort is highly dependent upon the size of the project and the quality of estimating data and
tools.
Business Case Justification Narrative Page 1 of 1
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 445 of 535

DocuSign Envelope ID:4315A7D0-2B60-48F5-AEF3-4E42B950730B
Central 24 HR Operations Facility
Appendix C-Downtown Project Center North Annex Building Remodel Level 4 Estimate
Basment Floor 3,120 sf
Main Floor 3,216 sf
Total 6,336 sf
2023$ Selective Building Demo $ 5.00 /sf $ 31,680.00 MACC Estimating Group pricing(typ)
Exterior Enclosure $ 40.00 /sf $ 253,440.00 Reduced from$60 to$40
Interior Construction $ 17.00 /sf $ 107,712.00
Stairs $ 2.00 /sf $ 12,672.00
Intertior Finishes $ 31.00 /sf $ 196,416.00
Conveying System $ 5.00 /sf $ 31,680.00
Plumbing $ 19.00 /sf $ 120,384.00
HVAC $ 50.00 /sf $ 316,800.00
Fire Protection $ 6.00 /sf $ 38,016.00
Electrical $ 80.00 /sf $ 506,880.00 Bumped$60 to$80
Equipment $ 1.00 /sf $ 6,336.00
Furnishings $ 20.00 /sf $ 126,720.00 Bumped$10 to$20
Site Improvements $ 10.00 /sf $ 63,360.00
Site Mechancial $ 10.00 /sf $ 63,360.00
Site Electrical $ 10.00 /sf $ 63,360.00
General Requirments $ 20.00 /sf $ 126,720.00
Building Subtotal $ 2,065,536.00
2025$Compounded Rate 18.31% $ 2,443,735.64 $ 385.69 /sf
Bond&Insurance 1.50% $ 36,656.03
OH&P 8% $ 195,498.85
GC Construction Subtotal $ 2,675,890.53
Avista 10% $ 267,589.05 Historical data%
Avista ET $ 927,476.00 ET provided estimate
Project Subtotal $ 3,870,955.58
Contingency 5% $ 193,547.78
Project Total $ 4,064,503.36
ROM Bump 10% $ 406,450.34
CPG Build$Request $ 4,470,953.70 $ 705.64 /sf
Arcitectual&Engineering Design 4% $ 178,838.15 Historical data%
Avista 3% $ 134,128.61 Historical data%
ET $ 203,300.00 ET provided estimate
CPG Design$Request $ 516,266.76 $ 81.48 /sf
Design+Build$ $ 4,987,220.45 $ 787.12 /sf
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J.DiLuciano,Avista
Schedule 3,Page 446 of 535

Fleet Vehicle Refresh Capital Program
EXECUTIVE SUMMARY
The Fleet Vehicle Refresh Capital Plan is the annual and ongoing plan to replace a portion of Avista's fleet
to ensure the highest level of reliability and the lowest total cost of ownership. The annual cost of vehicles is
split into two types: direct operating, and indirect costs. Direct costs include fuel and maintenance, while
indirect costs include common ownership expense. Avista's replacement model is based on a proven fleet
management concept: there are predictable increasing maintenance costs and decreasing ownership costs
as vehicles age. The point at which those two lines intersect gives Avista a window of opportunity in which
we will achieve the lowest total cost for a given unit. Replacing units within that window allows us to provide
a high level of reliability(95%availability currently)while at the same time providing a steady and predictable
capital spend, and level of work for our technicians.
Maintaining a high reliability percentage is essential when we experience an EOP event. Over the last several
years we have experienced multiple large EOP events that have tested the reliability of our fleet. During these
events, our fleet experienced very few breakdowns even though our units were being used around the clock
in some of the most severe conditions. This strategy also gives us the advantage of liquidating units while
they still have a reasonable amount of value in the secondary market. These funds help supplement our
planned spend, minimizing the need for additional funds requests as market prices fluctuate. We have been
navigating inflationary pressures like every other line of business with little sign of significant future relief. In
a meeting with our largest supplier,they shared that amongst the most common commodities they use in the
manufacturing of our vehicles they have seen increases from the low end of 17% to upwards of 60% in the
last three years (see Figure 1 Below). However, these are not the largest price pressures we face over the
next five years. As Oregon and Washington adopt the California Air Resource Board (CARB) Omnibus
and Advanced Clean Truck (ACT) rules to move to zero emissions, vehicles we will face greater economic
impacts.
Additionally, in 2027, EPA's Green House Gas Emission Standards for Heavy Duty and Medium Duty
Vehicles Phase 3 will become effective and impact a majority of the vehicles we operate. This mandate will
have stringent GHG targets in all jurisdictions in which we operate.While these mandates do not dictate what
percentage of electric vehicles we purchase, they do mandate what percentage of new unit's OEMs register
in these states. EPAs rules do contain ZEV guidance that will need to be fully resolved before implementation.
Our greatest concerns are in the medium duty segment of trucks ranging from 14,000 GVWR to 20,000
GVWR. What makes this of greatest concern is that we do not have clear answers from our largest supplier
(Ford), on how they will meet these requirements. Unfortunately, the other competitors in this market are not
indicating they are in any better position. This puts us at risk of seeing significant increases in chassis cost
over the next 5 years.As you will see in more detail later in this document a lack of funding will always create
a cascading effect both in capital expenses but more significantly in 0&M expenses. We are engaged in
conversations with OEM's and desire to be a part of the solution that not only fulfills our obligations to the
laws of our states but to ensure we are doing what is right for our planet, and the communities we serve.With
your support we have successfully kept our fleet on an environmentally responsible path, and our desire is
to continue that into the future.
Avista has worked with Utilimarc, a utility focused data analytics company that provides benchmarks with a
proven record working with utility fleets in the US. The model inputs the initial price, actual maintenance &
repair costs, depreciation expense and salvage value to establish each class of vehicle's replacement cycle.
Business Case Justification Narrative Template Version: February 2023 Page 1 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 447 of 535

Fleet Vehicle Refresh Capital Program
The recommended solution is to replace 50-70 units per year with an escalating spend over the next five-
years for a total cost of$47.5M. The investment in Avista's fleet, over the past decade, means that we have
an exceptionally reliable fleet that meets the service level expectations of our internal customers. Our
equipment must function reliably in the most extreme situations. Our trucks can be in 120+ degree heat at
the bottom of Hells Canyon or 0-degree snowstorms in Sandpoint. Trucks that are running allow crews to
work an outage and reenergize/repressurize the system.
By spending a level amount of capital every year, we can maintain a constant average fleet age which
produces a known quantity of work in our shop, and it prevents us from having clusters of trucks that are the
same age, creating budget strain in the later years of a unit's lifecycle. The investments made have meant
that we are able to provide an extremely functional, reliable,and safe tool for our crews.Continued investment
is critical in ensuring we provide the safest equipment for our operators, as well as decreasing the
environmental impact of our fleet.The capital program has allowed us to maximize our value while minimizing
our total cost. Failing to fund this program will create a growing cost of repair expense, including the potential
need for additions to staff complement, and a decreasing level of reliability/availability.
Figure 1: Inflation by Components
70.00
60.00%
50.00%
40.00% 38.12% 39.28%
30.28% 30.06%
30.00%
24.82% 25.28%
19.57%
20.00% 16.94%
10.00%
0.00%
Cylinders Gear Fabricated Fiberglass Wire Harness Resins, Covers And Wire/Cable Reservoirs Hyd Oil
Box/Winch Steel Parts Chemicals, Plastics
Components And Raw
Materials
VERSION HISTORY
Version Author Description Date
1.0 Potter Initial draft of original business case 5-1-24
2.0 Potter Final Copy 51312024
BCRT BCRT Team Has been reviewed by BCRT and meets necessary requirements smG6/a/1ozy
Member
Business Case Justification Narrative Template Version: February 2023 Page 2 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 448 of 535

Fleet Vehicle Refresh Capital Program
GENERAL 2025-2029
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2025 $7,132,040 $7,132,040
2026 $8,822,402 $8,822,402
2027 $9,484,558 $9,484,558
2028 $10,496,342 $10,496,342
2029 $11,545,976 $11,545,976
Project Life Span 5 year
Requesting Organization/Department K51
Business Case Owner I Sponsor Greg Loew I Kelly Magalsky
Sponsor Organization/Department Energy Delivery
Phase Execution
Category Program
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
Trucks and equipment do not age well. Fleet vehicles experience a duty cycle that most
vehicle owners would not imagine, having only experience with a personal car or truck.
Avista's fleet of vehicles operate in conditions that are often extreme: excessive heat
and cold, dusty, and muddy environments are common in our service territory. These
vehicles also endure employees constantly ingressing, and egressing, while the
engines experience high idle time or high loads.
These factors all contribute to the wear and tear on our vehicles and can create
substantial demand for repair workorders. This kind of duty cycle over the life of a truck
will add up to an increasing amount of repair work and a lower reliability factor as
vehicles age. Our program allows us to optimize our vehicle life so that we extract the
right amount of useful value from our vehicles and replace them before they experience
a rapid rise in the amount of repair expenses they incur. The program we have built
affords us the ability to plan our labor and maximize our internal mechanic resources
while having a fleet of vehicles that are available for any job, planned or unplanned
operational response.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 449 of 535

Fleet Vehicle Refresh Capital Program
1.2 Discuss the major drivers of the business case.
The Fleet Equipment Capital Refresh Program is driven by Asset Condition. This
program benefits both our internal and external customers.
Internal customers: Our drivers have safe and reliable trucks because of the investment
in our fleet. Our fleet of trucks are ready for work over 95% of the time. In the field our
trucks experience fewer breakdowns per one hundred hours of operations and are in
the first quartile when compared to peer utility fleets. Our fleet of vehicles includes
advanced safety features, modern efficient engines and operational tools that make
tasks more efficient. We work extremely hard with input from our internal customers to
make sure we are producing units that give them the vehicles they need to in turn serve
our external customers safely, efficiently, and reliably.
External customers: Our customers benefit from our Fleet Replacement Program
Additionally, new vehicles have the cleanest burning engines and advanced safety
features that protect the environment and drivers on the road. A highly reliable fleet
ensures that our customers will not experience a delay in getting their energy restored;
we are ready and able to get to them in any location necessary.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The investment in vehicles for Avista's fleet is not an option. Our crews do not get to
their jobsites, near or far, in any way but in an Avista owned piece of equipment.
Vehicles will break down and reach their end of life and their life can be prolonged by
making expensive and time-consuming repairs. The availability of the company's fleet
and its field reliability will suffer if there is not an investment of capital. Additionally, the
company will see a steady rising cost in maintenance both in labor and material dollars.
The deferral of investment will also cause spikes of increased capital needs in future
years as the team tries to shore failed assets and work to bring the average fleet age
in line with industry best practices.
If we do not invest our dollars into the capital replacement plan, we will end up spending
those dollars on costly repairs. Repair costs are much higher, and less predictable
making it more difficult to forecast. In the worst case we could see a 12,000-hour delta
between available labor and the labor required to complete the increased repair
demand created by the replacement deferral in the coming decade. That difference
would likely be met with increased utilization of vendor labor at a significantly higher
cost over internal labor, or the need for additional employee complement. In 2032 that
would add an additional $660,000 per year to the clearing account which would be born
through significant equipment cost burdens
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
Business Case Justification Narrative Template Version: February 2023 Page 4 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 450 of 535

Fleet Vehicle Refresh Capital Program
2023 Goals) Status 3-5 Year Focus
Meet or Exceed 2022-23 Biennium energy efficiency Meet regulatory and Integrated Resource Plan(IRP)goals
savings goals for Washington for energy efficiency savings
Replace aging outage management&distribution b
management system(ADMS) Achieve electric reliability and Improve outage
Affordably operate and maintain b s
management system
safe,clean,reliable generation
a. Achieve reliability metric goals
and energy delivery
infrastructure Develop substation security roadmap and identify initial
improvements to be made at our most critical b
substations Mature physical security program and emergency
response system
Achieve emergency gas response goals b
File Oregon&Idaho General Rate Cases and secure
outcomes to meet objectives for financial performance b
and affordability
Complete joint use system audit to identify and realize
additional revenue opportunities
Achieve stated financial Achieve Cost per Customer metric to meet cost
b. Achieve authorized Return
objectives management and affordability goals b
Achieve earnings goals to meet objectives for financial b
performance
Remodel electric and gas hedging&optimization
programs to reduce risk and better capture forward value b
of market positions
4 uYISTA'
The Fleet Vehicle Refresh Capital Program (FVRCP) can play a role in the "Perform" goal
of achieving Cost per Customer to meet cost management and affordability goals. This can
be achieved through steady capital spend which in turn allows us to maintain predictable
O&M cost year over year. Having a reliable fleet also allows the hard-working men and
women in the field to efficiently perform their work in a timely manner.
2023 Goal(s) Status 3-5 Year Focus
Foster and apply an innovation Implement Robotic/Business Process Automation to Adopt new proven technologies to drive operational
a.
culture to benefit employees, drive operational excellence excellence
customers,communities and Hold two Startup Avista events and innovation training Launch one or more regulated or non-regulated new
Shareholders opportunities businesses as a result of internal innovation activities
Avista Innovation Lab hosting platform,capital efficiency Move the concepts of the bi-directional grid from the lab
Create the utility of the future and regional energy ecosystem and demonstration into the operation of the electric grid.
b with our stakeholders, Implement carbon trading policies and practices in
optimizing for cost,carbon and support of clean energy goals and regulations Deliver on the clean energy milestones developed during
reliability 2022,including achievement of a carbon-neutral supply of
Prepare infrastructure for low-carbon fuels,including electricity by the end of 2027
new work practices
The FVRCP also can help support the "Invent" goal of creating the utility of the future by
optimizing for cost, carbon, and reliability. With a large fleet of vehicles on the road across
four states it is critical to ensure we are not negatively affecting the environmental impact
on our communities. While we have many outside entities putting pressure to meet
environmental impact goals around how we generate electricity and deliver natural gas, we
also have many vehicles emission milestones quickly approaching.Fully funding our capital
investment will help propel us down the path proactively.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-13-25-01
J.DiLuciano,Avista
Schedule 3,Page 451 of 535

Fleet Vehicle Refresh Capital Program
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
1.5.1 Please reference and summarize any studies that support the problem
Supplemental information is available from Utilimarc.com
1.5.2 For asset replacement, include graphical or narrative representation of metrics associated
with the current condition of the asset that is proposed for replacement.
Lifecycle Summary
This table shows the lifecycle recommendations for Avista's top vehicle classes.These classes
represent around 75%of Avista's annual fleet spend.
Class Average Mileage Purchase Price Calculated Lifecycle Used
Lifecycle
Pickup-Class 2a 8,789 $56,000 14 14
Pickup-Class 2b" 8,512 $60,000 13 14
Pickup-Class 3" 13,256 $100,068 10 9
Dump Truck-Class 7" 5,005 $142,750 12 15
Dump Truck-Class 8" 5,536 $241,328 12 15
Service Truck-Class 3' 13,693 $130,000 13 11
Service Truck-Class 5" 8,464 $175,000 15 14
Service Truck Class 6+" 7,583 $221,706 15 15
Stake Truck" 6,291 $165,000 20 16
Bucket Truck-Class 5' 15,100 $200,000 8 9
Bucket Truck-Class 7" 9,345 $231,423 11 12
Bucket Truck-Class 8" 4,929 $349,372 17 18
Digger Derrick-Class 8" 4,565 $400,000 15 18
* Mix of company and industry maintenance data ** Industry maintenance data
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 452 of 535

Fleet Vehicle Refresh Capital Program
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
Option Capital Cost Start Complete
Requested Adjustment (no adds to complement $47.5M 012025 122029
funded)
Current Allocated Funding $28.1 M 012025 122029
Lease $M 012025 122029
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Avista's Vehicle Replacement Model (VRM) uses fleet data to develop company
specific replacement criteria for each vehicle class in fleet. This analysis is unique to
the behavior and characteristics of the Avista fleet. The inputs for the Utilimarc VRM
include:
• Company specific trending parts and labor cost for each vehicle class
• Company specific purchase price for each vehicle class
• Company specific annual usage patterns (mileage) for each vehicle class
• Company specific loaded productive labor rate and mechanic productivity
• Vehicles are identified as candidates for replacement when over their
recommended replacement age or replacement life to date mileage, whichever
occurs first.
A vehicle is identified as a candidate for replacement when it reaches its replacement
range for age or lifetime mileage. Replacing within these ranges ensures operating within
1% of the lowest total ownership cost of the vehicle over its lifetime. This can be seen in the
chart below with the green 5-year window. A standard regression model is used in this
analysis. There are certain units such as first responder/local rep units that may reach the
upper limits of the mileage triggers well before the desired age. In this situation we attempt
to move these units into a spare role that will allow us to get the full life expectancy out of
the vehicle. Conversely if we have units that see lower than expected use, we can extend
its years of service granted maintenance and repairs remain steady.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 453 of 535

Fleet Vehicle Refresh Capital Program
Pickup - Class 2a
Lifecycle 14
Purchase Pnce $56.000
Average Salvage at Sale $3.480
Market Depreciation Rate 18%
Inflation Rate 2k%
Average Annual Mileage 8.789
1 $697.32 $9,161.60 59,858.92 47.18%
2 $849.57 $8.412.18 59.261.75 38.55%
3 $1,005.79 $7,744.50 58.750.29 30.9%
4 $1.166.07 $7,148.52 $8.314.59 24.38%
5 $1.330.49 $6.615.54 $7.946.03 18.87%
6 $1.499.15 $6.137.97 S7.637.12 14.25%
7 $1.672.14 $5.709.19 S7.381.34 10.42%
8 $1.949.57 $5.323.47 $7.173.04 7.3%
9 $2.031.52 S4.975.78 S7.007.30 4.82%
10 $2.218.10 $4.661.73 $6.879.93 2.92%
11 $2.409.41 $4.377.48 S6.786.89 1.53%
12 $2.605.55 $4.119.68 S6.725.23 0.61%
13 $2.806.64 $3.885.39 $6.692.02 0.11%
14 $3.012.78 $3.672.01 S6.684.79 0%
15 $3.224.08 $3.477.29 S6.701.37 0.2M
16 $3.440.66 $3.299.23 $6.739.89 0.82%
17 S3.662.63 $3.136.07 $6.798.70 1.7%
18 $3.890.11 $2,986.27 $6.876.38 2.87%
19 $4.12323 $2.848.44 S6.971.67 4.29%
20 $4.362.10 $2.721.40 S7.083.50 5.96%
Business Case Justification Narrative Template Version: February 2023 Page 8 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 454 of 535

Fleet Vehicle Refresh Capital Program
Maintenance Cost Per Mileage - Pickup - Class 2a
•
Average Annual Cost by Lifecycle - Pickup - Class 2a
— Maintenance — Ownership Total
Lifecycle
S10.000
$5.000
i
s0
1 2 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20
Lifecycle
Business Case Justification Narrative Template Version: February 2023 Page 9 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 455 of 535

Fleet Vehicle Refresh Capital Program
Maintenance Cost Per Mileage - Bucket Truck - Class 5
S2.50
R2:0.96 •
$2.00 •
•
v
S1.50 S '
Average Annual Cost by Lifecycle - Bucket Truck - Class 5
— Maintenance — ownership Iota'
Lifecycle
S50.000
S40.000 '
S30.000
S20.000
S 10.000 ,
SO
1 2 3 4 5 6 7 8 9 10 11 12 13 14 1';
Lifecyc',
Business Case Justification Narrative Template Version: February 2023 Page 10 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 456 of 535

Fleet Vehicle Refresh Capital Program
2.2
Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other information that
was considered when preparing this business case (i.e., samples of savings,
benefits or risk avoidance estimates; description of how benefits to customers
are being measured; metrics such as comparison of cost ($) to benefit (value),
or evidence of spend amount to anticipated return).2
The capital in this case is an escalating amount to that reflects past capital allocation shortfalls
(where we prioritized investment in high expense & high required reliability over other lower
priority equipment), new regulatory requirements (driving higher purchase prices) and
inflation driven increases. The investment of capital in this case will provide a consistent
replacement plan which enables our continuing investment to ensure levelized (normalizing
for increasing costs) to ensure predictable parts, labor costs, vehicle downtime, and
technician requirements across the majority of our fleet.
Annual labor savings by maintaining the capital plan and having a predictable labor requirement.
Year 2024 2025 2026 2027 2028
Annual Capital Allocated $5,594,822.00 $5,615,086.00 $5,612,261.00 $5,618,098.00 $5,615,389.00
Average Age 11.57 11.84 12.18 12.54 12.93
Labor Hours 45,772 46,723 47,640 48,656 49,581
Annual Capital Adjustment Request $5,594,822.00 $7,132,040.00 $8,822,402.00 $9,484,558.00 $10,496,342.00
Average Age 11.57 11.72 11.87 11.96 12.08
Labor Hours 45,722 46,118 45,667 45,200 44,580
Labor Dollars Delta* $4,230.00 $51,183.00 $166,915.80 $292,377.60 $423,084.60
Avoided Crew Downtime
Our 2021 analysis showed that demand repair work orders would increase over time when not
controlling the total overall average age of fleet. A percentage of demand repair orders has some
impact on the users of the trucks. On average for this exercise, we assume each work order
creates 2 minutes of crew downtime when repairs are completed internally.
Labor impact 2024 2025 2026 2027 2028
FTE increase 0 0.49 1.63 2.92 4.31
Increase FTE Cost* $0.00 $66,037.98 $226,267.67 $417,498.55 $634,726.48
Outsourced Labor Cost** $3,750.00 1 $45,375.00 $147,975.00 $259,200.00 $375,075.00
Outsource Crew DT cost*** $0.00 $184,169.89 $187,795.56 $191,790.83 $195,451.70
Assuming 1 FTE O&M impact cost is$130,746 per year with a 3% annual increase
Assuming average outsourced labor rate at$150 per hour in 2023 with 50%going to O&M
—Assuming 2023 Hourly 4-person crew labor rate is$397
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 11 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 457 of 535

Fleet Vehicle Refresh Capital Program
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy Statement),
therefore it is critical that these impacts are thought through to support rate recovery.]
2.3 Summarize in the table, and describe below the DIRECT offsets' or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
2.4 Summarize in the table, and describe below the INDIRECT offsets
(Capital and O&M) that result by undertaking this investment.
Offset Offset 2025 2026 2027 2028 2029
s Description
Capital $ $ $ $ $
0&M Estimated $32,994 $113,047 $208,589 $317,120 $378,925"
repair hour as
measured in
labor hours
*2029 hours estimated using trendline data from 2023 estimates as Avista did not subscribe to
a Vehicle Replacement Model in 2024
By funding the additional capital request, we can have a significant impact on the O&M
budget over the next 5 years. The data indicates that if we maintain the current spending
level of$5.6M per year, we will see an increase in the average age of the Avista Fleet. This
has a cascading effect on the number of labor hours and work orders needed to maintain
the health of the fleet to minimize crew downtime and safety. Additionally, as we see an
increase in the number of hours needed to complete the repairs and maintenance, we have
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2023 Page 12 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 458 of 535

Fleet Vehicle Refresh Capital Program
two options for sourcing additional capacity. Outsource is one way we can supplement this;
however, this will significantly increase the length and cost of downtime for our crews. This
option also requires us to spend valuable time inspecting every repair when it comes back
from a vendor as well as increasing the risk of damage or theft from units being off-site.
The second and most effective option would be to increase our department complement to
accommodate for the increased workload. While this does come with a slightly higher cost,
it minimizes our risk significantly in ways that are difficult to quantify. Our desire is to
maintain the average age of the fleet and thus continue to maintain our current staffing
level.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternative 1:
Reduce investment approximately 25% ($11.9M). By investing below the optimum
scenario,we will be able to continue to address the highest cost per mile vehicle classes
(five of which account for 55% of the total annual operating spend) and those vehicles
that are critical response units. We will still face the risk of increased costs, downtime,
and inadequate technician capacity. However, the amount may be mitigated by
focusing on the highest cost and most critical assets. Additionally, we risk the potential
that additional funding would need to be allocated in one or two years to get "caught
up." This will create clusters of additional work for the team purchasing and preparing
units for service and will increase parts and maintenance costs.
Alternative 2:
Fund the program at 50% ($23.7M). This route would create an even larger cluster that
will need to be addressed by future capital spending that could exceed the
recommended spend by as much as 50%. One of the biggest challenges we will face
in this scenario is the effect it will have on our shop workload. As previously stated, this
scenario will create a 12,000 hour or a 33% delta between the amount of labor available
and what is required to complete all demand driven repairs and associated
maintenance. With a predictable number of units coming in, we can better plan our
team's schedule. This also allows us to maintain level staffing needs year over year.
Alternative 3:
The third scenario would be transitioning to a leasing model. Multiple utility fleets lease
their vehicles. This on the surface has the potential to free up capital for other uses.
The risk in this option is that you are trading a capital cost for an operating cost. The
depreciation that was realized on the P&L statement is now an O&M cost that must be
absorbed. Those costs include a leasing company's return on equity.This would require
huge change management with help from the operations management team, as our
vehicles are highly customized to ensure they can do their work in the most efficient
and expedient manner.
Business Case Justification Narrative Template Version: February 2023 Page 13 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 459 of 535

Fleet Vehicle Refresh Capital Program
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
The fleet capital plan is driven by a statistical analysis that is based on our financial and
operating outcomes. This analysis is reviewed by the Fleet Manager, Specialist, and
Analyst by utilizing the data from our analytics partner Utilimarc. The analysis can also
be confirmed by monitoring average age as well as tracking work order count and
maintenance spend using our fleet management system Asset Works.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
The Fleet Vehicle Refresh is a capital plan. Each vehicle or piece of equipment
purchased gets a jurisdiction code, specific project number, and a FERC specific task
code. We begin purchasing the next years equipment during the summer of the prior
year. Right now, we are taking delivery of equipment that had purchase orders cut last
August. The lead time for our most expensive mounted hydraulic equipment is
averaging between 350-450 days. We transfer each individual unit to plant when in
becomes used and useful, which is typically 30-90 days after receipt and invoicing.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
Each individual vehicle purchase is approved in two parts: 1) The Fleet Manager
approves the CPR request, and the Shared Services Director is notified. 2) The
requisition process is approved at multiple levels based on its value, from the Fleet
Manager and as high as the CEO.
Department and district managers are involved in the order process by confirming
which vehicles are to be replaced and by helping to ensure any requests that specific
operators or crews may have. Managers, operators/drivers sign off on a VLC form
which is maintained for every class and build of vehicle.
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Fleet Vehicle Refresh Capital Program and
agree with the approach it presents. Significant changes to this will be coordinated with and approved
by the undersigned or their designated representatives.
Business Case Justification Narrative Template Version: February 2023 Page 14 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 460 of 535

Fleet Vehicle Refresh Capital Program
Signature: 6r"ary Lot-t-r Date: 5/3/2023
Print Name: Greg oeL w
Title: Fleet Manager
Role: Business Case Owner
Signature: &d4 Date:
Print Name: Kel Magals y
Title: Director Shared Services
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 15 of 15
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 461 of 535

DocuSign Envelope ID: 16B10EA3-9B44-404E-BDD9-880D3754A87D
Palouse Service Center
EXECUTIVE SUMMARY
The existing Pullman Service Center facility was constructed in 1959. Due to its age, many of the
buildings on the site are past their useful life and in need of considerable capital investment. The
current site is located on a long narrow 5-acre parcel boxed between SR71 to the South and a
large hill to the North. As the property is so narrow, it has been difficult to efficiently utilize the
space for current operational needs and materials inventory as well as plan for any projected
growth. There is no adjacent property available for purchase to extend the campus, and the
adjacent properties would be difficult to utilize. The existing site and building have environmental,
safety and code concerns, many that do not have an effective resolution. These include
stormwater management issues, safe pedestrian pathways and ADA access and restroom
requirements.
This project would impact both Gas and Electric customers in both Washington and Idaho. We
expect our preferred solution, to cost $23M.
The proposed solution is to relocate the Pullman Service Center to the new location and sell the
existing building. The building will be located on a new property more in line with our current 10-
acre, square of rectangular yard standard. This new site allows the Service Center, the pole yard,
and the warehouse together. This option would allow us a better layout of the materials yard,
establish a more efficient vehicle flow pattern, and give us flexibility for future growth. With new
energy codes and insulation values, a new building would result in a lower cost per square foot
to heat and cool, estimated at 15%. The space will be designed to meet the needs of today's
employees and would meet all current code requirements.
This project would benefit external customers in that the new Service Center can improve
efficiencies. Having all materials, supplies and staff in one location allows for improved use of
resources and response times. Employees benefit from improved communication during outages
and ability to perform their tasks safely and effectively. The Pullman building and the site have
many critical systems that need replacement, including HVAC, plumbing and roof systems. Avista
will need to address the materials yard shortage by purchasing additional property in the coming
years, to meet this space need. The Pullman building and site have many worn buildings and
assets in dire need of replacement, as many of capital projects have been put on hold until the
future state of the site is known.
The Facilities Capital Steering Committee approved submission of this Business Case.
VERSION HISTORY
Version Author Description Date
1.0 L. Miller Initial draft on New Template 41812024
BCRT Team Steve
BCRT Member Has been reviewed by BCRT and meets necessary requirements Carrozzo
413012024
PLANNED SPEND FOR PARTIAL FUNDING
Business Case Justification Narrative Template Version: February 2023 Page 1 of 17
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 462 of 535

DocuSign Envelope ID: 16B10EA3-9B44-404E-BDD9-880D3754A87D
Palouse Service Center
The CPG partially funded this program in 2024 and 2025 below is the planned project
spend for those years. The 2024 projects are currently in planning. This partial funding
will be spent across the two locations in the program to provide them with needed
improvements to maintain functionality at the current locations.
YEAR LOCATION PROJECT ESTIMATED PLANNED
SPEND TTP
2024 Pullman Roof Replacement $200,000 11/2024
2024 Pullman Asphalt $200,000 11/2024
2024 Pullman Oil Water Separator/Wash Bay $150,000 11/2024
2024 Pullman Temp. Storage Yard $200,000 11/2025
TOTAL ALLOCATION $750,000
2025 Pullman Storage Buildings/ Canopy $250,000 11/2025
2025 Pullman Asphalt Phase 2 $200,000 11/2025
2025 Pullman Interior Improvements Phase 2 $125,000 11/2025
2025 Pullman I HVAC and Lighting Upgrades $175,000 11/2025
TOTAL PLANNED ALLOCATION $750,000
Business Case Justification Narrative Template Version: February 2023 Page 2 of 17
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 463 of 535

DocuSign Envelope ID: 16B10EA3-9B44-404E-BDD9-880D3754A87D
Palouse Service Center
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT($)
2024 $750,000 $750,000
2025 $750,000 $750,000
2026
2027
2028
2029
Project Life Span 5 years
Requesting Organization/Department Facilities
Business Case Owner I Sponsor Eric Bowles Kelly Magalsky
Sponsor Organization/Department Facilities
Phase Planning
Category Program
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
�. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
The Pullman service center facility was constructed in 1959, with various upgrades, remodels,
and additions since then. Some of the upgrades included the construction of an addition to the
West side of the service center in 1979, the construction of a storage canopy and meter shop
area, offices, a parking canopy, and an office addition to the East side of the building in 2009.
Building Condition
The Pullman Service Center had a Building Condition Assessment completed by a third party in
2017. In that survey, items were identified that needed immediate replacement or repair totaling
$217,000. Another $1,400,000 in repairs and replacements have been identified today that would
need to be completed in the next 5 years, including replacing the basic building systems such as
electrical, domestic water piping,the plumbing and septic system and the entire service yard asphalt
and drainage.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 17
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 464 of 535

DocuSign Envelope ID: 16B10EA3-9B44-404E-BDD9-880D3754A87D
Palouse Service Center
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Some of the immediate repair and replace items identified:
All the roll up doors need to be replaced at the site. Many are damaged and beyond repair. They
are part of the original construction and are not insulated and do not meet today's standards with the
proper safeties and automation.
The built-up roof requires a lot of maintenance and has several cracks and flashing that need repair.
There are blisters that are past repair and standing water observed throughout by the third-party
assessor.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 17
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 465 of 535

DocuSign Envelope ID: 16B10EA3-9B44-404E-BDD9-880D3754A87D
Palouse Service Center
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In the interior, there are needs for flooring replacements, furniture changes and ceiling grid
improvements. In the exterior there is concrete block repair, unit heater repair and painting
throughout the entire Service Center.
n
There are no existing fire safety systems at the Pullman location. This is considered a critical
failure and would need to be rectified immediately if we do not move forward with a new building.
Installation of a fire suppression system would include extensive ceiling work, lighting changes
and additional plumbing. At a minimum adding a monitored fire notification system may be
required at an O&M expense.
Materials/Storage
Business Case Justification Narrative Template Version: February 2023 Page 5 of 17
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 466 of 535

DocuSign Envelope ID: 16B10EA3-9B44-404E-BDD9-880D3754A87D
Palouse Service Center
The existing Pullman Service Center is too small and unable to sustain the inventory needed. The
Palouse area has historically had a high level of inventory compared to other Service Centers with
territories of a similar size. The local warehouseman has struggled for years to make use of the
existing land.We have used all the existing storage space available, and soon there will be additional
smart grid inventory which will overwhelm the storage yard.We are unable to purchase any additional
land adjacent to the existing property to expand. There is a hillside to the north and east of the
property, but it would not be useable because it would require extensive excavation to bring it down
to the existing property grade. To the west, the land is part of the highway drainage system, so we
are unable to purchase that land.
Historical Warehouse Inventory- Pullman:
400 OW
20o noo
,.000,000.
800.000.
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o.
The layout of the yard requires the whole property to be fenced. During business hours, when gates
must be left open to provide safe access from the highway, the public can enter our property where
all our equipment and material is stored. This is a security issue because some doors into the office
are unlocked during business hours(for ease for employees)and sometimes bay doors are left open
—which people could enter at any time. There is not enough space to provide a separate fenced
warehouse storage yard.
The workload in the Palouse District is growing each year. Pullman is a large portion of that growth.
Over the last two years Pullman has grown by 2.3%. The Palouse construction office services nearly
41,000 natural gas and electric customers (3rd largest District in the company by customer count.)
Palouse District also has one of the largest service territories, around some 5,000 square miles of
area. The workload in the region is expected to continue to increase with the load growth we are
seeing.
The storage/warehouse room is out of space. It is also very inconvenient because the building is in
the middle of the property and the East end of the property gets smaller and smaller. Delivery vehicles
have a very hard time because there is not a good spot for them to be able to turn around safely.
These limitations and the odd configuration create inefficiencies for warehouse staff and crews. It
also creates confusion around inventory,
Environmental/Compliance
This site has environmental concerns and needs to have a review of the water runoff plain and
upgrades will need to be made. One concern is the public highway runoff, which the state has made
some changes to, but we need to look at its impact on maintenance on our site. The vehicle wash
bay also needs to be properly mitigated,which is not currently happening. To manage the wash bay
properly an oil water separator system would need to be installed, estimated at$200K.
The existing building has minor code compliance and security issues. There are many ADA issues,
such as non-compliant restrooms and building access,and much of the construction does not comply
with current code. The site layout prevents the yard from being secured during the day as the building
is centrally located. This layout causes customer and visitor traffic to cross a portion of the storage
yard. This also leaves the site open for access by outside folks to all areas of the storage yard,
warehouse, and fleet area. The interior of the main building needs an update and possibly a large
reconstruction or renovation. The layout is no longer conducive to today's business needs. Avista
has added a number of onsite FTE's increasing the need for office space. Most of these added FTE's
Business Case Justification Narrative Template Version: February 2023 Page 6 of 17
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 467 of 535

DocuSign Envelope ID: 16B10EA3-9B44-404E-BDD9-880D3754A87D
Palouse Service Center
are Construction Project Coordinators working on the growth in the Palouse area. Many of the
building systems are antiquated and have reached the end of their useful life.
Employee/Customer Impact
Currently there are 41 employees that work out of the Pullman office, including 3 local reps that have
their own location along with visiting/working out of Pullman office occasionally.The office is currently
full with respect to being able to "house" employees in the current Service Center as there are only
18 workspaces available, and the Pullman employees do not typically work hybrid and are all in the
office day to day. There are plans to add an employee to either the Pullman/Clarkston office, but we
may have to put them in Clarkston because of the lack of room for the employee in Pullman. Though
the employee would like to be in the Pullman office. We also currently don't have room for summer
students and must pair them up with a local rep desk when they work out of the office. There are no
spare desks for anyone visiting the office to use.
There are 30 legal parking spaces at the current Service Center. With 41 employees we currently
have there is not enough customer/employee parking available. There is parking that occurs outside
of the permitted parking, along drive paths and in front of storage materials. When local reps,
serviceman and others are in attendance of safety meetings or other meetings, the vehicles are
parked all over the property due to lack of parking space. This poses safety concerns and limits the
ability to maneuver through the yard. This also creates a safety concern for pedestrians as they walk
from their vehicles to the building, crossing operations vehicle traffic.
Operational Efficiency/Safety
Traffic must enter and exit from the Service Center straight onto/ from a 55mph highway. This is
problematic for hauling poles, trailers and equipment which is done daily. This is a safety concern in
the winter as well and crossing traffic can be dangerous. While we have made improvements to the
entrance to help mitigate this issue it is still problematic. The current mitigation is the use a driveway
installed by the highway to the West of the property on adjacent land not owned by Avista.
There isn't enough room to park company vehicles in covered areas. We currently park 6 vehicles
indoors out of all the vehicles in Pullman yard. The remainder of the vehicles and trailers are parked
throughout the service yard. Many of the company vehicles that are parked inside are parked with
few inches to spare between the dock and the roll up door. The bays are not large enough due to
larger equipment purchased for today's needs. This provides limited movability around the trucks
and requires that the employees driving must basically back up into the dock, leaving no room behind
the vehicle and the line dock.
Previous Pullman Service Center Aerial
Business Case Justification Narrative Template Version: February 2023 Page 7 of 17
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 468 of 535

DocuSign Envelope ID: 16B10EA3-9B44-404E-BDD9-880D3754A87D
Palouse Service Center
Current Pullman Service Center Aerial- Revised Highway entrance
f
a/
1.2 Discuss the major drivers of the business case.
The major driver of this business case is Asset Condition, Safety and Performance and
Capacity.
The Pullman building and site have many worn buildings and assets in dire need of replacement,
as many of capital projects have been put on hold until the future state of the site is known. This
is causing the current Asset Condition to fall well below acceptable. The lack of investment in
these assets has resulted in safety concerns throughout the building and site. Examples of
safety items include risk of slips,trips, and falls and snow/ice shedding from roofs. The Pullman
Service Center has been considered for replacement since 2018.
This project would benefit external customers in that the new Service Center can improve
efficiencies. Having all materials, supplies and staff in one location that is efficiently laid out
allows for improved use of resources and response times. Internal Customers benefit from
improved communication during outages and ability to perform their tasks safely and effectively
with the necessary tools and facilities. The current situation in Pullman is such that Avista will
need to address the materials yard shortage by purchasing additional property in the coming
years, to meet this space need.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
A large investment is needed for the Pullman Service Center due to its condition. The Pullman
Service Center had a Building Condition Assessment completed by a third party in 2017. In that
survey, items were identified that needed replacement or repair under Operations and
Maintenance totaling $217,000 over the next 5 years. Another $1,400,000 in repairs and
replacements have been identified as of today that would need to be completed under Capital
Spend in the next 5 years, including replacing the basic building systems such as electrical,
domestic water piping, the plumbing and septic system and the entire service yard asphalt and
drainage. Facilities estimates that an interior remodel including ADA upgrades to restrooms and
relocation/ remodel of office and shop space to accommodate business changes would total
Business Case Justification Narrative Template Version: February 2023 Page 8 of 17
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 469 of 535

DocuSign Envelope ID: 16B10EA3-9B44-404E-BDD9-880D3754A87D
Palouse Service Center
another$3,000,000 over the next 5 years. These costs would be invested into a building that
does not meet the needs of the business. Facilities has delayed spend at this location since
2018 due to the active request to fund this work.
As the site itself is insufficient for the needs of the business an alternative solution needs to be
looked at. Differing this work may result in capital investments to be made to an existing location
that has large safety and condition issues. Regardless of improvements made the site is unable
to accommodate appropriate vehicle storage canopies, materials storage (both yard and
warehouse), office and meeting space needs and the safety impact of the highway remains.
Asset Condition Requirements:
Requirements
400,000
M CaDital Replacements
M Component Renewal at ESL
Deficiency Repays 200,000
Preventative Maintenance
■
2024 2025 2026 2027 2028
Year•
Account • 2024 2025 2026 2027 2028 Grand Total
Capital Replacements $493,428 $332,241 $0 $0 $0 $825,669
Component Renewal at ESL $59,699 $0 $228,063 $114 $109,531 $397,406
Defidency Repairs $24,433 $0 $0 $0 $0 $24,433
Preventative Maintenance $68,319 $28,301 $29,150 $30,024 $30,925 $186,718
Grand Total $645,879 $360,542 1 $257,213 1 $30,138 $140,455 $1,434,227
Active Assets 71 71 71 7 7
Total Replacement Value 1 $7,612,327 $7,840,697 $8,075,918 1 $8,318,195 1 $8,567,741
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
The major reason to perform this project is to align with Avista's Focus Areas of Our Customer
and Our People. Being able to provide service to our customers safely and efficiently is a
cornerstone of Avista and the facilities our crews report to is a vital piece of this service effort.
Having facilities and storage yards that meet the needs of both electric and gas operations
benefits both Our People and Our Customers.
This project also aligns with our value of Innovation and our Mission of innovative energy
solutions. Innovation is change and having an openness to improve products, processes, and
services. Whether it is from incorporating new ideas into already established systems, or
completely transforming how something is done, innovation is the key to solving the
challenges Facilities is faced with today. Facilities has worked to include innovation into each
of the projects we complete with a focus on energy and operational efficiency. Providing savings
to both the company and customers by reducing company utility bills. Operationally, layouts of
service yards and buildings will be evaluated to create the most efficient pathways and access.
Saving employee time and increasing safety.
Business Case Justification Narrative Template Version: February 2023 Page 9 of 17
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 470 of 535

DocuSign Envelope ID: 16B10EA3-9B44-404E-BDD9-880D3754A87D
Palouse Service Center
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
The Asset Condition Study and Asset Condition Report for the Pullman Service Center were
used to help determine the best option to resolve the various business problems. These reports
help to understand the Asset Condition needs of the existing structure and the cost impacts to
those improvements. The Facilities 10-year plan Matrix was also used to compare the Avista
owned assets to determine which locations require new locations, remodels, or upgrades.
Pullman 10-Year Forecast of Backlog and Requirements:
*Based on typical yearly spend in Pullman, does not include any of the planed $1.5M spend
Forecast Analysis
0.2000
s2,000,000
0.1800
$1,800,000
$1,600,000 0.1600
$1,400,000 0.1400
$1,200,000 0.1200
T
$1,000,000 0.1000 C'1
$800,000 0.0800
$600,000 0.0600
000,000 0.0400
$200,o00 0.0200
s0 6 0.0000
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 .. __._ 2033
E 5tartirgBacldo0 E Requirement N Spendin0E Endirg Baddog-t-FCi
Please do not attach any requested items to the business case,rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 10 of 17
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 471 of 535

DocuSign Envelope ID: 16B10EA3-9B44-404E-BDD9-880D3754A87D
Palouse Service Center
Startma Baddo:S523.118
Year
ID Grouping Q Category Q 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
Backlog(Start of Capital $0 $0 $0 $0 $498,685 $581,498 $879,365 $1,128,188 $1,146,179 $1,276,008 $1,331,517 $1,426,155 $1,530,761 $1,855,613
1 Year) O&M $0 $0 $0 $0 $24,433 $16,469 $16,963 $17,472 $17,996 $18,536 $19,092 $19,665 $20,255 $20,863
Backlog
(Start of Year)Total $0 $0 $0 $0 $523,118 $597,967 $896,328 $1,145,660 $1,164,175 $1,294,544 $1,350,609 $1,445,820 $1,551,016 $1,876,475
Requirements Capital $0 $0 $0 $0 $78,829 $286,594 $228,063 $114 $109,531 $31,399 $64,089 $77,547 $287,830 $0 $1,163,994
2 O&M $0 $0 $0 $0 $27,476 $28,301 $29,350 $30,024 $30,925 $31,853 $32,808 $33,792 $34,806 $35,850 ¢314,985
Requirements Total $0 $0 $0 $0 $106,305 $314,895 $257,213 $30,138 $140,455 $63,251 $96,897 $111,339 $322,637 $35,850 $1,478,980
3 Backlog+ $0 $0 $0 $0 $629,423 $912,861 $1,153,541 $1,175,798 $1,304,630 $1,357,796 $1,447,506 $1,557,159 $1,873,653 $1,912,325
Requirements
Capital $0 $0 $0 $0 $15,000 $15,450 $15,914 $16,391 $16,883 $17,389 $17,911 $18,448 $19,002 $19,572 $171,958
4 Budget O&M $0 $0 $0 $0 $25,000 $25,000 $25,000 $25,000 $25,000 $25,000 $25,000 $25,000 $25,000 $25,000 $250,000
Budget Total $0 $0 $0 $0 $40,000 $40,450 $40,914 $41,391 $41,883 $42,389 $42,911 $43,448 $44,002 $44,572 $421,958
Capital $0 $0 $0 $0 $13,954 $14,339 $12,393 $15,507 $16,866 $16,538 $10,989 $17,526 $17,026 $16,726 $151,863
5 Spending O&M $0 $0 $0 $0 $22,694 $14,678 $15,119 $15,572 $16,039 $16,520 $17,016 $17,526 $18,052 $18,594 $171,811
Spending Total $0 $0 $0 $0 $36,648 $29,017 $27,511 $31,079 $32,906 $33,058 $28,005 $35,052 $35,078 $35,320 $323,674
Variance(Budget Capital $0 $0 $0 $0 $1,046 $1,111 $3,520 $883 $16 $851 $6,921 $922 $1,975 $2,845 $20,091
6 minus Spending) O&M $0 $0 $0 $0 $2,306 $10,322 $9,881 $9,428 $8,961 $8,480 $7,984 $7,474 $6,948 $6,406 $78,189
Variance(Budget mm us Spending) $0 $0 $0 $0 $3,352 $11,433 $13,402 $10,311 $8,976 $9,331 $14,905 $8,396 $8,923 $9,251 $98,280
Total
Backlog(End of Capital $0 $0 $0 $0 $564,561 $853,753 $1,095,329 $1,112,795 $1,238,843 $1,292,735 $1,384,617 $1,486,176 $1,801,566 $1,838,886
7 Year) O&M $0 $0 $0 $0 $15,989 $16,469 $16,963 $17,472 $17,996 $18,536 $19,092 $19,665 $20,255 $20,863
Backlog(End of Year)Total $0 $0 $0 $0 $580,550 $870,222 $1,112,292 $1,130,267 $1,256,839 $1,311,271 $1,403,709 $1,505,841 $1,821,820 $1,859,749
Unfunded
8 Preventative $0 $0 $0 $0 $13,226 $13,622 $14,031 $14,452 $14,886 $15,332 $15,792 $16,266 $16,754 $17,256 $151,617
Maintenance
9 Fa 0.0000 0.0000 0.0000 0.0000 0.0757 0.1094 0.1354 0.1336 0.1441 0.1459 0.1516 0.1578 0.1851 0.1835
10 Total Replacement $0 $0 $0 $0 $7,840,697 $8,075,918 $8,318,195 $8,567,741 $8,824,773 $9,089,516 $9,362,202 $9,643,068 $9,932,360 $10,230,331
Value
11 Spending
peding as%of 0.00% 0.00% 0.00% 0.00% 0.47% 0.36% 0.33% 0.36% 0.37% 0.36% 0.30% 0.36% 0.35% 0.35%
TRV
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Short Term Alternative Solution- Provide Funding for Specific improvements at the Current
Pullman Service Center-$1.5M
Provide the Pullman Service Center with a temporary solution while we work towards the
recommended long-term solution. Providing $1.5M over two years will allow for improvements to
the parking lot and storage yard. Repair of the roof and improvements to the canopy. Construction
of a new temporary storage yard off Airport Road will provide an alternative pole storage yard.
Asset Condition Projects: $925,000
Repair of the roof,to improve safety and eliminate roof leaks. Replacement of the asphalt,to reduce
pooling water and ice and provide safer access for the forklift. Add a wash pad and oil water
separator, to wash vehicles without impacting the site.
Operational Request Projects:$575,000
Construction of a new temporary storage yard, potentially off Airport Road at the site of a new
substation. Interior improvements to provide additional needed off space and upgrades to create
efficiency. Lighting and HVAC upgrades due to failing systems.
Providing these improvements will allow the Pullman Service Center team to work more efficiently
over the next 10 years. While this does not solve for all the Business Problems, including much of
the asset condition issues it does provide solutions for many of them.
Business Case Justification Narrative Template Version: February 2023 Page 11 of 17
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 472 of 535

DocuSign Envelope ID: 16B10EA3-9B44-404E-BDD9-880D3754A87D
Palouse Service Center
Recommended Solution-New Pullman Service Center
The proposed solution to the business problems identified above is to build a new Service Center.
The new Service Center will be located on a new property where we could locate the Service Center,
the pole yard and warehouse, fleet location and radio tower. The radio tower is a critical part of the
communications system with crews, both daily and during an outage, and will need to be included
in the relocation. This option would allow us to find a property large enough allowing future growth.
This new Service Center would meet the requirements outlined in the Business Problem stated
above. Providing the needed warehouse and storage, office space and include the necessary
environmental requirements and safety protocols.
A property has been identified in Moscow ID and is currently being reviewed for feasibility with Real
Estate but is not confirmed for funding. The property is 7.5 miles from our current location and
centered within the Palouse service territory.
The new Service Center, regardless of location, will include environmentally protected transformer
storage areas and adequate storm water protection, including oil water separators for the entire
facility. This is the new environmental standard for design for Avista, meeting legal requirements
as well. The new facility will centralize all of Pullman crew functions into one location, saving
windshield time each day for crews who currently travel to various substation properties for
materials if needed.
The new Service Center would be designed to meet the needs of today's employees and would
meet current code requirements. These needs include both men's and women's ADA restrooms
and showers, workspace for all necessary employees, meeting space for both Move Safe and
EOP's,workout equipment and warehousing.All the building systems would be designed to today's
technology and are planned to be more efficient than the existing location due to technology
improvements and reduction of energy costs per square foot.
The current building will be sold to offset some of the cost of building new.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
There is currently an identified backlog of$523K in Asset Condition work needed at the
Pullman Service Center. In 2017 Terricon identified $110K in work on their initial assessment.
This list is growing every year as our building ages and new items are identified that need
replacement. At the current funding level this backlog of capital work will continue to grow.
The backlog is growing faster than our current funding model can accommodate. Making the
investment into the existing structure will not solve the remaining problems of limited space,
safety and environmental.
Environmental Compliance has rated the Sandpoint Service Center as a 3. Placing at the top
of our list for locations needing environmental mitigation.
2 Please do not attach any requested items to the business case,rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 12 of 17
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 473 of 535

DocuSign Envelope ID: 16B10EA3-9B44-404E-BDD9-880D3754A87D
Palouse Service Center
Pullman
Element Score Reason
Surface Water 1 Adjacent wetland and Paradise Creek
Floodplain 0
Historic District 0
Adjacent Use 1 Ag and steep slopes
Zoning 0
Total 2
2.3 Summarize in the table and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital - $ $ $ $ $
0&M Utility savings/Sale of Building $ $ $ $0 $
*Building sale not valid in partial funding solution
Direct (Based on Revised Solution):
• None
2.4 Summarize in the table and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M Business Operations Improve $ $155,905 $155,905 $155,905 $155,905
Indirect (Based on Partial Funding):
• Extended/ improved storage yards or storage facilities: Improved business
operations and time efficiencies for crews. An example of this would be added
storage racking resulting in easier material access, yard consolidation.
■ 15 emp x 0.25 hr./day x 260 workdays x$85/hr. avg loaded rate= $82,975
• Efficiencies created through improved storage, more efficient workspaces and
expanded workspaces as required for growth.
■ 22 emp x 0.15 hr./day x 260 workdays x$85/hr. avg loaded rate= $72,930
s Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 13 of 17
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 474 of 535

DocuSign Envelope ID: 16B10EA3-9B44-404E-BDD9-880D3754A87D
Palouse Service Center
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, which were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternative 1: PULLMAN RENOVATION/ STORAGE YARD LAND
O&M: $217,000 CAPITAL: $9,900,000
To avoid constructing a new Pullman service center, Avista would need to continue upgrading
the existing Service Center building.This would include several hundred thousand dollars'worth
of upgrades and improvements. Purchasing additional adjacent properties and expanding the
service center is not an option. Hills and grading difficulties will cost hundreds of thousands of
dollars any time we were to increase the yard by even a little bit.
• Required replacement or repair under Operations and Maintenance totaling $217,000 over
the next 5 years.
• Another $1,400,000 in repairs and replacements were identified that would need to be
completed under Capital Spend over the next 5 years.
• A $3,000,000 renovation to the existing structures would be required to complete and
interior remodel including ADA upgrades to restrooms and relocation/remodel of office and
shop space to accommodate business changes.
We would need to purchase land in another area of town and create an additional storage yard
and possibly additional structures to accommodate larger trucks. This would require that crews
drive to and from this new storage yard/ secondary location several times a day. Impacting
response times and reducing productivity.
• A land purchase to accommodate a storage yard would need to be made. The land
would need to be a minimum of 5 acers. Based on property estimates in the Palouse
are: $500,000.
• Development on land and vehicle storage barn. $5,000,000
Alternative 2: MAINTAIN CURRENT LOCATION
O&M: $217,000 CAPITAL: $4,400,000
Choosing to maintain the current location would greatly impact the Operations and Maintenance
budget for the Pullman facility. The existing building condition would require that some large
Capital investment be made to create a useable and safe location for employees to work. The
building would require an extensive renovation to try to accommodate the current employees
and materials.
The current land is not sufficient for the needs of the Pullman Service Team. Materials would
need to be stored at other locations including Clarkston and Spokane greatly impacting
response times.
• Required replacement or repair under Operations and Maintenance totaling $217,000 over
the next 5 years.
• Another $1,400,000 in repairs and replacements were identified that would need to be
completed under Capital Spend over the next 5 years.
A $3,000,000 renovation to the existing structures would be required to complete and interior
remodel including ADA upgrades to restrooms and relocation/remodel of office and shop space
to accommodate business changes.
Business Case Justification Narrative Template Version: February 2023 Page 14 of 17
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 475 of 535

DocuSign Envelope ID: 16B10EA3-9B44-404E-BDD9-880D3754A87D
Palouse Service Center
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
Confirm the scoping documentation and approved design to the final constructed solution that
provides room for growth, expands technology requirements, and adheres to safety and
security best practices. Some of these solutions would include items such as:
1) Materials/Storage: Provide warehouse space that meet the needs of the Stores team and
Operations. Reduction in trips back to Spokane or other storage yards for materials
(currently not tracked).
2) Environmental/ Compliance: Ensure that the building and site meets with Avista's
environmental standards. Currently not meeting the base standards for storm water
runoff.
3) Employee/Customer Impacts: Room for employee or operations growth
4) Operational Efficiency: Ensure that operational needs of employees are being met,
increase of productivity and reduced windshield time for crews.
Asset Condition: Provide systems and materials that meet with Avista standards and current
building codes and requirements.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Plan if fully Funded:
The property purchase would be completed in 2024. Design will begin in early 2026 with
construction to follow in 2026 and 2027. Currently, as of April 2023, we expect to Transfer to
Plant by December of 2027.
Partial Funding Plan:
The CPG partially funded this program in 2024 and 2025 below is the planned project spend for
those years. This partial funding will be spent across the two locations in the program to provide
them with needed improvements to maintain functionality at the current locations.
YEAR LOCATION PROJECT ESTIMATED PLANNED
SPEND TTP
2024 Pullman Roof Replacement $200,000 11/2024
2024 Pullman Asphalt $200,000 11/2024
2024 Pullman Oil Water Separator/Wash Bay $150,000 11/2024
2024 Pullman Temp. Storage Yard $200,000 11/2025
TOTAL ALLOCATION $750,000
2025 Pullman Storage Buildings/Canopy $250,000 11/2025
2025 Pullman Asphalt Phase 2 $200,000 11/2025
2025 Pullman Interior Improvements Phase 2 $125,000 11/2025
2025 Pullman HVAC and Lighting Upgrades $175,000 11/2025
TOTAL PLANNED ALLOCATION $750,000
Business Case Justification Narrative Template Version: February 2023 Page 15 of 17
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 476 of 535

DocuSign Envelope ID: 16B10EA3-9B44-404E-BDD9-880D3754A87D
Palouse Service Center
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
Facilities Capital Steering Committee
Once the project list is assembled, the finalized list of projects is approved by the Capital
Facilities Steering Committee. This Committee of Directors is responsible for approving the
submission of Business Cases to the Capital Planning Group and approval of projects and any
changes within this program.
In the past this has most often been:
• Director of Shared Services
• Director of Environmental Affairs
• Director of Financial Planning and Analysis
• Director of Generation, Production, Substation Support
• Director of IT and Security
• Director of Natural Gas
The project shall use certain Project Management Professional (PMP) guidelines and
procedures during the course of this project.
A Project Execution Plan, consisting of the documents below, will be drafted and approved by
the SteerCo described in Section 3.1 (A).
• Project Charter, Change Management Plan, Communication Management Plan, Cost
Management Plan, Procurement Management Plan, Project Team Management Plan,
Risk Management Plan and Risk Register, Schedule Management Plan, Scope
Management Plan, and Project Execution Approval Form.
Each month, the project manager will provide the following information either at the scheduled
SteerCo meeting, or via email.
• Approved Yearly Budget, Accrued Yearly to Date, Year Estimate at Complete, Year
Variance at Complete,Approved Lifetime Budget,Accrued Life to Date, Lifetime Project
Estimate at Complete, and Lifetime Project Variance at Complete.
Each month, the SteerCo will make decisions on cost, scope, or budget items as required by
the Project Execution Plan. The project manager reserves the right to present items not outlined
in the Project Execution Plan if he/she determines its importance is relevant to SteerCo input.
The final decisions regarding these items, especially certain change requests as required by the
Project Execution Plan, will be presented to, and voted upon by the SteerCo. The decisions will
be documented in a monthly meeting minute of the SteerCo for documentation and oversight.
It will be the Project Manager's role to monitor the scope, budget, and schedule and present the
results to the SteerCo, regardless of they are within tolerances, or not.
Business Case Justification Narrative Template Version: February 2023 Page 16 of 17
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 477 of 535

DocuSign Envelope ID: 16B10EA3-9B44-404E-BDD9-880D3754A87D
Palouse Service Center
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Palouse Business Case and agree with the
approach it presents. Significant changes to this will be coordinated with and approved by the
undersigned or their designated representatives.
DocuSigned by:
Signature: Date: May-01-2024 i 12:40 PM PDT
Print Name: mC-ka Iles4CZ
Title: Corporate Facilities Manager
Role: Business Case Owner
DocuSigned by:
Signature: km_4s_L Date: May-01-2024 3:25 PM PDT
Print Name: Ke 1y° aga�SKY
Title: Director-Shared Services
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 17 of 17
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 478 of 535

Right-of-Way Use Permits
EXECUTIVE SUMMARY
Avista owns and maintains electric transmission,distribution,and natural gas facilities which cross
public lands managed by a variety of state, federal and local agencies, as well as entities who own
extensive tracts, such as railroads. Traditionally,we have secured long-term rights-of-way permits
for these facilities, but have been required to renew them through an annual billing process. The
cost of renewing these permits continues to increase each year,ranging from 3%to 10%annually,
depending on the agency/entity,thereby increasing annual O&M expenses to the company and our
customers. This business case proposal is to secure long-term agreements with lump-sum
payments to reduce overall expenses related to labor of tracking,researching, and processing these
annual permits. In some cases, we have been able to negotiate a lower annualized cost over the
term of the permit by paying a lump sum up front. In either case, we reduce costs to the company
and our customers. Making long-term lump sum payments allows us to capitalize these costs, as
the permit is a long-term asset.
A final determination was made by project accounting that all right of way permits may be
capitalized since they are in the retirement catalog. The permit must be for a term of at least one
year.
Without capital funding, we will continue to incur increasing annual permitting fees and related
internal costs as an O&M expense. These costs affect all customers, electric and gas, in the entire
Avista service territory.
VERSION HISTORY
Version Author Description Date
1.0 Ted Hermann Initial draft of original business case 8130123
2.0 Ted Hermann Information moved to new 2025-2029 template 4129124
BCRT Heide Evans Has been reviewed by BCRT and meets necessary requirements 4129124
Business Case Justification Narrative Template Version: February 2023 Page 1 of 7
Exhibit No. 10
Case Nos.AW-E-25-01iAW-G-25-01
J.DiLuciano,Avista
Schedule 3,Page 479 of 535

Right-of-Way Use Permits
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2025 $250,000 $250,000
2026 $250,000 $250,000
2027 $250,000 $250,000
2028 $250,000 $250,000
2029 $250,000 $250,000
Project Life Span Annually
Requesting Organization/Department V08/ Real Estate
Business Case Owner I Sponsor Ted Hermann / Bruce Howard
Sponsor Organization/Department A04/ Environmental Affairs
Phase Execution
Category Program
Driver Mandatory& Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link
Investment Drivers
i. BUSINESS PROBLEM - This section must provide the overallbusiness case information
conveying the benefit to the customer,what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
Avista owns and maintains electric transmission, distribution, and natural gas
facilities which cross public lands managed by a variety of state, federal and
local agencies, as well as entities who own extensive tracts, such as railroads.
As these rights of way permits renew, we've been paying annually increasing
fees, leading to increased O&M expenses associated with both the permit costs
and the labor to process them.
Business Case Justification Narrative Template Version: February 2023 Page 2 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 480 of 535

Right-of-Way Use Permits
1.2 Discuss the major drivers of the business case.
Performance & Capacity, and Failed Plant & Operations. In order to legally
construct, maintain and upgrade our facilities on agency owned lands, we must
acquire and renew rights of way permits. While we would continue doing this
work without this business case, the main benefits to the customer are being
able to negotiate lower fixed permit costs through lump sum payments, as well
as securing long term permits which will allow us to maintain reliability in our
infrastructure. In addition, we will reduce our labor costs for managing these
permits. We also reduce the risk of annual permits not being renewed or being
modified unilaterally.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
Right of way permitting on agency-owned lands is an ongoing and necessary
scope of work. We will continue doing this work without an approved capital
business case. This business case is based on our potential of saving the
company and our customers money over the long term by capitalizing permit
fees and negotiating lower costs through long term, lump sum payments.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
Our proposed investment is aligned with Avista's mission of delivering reliable
power to our customers at the most affordable price we can deliver. Right-of-
Way Use Permits are required for Avista to construct, maintain, and upgrade
electric infrastructure. Without these rights of way, we cannot meet our
objectives.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 481 of 535

Right-of-Way Use Permits
1.5 Supplemental Information - please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
Row Labels - Sum of Transaction Amount
2020 126,396.32
2021 202,717.87
2022 265,548.90
2023 383,587.04
Based on historic data, the program cost is approximately $250k annually.
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solutionto
the business problem identified above and wiry this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
We propose that through this business case, we will work with agencies to
negotiate lump sum payments for our rights of way permits, thereby securing
long-term, and lower fixed costs associated with acquiring and renewing these
permits.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 482 of 535

Right-of-Way Use Permits
This business case was developed utilizing a historical analysis of expenses
related to labor and other administrative costs in completing previous Right-of-
Way Use Permits.
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset ascription 2025 2026 2027 2028 2029
Capital $ $ $ $ $
08M $ $ $ $ $
direct costs of acquiring legal rights to maintain and/or extend rights-of-way
(ROW) for Avista's electric transmission/distribution and gas infrastructure on
public lands. Public land entities typically provide rights-of-way via permits, and
our goal is to acquire these at the lowest cost and for the longest term possible.
Absent such permits, Avista would be required to re-route linear projects around
public lands. Such re-routing would result in significant additional direct costs.
These would include additional materials and construction costs for longer
distances, increased ROW acquisition costs, and increased internal labor for
design, planning, permitting and project management. The range of such costs
is too uncertain to quantify but would be in the millions of dollars. By not
maintaining ROW permit approvals, Avista would risk legal action, fines and
ultimately, eviction from public lands.
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
capital $ $ $ $ $
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 483 of 535

Right-of-Way Use Permits
While there are no quantifiable indirect savings, were Avista unable to acquire
permits for public land ROW, we would be forced to seek alternative routes. In
addition to the direct additional costs, there would be indirect costs, such as
increased line losses due to increased distances, increased AFUDC, time
delays, etc.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
There are no alternatives to renewing Right-of-Way Use Permits.
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
Once the highway audit is complete Real Estate will have a complete
understanding of what portions of highway have Avista facilities that are not
permitted. We can use this audit to track permit application submittals and
approvals as we progress through the list. This list is currently maintained in
Excel. A regular audit should be scheduled every 2 years to verify checks and
balances are accurate and facilities are maintained in an approved status.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
This is a program, and the work is completed throughout the year based on
when agency permits are received. They will become used and useful once
the fully executed permit is in place.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
This program will be monitored by the Real Estate Manager, Sr. Director of
Environmental Affairs, and Department Financial & Budget Specialist. We will
evaluate the annual costs and savings to ensure the program is on track.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 484 of 535

Right-of-Way Use Permits
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Right-of-Way Use Permits and agree with
the approach it presents. Significant changes to this will be coordinated with and approved by the
undersigned or their designated representatives.
Signature: 7Z2/ Date: April 30th, 2024
Print Name: Ted Hermann
Title: Manager Real Estate
Role: Business Case Owner
Signature: F2 � '
9 Date: April 30, 2024
Print Name: Bruce Howard
Title: Sr Dir Environmental Affirs
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 7 of 7
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3, Page 485 of 535

DocuSign Envelope ID: DD7B2E08-519E-43D4-A38F-44D5BE1CF5BB
Sandpoint Service Center
EXECUTIVE SUMMARY
The existing Sandpoint Service Center facility was acquired in 1995 with an original construction
date estimated at 1957. The existing storage yard is becoming too small for ever-growing
inventory, which has almost tripled in the last 10 years. The unique voltage in the Sandpoint area,
different than the rest of the company, requires the local storekeeper to have more material than
yards of a similar size because Spokane cannot be utilized for backup. The property is too small
for our needs, and we are unable to purchase any additional land adjacent to the existing property.
We are currently looking for additional off-site storage to help accommodate the needs of the
Service Center. The property to the North, which Avista owns, is wetlands and currently the
drainage from this property runs through our yard creating stormwater issues.
The Sandpoint substation, currently adjacent to the Service Center, needs a rebuild in the next
15 years. The current plan is to locate the new substation on the land currently occupied by the
Sandpoint Service Center. When building substations, it is least expensive for Avista to build a
new station (with all the modern equipment and to current standards) on a parcel right next door
the old station. That allows us to keep the old station energized and serving load while we
build. Then we cut the load over to the new station with very little (or no) impact to our
customers. The farther we are from the old yard the harder the cut over is and the more
interruption our customers will see. This requires the Service Center be relocated prior to the
design phase of that substation.
The proposed solution to the business problems identified above was to relocate the Sandpoint
Service Center where we will locate the office, line dock, pole yard and the warehouse. The
building will be located at an already purchased parcel North of Sandpoint. This option would
allow for future growth. Due to unavailable funding the solution was proposed to provide a minimal
amount of funding to make improvements to the Sandpoint Service Center at its current location.
Improving the asphalt, storage areas and repairing building systems such as roofs, electrical and
HVAC will provide the Sandpoint team with a few improvements while we work towards the
preferred solution of a new Service Center in the next 10 years. A new storage yard located on
another property to the North is also included in this option to provide additional storage. These
improvements will cost $1.5M over two years.
This project would impact both Gas and Electric customers in both Washington and Idaho and
this project would benefit external customers in that the Service Center improvements can
improve efficiencies. Having all materials, supplies and staff in a safe location allows for better
use of resources and response times. Employees benefit from improved communication during
outages and ability to perform their tasks safely and effectively. The Sandpoint building and the
site have many critical systems that need replacement, including electrical, HVAC, plumbing and
roof systems. Many of these projects have been put on hold as there are functional issues in
Sandpoint that the location is unable to accommodate, such as trucks being unable to park at the
line dock due to current vehicle size and the inability to house a future Gas crew.
The Facilities Capital Steering Committee approved submission of this Business Case.
VERSION HISTORY
Version Author Description Date
1.0 L. Miller Initial draft on New Template 41412024
2.0 L. Miller 2 d Draft for BCRT Review 0412612024
BCRT Team Steve
BCRT Member Has been reviewed by BCRT and meets necessary requirements Carrozzo
413012024
Business Case Justification Narrative Template Version: February 2023 Page 1 of 18
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 486 of 535

DocuSign Envelope ID: DD7B2E08-519E-43D4-A38F-44D5BE1CF5BB
Sandpoint Service Center
PLANNED SPEND FOR PARTIAL FUNDING
The CPG partially funded this program in 2024 and 2025, below is the planned project spend for
those years. Many of the 2024 projects are in the planning process and will transfer to plant
before the end of 2024. This partial funding will be spent to provide the Sandpoint Service Center
with needed improvements to maintain functionality at the current location until a new Service
Center can be designed and built. It is expected that these improvements will allow the Service
Center to maintain functionality for the next 5-10 years at which point designing and relocating
the Service Center will be required.
YEAR LOCATION PROJECT ESTIMATED PLANNED
SPEND TTP
2024 Sandpoint Partial Roof Replacement $150,000 11/2024
2024 Sandpoint Asphalt Phase 1 $100,000 11/2024
2024 Sandpoint Warehouse Design $60,000 11/2024
2024 Sandpoint Exterior Lighting Upgrades $20,000 9/2024
2024 Sandpoint Furniture/ Chair Upgrades $120,000 11/2024
2024 Sandpoint Pole Storage Yard $200,000 11/2024
2024 Sandpoint Warehouse Construction Start $100,000 11/2025
TOTAL ALLOCATION $750,000
2025 Sandpoint Warehouse Construction $500,000 11/2025
2025 Sandpoint Asphalt Phase 2 $100,000 11/2025
2025 Sandpoint Interior Improvements $120,000 11/2025
2025 Sandpoint I HVAC and Lighting Upgrades $30,000 11/2025
TOTAL PLANNED ALLOCATION $750,000
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT($)
2024 $750,000 $650,000
2025 $750,000 $850,000
2026
2027
2028
2029
Business Case Justification Narrative Template Version: February 2023 Page 2 of 18
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 487 of 535

DocuSign Envelope ID: DD7B2E08-519E-43D4-A38F-44D5BE1CF5BB
Sandpoint Service Center
Project Life Span 5 years
Requesting Organization/Department Facilities
Business Case Owner Sponsor Eric Bowles Kelly Magalsky
Sponsor Organization/Department Facilities
Phase Planning
Category Program
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
BUSINESS PROBLEM - THIS SECTION MUST PROVIDE THE OVERALL
BUSINESS CASE INFORMATION CONVEYING THE BENEFIT TO THE
CUSTOMER, WHAT THE PROJECT WILL DO AND CURRENT PROBLEM
STATEMENT.
1.1 What is the current or potential problem that is being addressed?
The site has many issues and concerns that are forcing us to make an investment in the site or a
new location. The Sandpoint Service Center facility was acquired in 1995 for $181,483. We are
unsure of the original construction date but estimate it in 1957. Since that time, Avista has invested
$514,423 in capital improvements to the facility. Major maintenance upgrades include a new roof
and an asphalt overlay in the service yard. The issues and concerns are as follows:
Building Condition
The Sandpoint Service Center building had a Building Condition Assessment completed by a third
party in 2017. In that survey, items were identified that needed immediate replacement or repair
totaling $150,000. The current backlog and requirements, as of today, total $912,000 in repairs and
replacements. There is additional work identified that would need to be completed in the next 5 years
bringing the backlog and requirements to $1,193,000. The estimates are for like for like
replacements and make no operational building or site improvements. The Inventory Condition
Report was completed to review the existing condition of the structure as well.
There are specific items that need to be replaced per the third-party survey we had completed in
2017. Items like the emergency generator, electrical panels, unit heaters and bollards. There is also
extensive repair needed to the existing CMU walls. There is widespread asphalt damage and
requires complete replacement throughout the Service Center.
✓``y`�
Business Case Justification Narrative Template Version: February 2023 Page 3 of 18
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 488 of 535

DocuSign Envelope ID: DD7B2E08-519E-43D4-A38F-44D5BE1CF5BB
Sandpoint Service Center
00
y
1
There are a large number of small items that need to be repaired and replaced in the next 5 years.
The flooring needs to be replaced, lighting needs to be upgraded, the entire building inside and out
needs paint,and the roof hatch needs to be replaced. The plywood roof decking needs to be replaced
in areas and the HVAC system and window units need to be upgraded.
All the roll up doors need to be replaced at the site. Many are damaged and beyond repair. They
are part of the original construction and are not insulated and do not meet today's standards. The
site has extensive damage to the concrete sidewalks and paving and needs replacement. The
fencing requires extensive work and has a lot of damage from the snowplows and winter weather.
Most of this work would be capital investments that would need to be written off once the building is
demolished to accommodate the Sandpoint Substation in the next 15 years. A small portion, about
5%, of this identified work is O&M, including paint and fence repair.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 18
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 489 of 535

DocuSign Envelope ID: DD7B2E08-519E-43D4-A38F-44D5BE1CF5BB
Sandpoint Service Center
� C=
i
a
I i
�a
Current Sandpoint Service Center:
Business Case Justification Narrative Template Version: February 2023 Page 5 of 18
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 490 of 535

DocuSign Envelope ID: DD7B2E08-519E-43D4-A38F-44D5BE1CF5BB
Sandpoint Service Center
i
I
Alt. . .
(I f� •E`er`'
i.9
Materials/Storage
The existing storage yard is becoming too small for ever-growing inventory, which has almost tripled
in the last 10 years. Due to the unique voltage only in the Sandpoint area,the local storekeeper must
keep more material than other yards as Spokane cannot be utilized for backup. Facilities has
everything it can to capitalize on the existing storage space available. However, the property is too
small to meet the needs of our customers and there is an inability to purchase any additional adjacent
land.
A further issues and risk to the storage yards is the creek that runs through our yard yearly
floods. We are currently looking for additional off-site storage to help accommodate the needs of the
Service Center.
Historical Warehouse Inventory-Sandpoint:
1,aco,aoo.
1,6W,000. —
1,400,000. —
1,200,000. --
1,000,00a —
800,000.
800,000.
400,000.
200,000
0.
°°
Every spring a creek expands and runs through the back of the Sandpoint yard resulting in the crews
working in 18"of water to load poles.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 18
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 491 of 535

DocuSign Envelope ID: DD7B2E08-519E-43D4-A38F-44D5BE1CF5BB
Sandpoint Service Center
is
Environmental/Compliance
Many of the building systems are antiquated and have reached the end of their useful life. We expect
some of these systems to fail in the next 5 years. If the systems fail, we will need to replace them to
allow for continued use of the structure. As the building will be demolished to accommodate the
Sandpoint substation in the next 15 years investing in these systems could result in a large write off
at that time.
This site has environmental concerns and needs to have a review of the water runoff plain and
upgrades will need to be made. One concern is the public highway runoff, which the state has made
some changes to, but facilities and environmental need to look at its impact on maintenance on the
site. The vehicle wash bay also needs to be properly mitigated, which is not currently happening.
Facilities estimates that installing a proper drainage and oil/ water separator system would cost
approximately$250k.
The existing building has minor code compliance and security issues. These include no ADA access
or restrooms and no access control system or automatic gates. The interior of the main building
needs an update and possibly a large reconstruction or renovation. The layout is no longer conducive
to today's business needs.The office space is limited preventing current staff from having dedicated
seating. There are many ADA issues and much of the construction does not comply with current
code requirements.
Employee/Customer Impact
There are currently 22 employees working out of the Sandpoint Service Center. In addition, there
are contract crews from NPL that work out of that office and leave their equipment in the yard. We
do not have enough parking for the current employee/contractor count. One of the employee's trucks
had $3,500 worth of damage due to ice unloading while parked in an undesirable area because we
had no room with 24" of snow that forces us out of most areas. Employees also experience icy
walking conditions throughout the exterior of the service center. The roof of the dock area leaks
creating icy patches that must be continually de-iced and sanded. It is very hard to shovel and plow
safely due to the paving in Sandpoint.
The weather during the winter months in Sandpoint is much worse than in the Spokane area.
Sandpoint averages 59 inches of snow per year and employees spend a great deal of time shoveling
snow off their equipment and materials to function in the winter because it is not under cover. One
of the canopies on site collapsed a few years ago due to snow load, the structure was unsafe, built
very poorly. The remaining structure is very narrow, preventing vehicles from being able to utilize
the cover.
The interior of the main building is in need of an update and possibly a large reconstruction or
Business Case Justification Narrative Template Version: February 2023 Page 7 of 18
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 492 of 535

DocuSign Envelope ID: DD7B2E08-519E-43D4-A38F-44D5BE1CF5BB
Sandpoint Service Center
renovation. The layout is no longer conducive to today's business needs. There is no meeting room
for employee meetings or for community use. Employees use the breakroom when meetings are
required and impact the use of that space. There is no room for exercise equipment to help assist
our employees with fitness.
Operational Efficiency/Safety
Emergency exit lighting and smoke detection systems are missing from the building. This is a
critical failure and would need to be rectified if a new building is not built. The existing building has
minor code compliance and security issues. These include no ADA access or restrooms and no
access control system or automatic gates.
There isn't enough room to park company vehicles in covered areas. Avista has purchased larger
and larger vehicles over the last 15 years which has caused a systemic issue with vehicle size line
dock parking. The line docks were designed for the vehicles at that time which no longer safely fit.
Many of the company vehicles that are parked inside are parked with few inches to spare between
the dock and the roll up door. The bays are not large enough due to larger equipment purchased
for today's needs. This provides limited movability around the trucks and requires that the
employees driving must back up into the dock.
The mechanic's bay has taken over a bay in the truck barn to accommodate the need to repair
vehicles. This has moved another vehicle out into the weather. There is also no means of washing
the vehicles and the mag chloride (road de-ice/salt) is creating an incredible amount of down time
on our fleet due to the corrosiveness over time.
1.2 Discuss the major drivers of the business case.
The major drivers of this business case are Asset Condition and Safety.
The Sandpoint building and site have many worn buildings and assets in dire need of
replacement, as many of capital projects have been put on hold until the future state of the site
is known (see section 1.1). The upcoming Sandpoint Substation has caused a hold to be placed
on any improvements to this site as the plan is to demolish the building. This is causing the
current Asset Condition to fall well below acceptable. The lack of investment in these assets
has resulted in safety concerns throughout the building and site. Examples of safety items
include risk of slips, trips, and falls and snow/ ice shedding from roofs. The Sandpoint Service
Center has been considered for replacement since 2018.
This project would benefit external customers in that the new Service Center can improve
efficiencies. Having all materials, supplies and staff in one location allows for improved use of
resources and response times. Employees benefit from improved communication during
outages and ability to perform their tasks safely and effectively. The current situation in
Sandpoint is such that Avista will need to address the materials yard shortage by purchasing
additional property in the coming years, to meet this space need.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The funds being requested are to enable the Sandpoint Service Center to meet its customer
needs both internally and externally until a replacement facility is constructed at a later,
unspecified date. The Sandpoint Service Center had a Building Condition Assessment
completed by a third party in 2017 that identified immediate replacement or repair needs totaling
$150,000. There is also a current backlog totaling$912,000 in repairs and replacements. Other
work identified needing to be completed in the next 5 years brings amounts to approximately
$1,193,000. and includes replacing the basic building systems s; the septic system; and the
entire service yard asphalt and drainage.
Business Case Justification Narrative Template Version: February 2023 Page 8 of 18
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 493 of 535

DocuSign Envelope ID: DD7B2E08-519E-43D4-A38F-44D5BE1CF5BB
Sandpoint Service Center
The upcoming Sandpoint Substation has caused a hold to be placed on any improvements to
this site as the plan is to demolish the building. However, this caused the current Asset
Condition to fall well below acceptable. The lack of investment in these assets has resulted in
safety concerns throughout the building and site.
Asset Condition Requirements:
Requirements
600,000
Capital ReplaceM—
�ComponentRenewalatESL 400,009
Defiaency Repairs
Delia ncy Repaira(Replao3oe6 200,000
Preventative Maintenan¢
2024 2025 2026 2027 2028
Year.
Account ♦ 2024 2025 2026 2027 2028 Grand Total
Capital Replacements $163,881 $28,025 $0 $0 $0 $191,905
Component Renewal at EA $120,100 $8,589 $67,358 $0 $110,480 $306,535
Deficiency Repairs $27,226 $0 $0 $0 $0 $27,226
Deficiency Repairs/Replacements $638,763 $0 s0 $0 $0 $638,763
Preventative Maintenance $14,794 $15,238 $15,695 $16,166 $16.65' $78,545
Grand Total $964,765 $51,852 $83,054 $16,166. $127,1391 $1,242,976
Active Assets 5 5 5 5 5
Total Replacement Value $6,661,417 $6,861,260 $7,067,098 $7,279,331 $7,497,484
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategyic Goals
The major reason to perform this project is to align with Avista's Focus Areas of Our Customer
and Our People. Being able to better facilitate in providing service to our external customers
safely and efficiently is a cornerstone of Avista and the facilities our crews report to is a vital
piece of this service effort. These requested improvements will enable the Sandpoint Service
Center to meet its customers' needs up until a new facility is constructed.
Business Case Justification Narrative Template Version: February 2023 Page 9 of 18
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 494 of 535

DocuSign Envelope ID: DD7B2E08-519E-43D4-A38F-44D5BE1CF5BB
Sandpoint Service Center
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
The Asset Condition Study and Asset Condition Report for the Sandpoint Service Center were
used to help determine the best option to resolve the various business problems. These reports
help to understand the Asset Condition needs of the existing structure and the cost impacts to
those improvements.
The Facilities Building Matrix was used to compare the Avista owned assets to each other. This
helped to determine which locations require new buildings to be constructed, remodels needed,
or upgrades to existing structures. This matrix prioritized the locations based on current location
and site suitability, condition rating, current utilization, site risk and environmental risk.
prawn pmm�pn mentmea 6rmrpnmenSit
Sit. Bullt Cu ent Slze Sulbhlllly 51te CRating site Otilbat- Site Risk taI RISK IIOIN Stming e<ommeneee Course ofpabn
Pullman 1959 61 1, v Poor it Over COP-,,, Metl Metl Z IS.,Hig6wpYoreess,stte droewpe osues 10 Sellantl Relo[ate Fadlty
Santlppin[ 195) 63 Mee r Poor Over-P--,, -,,h High ern res ennvrev/spdngtl'vinvgejbvtlipg 10 sell pndge .-Wly
Davenport 1966 54 ar or ov Over Capacity Med High 3OJ)rte vNPpper nbehi[g velritks/smnsjwmerztprvgebyriver20 Sell antl NebepteF ft,
Grangevllle 1933 g) — 1Poor r 1 Over Capacity .,,h High 3 20 Sell antl Rewcpte Fa o
ehewelah 1985 3s 1, on Pov' r f0/f Metl I High 3 access H39SFNerjbpdz pzapertyerchSpmp 20 SellaM Reweave or Merge with
CdvlNea OP)
Othello 1974 16 1 Z Slppee/x+nM ypNhazare/eminpge 11 Sell andR—1,1-ht,
ttzvllle I955 6S 2 1 Rvyvnd ev ssues Renovote exis[i'ybuilding a'hulltl
Spokane Valley Call Crater 19)9 di XLrq Fai FairI Good 1 Over Capacity 4 Hgh I Sesurtt,vsues ontl dCl—cress /high rpeM hg 17 orn—one Operate or Sell an0
wih
St Maries 19)d 46 Med v v r 3 1 Metl 1Med 2 pep sip,winmsWedonger/zswpge voMon lWYeorppodpbin I) r and Operate Off-/
CDA 1990 I6 Good I F,11 3 F.11 2Ove COPo[I(V/ MId a sWvn/nvpeMvwrce vM vwibMeymmpuz 1C Yazd Refresh/ExppnLpn
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elarkston 19)s es 19 Gopd a ce napwe raze Refresh/6..pawpn
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latlr Stewart Training 1993 17 #rg Good r ndoWe Tiaikrs innpowepnd#ion/Remedimedsprn sire/Cwp Fibe.nnv12Site Refresh
Omflno 19)CI s0 Sm — 2 Fair 2Fvir2 Adequate 2 Gjfire to Maintain and Operot
Colfax 1999 30 Sm Good r 2 3Expvndode1 2 —ftPCYfi­—PPWf.1f—­1— 10 antl Opera
4w+rton Call Center 19% M XVq Goad Gaud1 r 3 M,d 3 nMpSecudrr— ]O ontl Operor
OreTCgpaciN/ Manrprn
Metlfortl 1990W
r rs vp— 10 Mainmin ontl Ot,Tekoa 19)1 v r Adequate Low Med 1 NewR.4 lO 4 10 Malntaln and OperateKellogg 1960 GaW Fvir Adequate Med Med 1 Svarp Communlrypzesenre ueth benejrt..O... 10 Malntaln and OperateGrans pass 1960 a n2 A--- I Inw I I I Low nrcp are/m neetl 9 nta(n antl Operor
The Inventory Condition Report is a report the Paragon Asset Management System provides
that can be used to assess the condition of all the building assets found at the Sandpoint Service
Center.
Please do not attach any requested items to the business case,rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 10 of 18
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 495 of 535

DocuSign Envelope ID: DD7B2E08-519E-43D4-A38F-44D5BE1CF5BB
Sandpoint Service Center
10-Year Forecast of Backlog and Requirements:
*Based on typical yearly spend in Sandpoint, does not include any of the planed $1.5M spend
Forecast Analysis
$1,600,000 0.1800
f1,400,000 ♦ -�-- -0.1600
0.1400
$1,200,000
0.1200
sl,000,000
0.1000
$800,000
0.0800
$600,000
0.0600
$400,000
0.0400
$200,000 0.0200
$0 --- o.0000
2024 2024 2025 2025 2026 2026 2027 2027 2028 2020 2029 2029 2030 2030 2031 2031 2032 2032 2033 2033 2034
StartingBaddog Requirements M Spending EndingBacWog FCI
Starting Badd 742 589
.Year
Grouping El .Category 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
Capital $721,319 $966,012 $904,820 $1,037,629 $1,050,088 $1,184,101 $1,270,543 $1,308,659 $1,479,354 $1,576,079
1 Backlog(Start of Year) f)&M $21,269 $18,821 $14,946 $15,394 $15,856 $16,331 $16,821 $17,326 $17,846 $18,381
Baddog(Start of Year)Total $742,589 $904,833 $919,766 $1,053,022 $1,065,944 $1,200,433 $1,287,364 $1,325,985 $1,497,199 $1,594,460
Captal $155,137 $8,589 $123,234 $0 $110,488 $61,101 $0 $136,868 $75,417 $0 $670,835
2 Requirements O&M $14,794 $15,238 $15,695 $16,166 $16,651 $17,151 $17,665 $18,195 $18,741 $19,303 $169,601
Requirements Total $169,931 $23,827 $138,929 $16,166 $127,139 $78,252 $17,665 $155,063 $94,158 $19,303 $840,436
3 Backlog+Requirements $912,520 $928,660 $1,058,695 $1,069,189 $1,193,083 $1,278,685 $1,305,029 $1,481,048 $1,591,358 $1,613,763
Capital $20,000 $20,600 S21,218 $21,855 $22,510 $23,185 $23,881 S24,597 $25,335 $26,095 $229,277
4 Budget O&M $20,000 $20,000 $20,000 $20,000 $20,000 $20,000 $20,000 920,000 $20,000 $20,000 $200,000
Budget Total $40,000 $40,600 $41,218 $41,855 $42,510 $43,185 $43,881 $44,597 $45,335 $46,095 $429,277
Capital $16,516 $16,134 $20,648 $18,126 $10,963 $11,666 $0 $9,261 $24,924 $11,207 $139,445
5 Spending 06M $17,791 $19,549 $15,695 $16,166 $16,651 $17,151 $17,665 $18,195 $18,741 $19,303 $176,908
Spending Total $34,307 $35,683 $36,344 $34,292 $27,614 $28,817 $17,665 $27,457 $43,665 $30,510 $316,353
Capital $3,484 $4,466 $570 $3,728 $11,547 $11,519 $23,881 $15,336 $411 $14,888 $89,830
6 Variance(Budget minus Spending) G&t4 $2 209 $451 $4,305 $3,834 $3,349 $2,849 $2,335 $1,805 $1,259 $697 $23,092
Variance(Budget minus Spending)Total $5,693 $4,917 $4,874 $7,562 $14,8% $14,368 $26,216 $17,140 $1,670 $15,585 $112,922
Capital $860,205 $878,466 $1,007,406 $1,019,503 $1,149,613 $1,233,536 51,270,543 $1,436,266 $1,530,173 $1,564,872
7 Backlog(End of Year) O&M $18,273 $14,510 $14,946 $15,394 $15,856 $16,331 $16,821 $17,326 $17,846 $18,381
eaddog(End of Year)Total $878,478 $892,977 $1,022,352 $1,034,897 $1,165,469 $1,249,868 $1,287,364 $1,453,592 $1,548,019 $1,583,253
9 FCI 0.1280 0.1264 0.1405 0.1380 0.1509 0.1571 0.1571 0.1723 0.1781 0.1769
10 Taal Replacement Value $6,861,260 $7,067,098 $7,279,111 $7,497,484 $7,722,408 $7,954,081 $8,192,703 $8,438,484 $8,691,639 58,952,388
11 Spending as%of TRV 0.50% 0.50% 0.50% 0.46% 0.36% 0.36% 0.22% 0.33% 0.50% 0.34%
Business Case Justification Narrative Template Version: February 2023 Page 11 of 18
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 496 of 535

DocuSign Envelope ID: DD7B2E08-519E-43D4-A38F-44D5BE1CF5BB
Sandpoint Service Center
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
SHORT TERM ALTERNATIVE SOLUTION- PROVIDE FUNDING FOR
SPECIFIC IMPROVEMENTS AT THE CURRENT SANDPOINT SERVICE
CENTER- $1.5M
Provide the Sandpoint Service Center with a temporary solution while we work towards the
recommended long-term solution. Providing $1.5M over two years will allow for improvements
to the parking lot and storage yard as well as many operations needs of the business. This
$1.5M allocation will be spend across both Asset Condition and Operation capital projects. In
an effort to ensure the best functionality for the Sandpoint team over the next 5-10 years the
allocation will be as follows:
Asset Condition Projects: $520,000
Repair of the canopy and roof, to improve safety and eliminate roof leaks. Replacement of the
asphalt and added asphalt in the storage yard, to reduce pooling water and ice and provide
safer access for the forklift. Lighting and HVAC upgrades due to failing systems.
Operational Request Projects:$980,000
Construction of a new temporary storage yard off Bronx Road, at the future Service Center site.
Construction of a new warehouse pole building, to improve safety for the storekeeper and
access to materials. Renovation of the existing warehouse to provide a meeting room and
additional office space for staff.
Providing these improvements will allow the Sandpoint Service Center team to work more
efficiently over the next 10 years. While this does not solve for all of the Business Problems,
including much of the asset condition issues it does provide solutions for many of them.
RECOMMENDED LONG TERM SOLUTION- NEW SANDPOINT SERVICE
CENTER- $18M
In the next 10 years we need to prepare the area for the next 50 years of service,we are asking
to invest in a new building. We propose constructing a new line dock facility and covered
storage buildings for materials inventory, expensive equipment, provide modernized offices,
meeting rooms, and mini warehouse. The facility will be fully fenced, and card reader access
gates installed. The HVAC systems will be modernized, which will provide energy savings.
The proposed solution to the business problems identified above is to build a new Service
Center. Avista currently owns a vacant property where we would locate the new Service
Center, the pole yard and warehouse. This option would allow us to develop the existing
property using any remaining acreage for future growth.
The new Service Center will include environmentally protected transformer storage areas and
adequate storm water protection. This will include oil/water separators for the entire facility,
allowing for greater warehouse flexibility for transformers. This is the environmental standard
for design for Avista and meets the legal requirements as well. The new facility will centralize
all of Sandpoint crew functions into one location.
The new Service Center would be designed to meet the needs of today's employees and would
meet current code requirements. These needs include both men's and women's ADA
restrooms and showers,workspace for all necessary employees, meeting space for both Move
Safe and EOP's, workout equipment and warehousing. All the building systems would be
Business Case Justification Narrative Template Version: February 2023 Page 12 of 18
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 497 of 535

DocuSign Envelope ID: DD7B2E08-519E-43D4-A38F-44D5BE1CF5BB
Sandpoint Service Center
designed to today's technology and are planned to be more efficient than the existing location
due to technology improvements.
This new substation project, at this location, is already being discussed and currently is on the
15-year plan according to the Engineering Round Table.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
There is currently an identified backlog of$742K in Asset Condition work needed at the
Sandpoint Service Center. In 2017 Terricon identified $150K in work on their initial
assessment. This list is growing every year as our building ages and new items are identified
that need replacement. At the current funding level this backlog of capital work will continue to
grow. The backlog is growing faster than our current funding model can accommodate.
Making the investment into the existing structure will not solve the remaining problems of
limited space, safety and environmental.
Environmental Compliance has rated the Sandpoint Service Center as a 3.
Sandpoint
Element Score Reason
Surface Water 0
Floodplain 0
Historic District 0
Adjacent Use 1 Heavy MF residential in vicinity,not ideal
Zoning 1 Zoned Res.MF,CUP required,not ideal
Total 3
2.3 Summarize in the table and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital None $0 $0 $0 $0 $
0&M Energy savings $0 $0 $0 $0 $0
Direct (Based on Revised Solution):
• None
2 Please do not attach any requested items to the business case,rather be sure to have ready access
to such information upon request.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2023 Page 13 of 18
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 498 of 535

DocuSign Envelope ID: DD7B2E08-519E-43D4-A38F-44D5BE1CF5BB
Sandpoint Service Center
2.4 Summarize in the table and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital Use of existing land $0 $0 $0 $0 $0
00 Business Operations Improve $0 $0 $0 $0 $0
Indirect (Based on Revised Solution Funding):
• None
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, which were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternative 1: SANDPOINT RENOVATION/STORAGE YARD LAND
O&M: $95,000 CAPITAL: $8,193,000
To avoid constructing a new Sandpoint Service Center,Avista would need to continue upgrading
the existing Service Center building.This would include several hundred thousand dollars'worth
of upgrades and improvements. Purchasing adjacent properties and expanding the Service
Center would be very costly due to the cost of land in the adjacent Sandpoint area and the risk
of building an already identified wetland.
Items were identified that needed replacement or repair under Operations and Maintenance
totaling $95,000 over the next 5 years. Another$1,193,000 in repairs and replacements were
identified that would need to be completed under capital spend in the next 5 years, including
replacing the basic building systems such as electrical, domestic water piping,the plumbing and
the entire service yard asphalt and drainage, including management of the stormwater and
wetlands.
Facilities estimates that an interior remodel including ADA upgrades to restrooms and
relocation/ remodel of office and shop space to accommodate business changes would total
another$2,000,000 over the next 5 years.
We would need to create an additional storage yard at an already purchased property outside
of town and possibly additional structures to accommodate larger trucks. This would require
that crews drive to and from this new storage yard/ secondary location several times a day.
Impacting response times and reducing productivity. The estimate for this land development
and vehicle storage barn is$5,000,000.
Alternative 2: MAINTAIN CURRENT LOCATION
O&M: $95,000 CAPITAL: $3,193,000
Choosing to maintain the current location would greatly impact the Operations and Maintenance
budget for the Sandpoint facility. The existing building condition would require that some large
Capital investment be made to create a useable and safe location for employees to work. The
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 14 of 18
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 499 of 535

DocuSign Envelope ID: DD7B2E08-519E-43D4-A38F-44D5BE1CF5BB
Sandpoint Service Center
building would require an extensive renovation to try to accommodate the current employees
and materials.
The current land is not sufficient for the needs of the Sandpoint Service Center team. Materials
would need to be stored at other locations including Clarkston and Spokane greatly impacting
response times and customer restoration as materials would not be on hand.
Items were identified that needed replacement or repair under Operations and Maintenance
totaling $95,000 over the next 5 years. Another $1,193,000 in repairs and replacements were
identified that would need to be completed under capital spend in the next 5 years, including
replacing the basic building systems such as electrical, domestic water piping, the plumbing and
the entire service yard asphalt and drainage, including management of the stormwater and
wetlands.
Facilities estimates that an interior remodel including ADA upgrades to restrooms and
relocation/ remodel of office and shop space to accommodate business changes would total
another$2,000,000 over the next 5 years.
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
Confirm the scoping documentation and approved design to the final constructed solution that
provides room for growth, expands technology requirements, and adheres to safety and security
best practices. Some of these solutions would include items such as:
1) Materials/ Storage: Provide warehouse space that meet the needs of the Stores team and
Operations. Reduction in trips back to Spokane or other storage yards for materials(currently
not tracked).
2) Environmental/ Compliance: Ensure that the building and site meets with Avista's
environmental standards. Currently not meeting the base standards for storm water runoff.
3) Employee/Customer Impacts: Room for employee or operations growth
4) Operational Efficiency: Ensure that operational needs of employees are being met, increase
of productivity and reduced windshield time for crews.
Asset Condition: Provide systems and materials that meet with Avista standards and current
building codes and requirements.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
The CPG partially funded this program in 2024 and 2025, below is the planned project
spend for those years. This partial funding will be spent to provide the Sandpoint Service
Center with needed improvements to maintain functionality at the current location until a
new Service Center can be designed and built. It is expected that these improvements
will allow the Service Center to maintain functionality for the next 5-10 years at which point
designing and relocating the Service Center will be required.
YEAR LOCATION PROJECT ESTIMATED PLANNED
SPEND UP
2024 Sandpoint Partial Roof Replacement $150,000 11/2024
2024 Sandpoint Asphalt Phase 1 $100,000 11/2024
Business Case Justification Narrative Template Version: February 2023 Page 15 of 18
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 500 of 535

DocuSign Envelope ID: DD7B2E08-519E-43D4-A38F-44D5BE1CF5BB
Sandpoint Service Center
2024 Sandpoint Warehouse Design $60,000 11/2024
2024 Sandpoint Exterior Lighting Upgrades $20,000 9/2024
2024 Sandpoint Furniture/ Chair Upgrades $120,000 11/2024
2024 Sandpoint Pole Storage Yard $200,000 11/2024
2024 Sandpoint Warehouse Construction Start $100,000 11/2025
TOTAL ALLOCATION $750,000
2025 Sandpoint Warehouse Construction $500,000 11/2025
2025 Sandpoint Asphalt Phase 2 $100,000 11/2025
2025 Sandpoint Interior Improvements $120,000 11/2025
2025 Sandpoint I HVAC and Lighting Upgrad $30,000 11/2025
es
TOTAL PLANNED ALLOCATION $750,000
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
Facilities Capital Steering Committee
Once the project list is assembled, the finalized list of projects is approved by the Capital
Facilities Steering Committee. This Committee of Directors is responsible for approving the
submission of Business Cases to the Capital Planning Group and approval of projects and any
changes within this program.
In the past this has most often been:
• Director of Shared Services
• Director of Environmental Affairs
• Director of Financial Planning and Analysis
• Director of Generation, Production, Substation Support
• Director of IT and Security
• Director of Natural Gas
The project shall use certain Project Management Professional (PMP) guidelines and
procedures during this project.
A Project Execution Plan, consisting of the documents below, will be drafted and approved by
the SteerCo described in Section 3.1 (A).
• Project Charter, Change Management Plan, Communication Management Plan, Cost
Management Plan, Procurement Management Plan, Project Team Management Plan,
Risk Management Plan and Risk Register, Schedule Management Plan, Scope
Management Plan, and Project Execution Approval Form.
Each month, the project manager will provide the following information either at the scheduled
SteerCo meeting, or via email.
• Approved Yearly Budget, Accrued Yearly to Date, Year Estimate at Complete, Year
Variance at Complete,Approved Lifetime Budget,Accrued Life to Date, Lifetime Project
Estimate at Complete, and Lifetime Project Variance at Complete.
Each month, the SteerCo will make decisions on cost, scope, or budget items as required by
the Project Execution Plan. The project manager reserves the right to present items not outlined
in the Project Execution Plan if he/she determines its importance is relevant to SteerCo input.
Business Case Justification Narrative Template Version: February 2023 Page 16 of 18
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 501 of 535

DocuSign Envelope ID: DD7B2E08-519E-43D4-A38F-44D5BE1CF5BB
Sandpoint Service Center
The final decisions regarding these items, especially certain change requests as required by the
Project Execution Plan, will be presented to, and voted upon by the SteerCo. The decisions will
be documented in the monthly meeting minutes of the SteerCo for documentation and oversight.
It will be the Project Manager's role to monitor the scope, budget, and schedule and present the
results to the SteerCo, regardless of they are within tolerances, or not.
Business Case Justification Narrative Template Version: February 2023 Page 17 of 18
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 502 of 535

DocuSign Envelope ID: DD7B2E08-519E-43D4-A38F-44D5BE1CF5BB
Sandpoint Service Center
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the <Sandpoint Service Center>and agree with
the approach it presents. Significant changes to this will be coordinated with and approved by the
undersigned or their designated representatives.
DocuSigned by:
Signature: bw�,s Date: May-01-2024 i 12:44 PM PDT
Print Name: r,@cj7M1ff4c2_-
Title: Corporate Facilities Manager
Role: Business Case Owner
DocuSigned by:
Signature: S� Date: May-01-2024 3:28 PM PDT
Print Name: Ke ry°�1agas�cy
Title: Director-Shared Services
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 18 of 18
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 503 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
EXECUTIVE SUMMARY
This program is responsible for the capital maintenance, site improvement, and furniture budgets
at over 75 Avista offices, Service Centers, storage buildings, and pole structures (1.2M total
square feet) companywide. This program is intended to systematically address lifecycle asset
replacements (examples: roofing, asphalt, electrical, plumbing), lifecycle furniture replacements
new furniture additions (to support growth), and business additions or site improvements. These
can include requests for productivity or business-related needs (examples: storage yard
reconfigures, office space changes and improvemens and additions due to changes in the
business.
Facilities apportions approximately 50% ($2,625,000 for 2025) to Asset Condition work that is
identified using Paragon Asset Condition software, 30% ($1,575,000 for 2025) is set aside for
Manager Requested projects, and 20% ($1,050,000 for 2025) is kept aside for unexpected capital
needs and furniture replacements. There is currently $15.8M in Asset Condition backlog and
requirements identified using the Paragon Asset Condition software. A funding of$5.25M in 2025,
and an additional 3% for inflation in remaining years will provide Facilities with the ability to keep
a level backlog for the next 5 years. Underfunding this program will increase the backlog of work
creating a bow wave in the coming years as Avista's aging assets continue to need improvements.
This program supports Avista's entire Service Territory and all service codes and jurisdictions.
Performing adequate Asset Management allows the Company to preserve and fully utilize its
properties while reducing expensive repairs in the long term. It also ensures a safe environment
for people and equipment. Damaged or poorly maintained facilities can create very real safety
risks and associated liability for employees, customers, and contractors. For internal stakeholders
such as employees and management, well- maintained assets ensure safe and efficient working
envoronments. This leads to improved employee morale and productivity as equipment and
facilties function optimally and reliably. When assets like machinery, buildings, and systems are
in top condition, external customers benefit from consistent, high- quality service.
The Facilities Capital Steering Committee approved submission of this Business Case.
VERSION HISTORY
Version Author Description Date
1.0 L. Miller Initial draft on Revised Template 41812024
2.0 L. Miller Revised draft 412612024
BCRT Team Steve
BCRT Member Has been reviewed by BCRT and meets necessary requirements Carrozzo
4/29/2024
Business Case Justification Narrative Template Version: February 2023 Page 1 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 504 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT($)
2024 $5,200,000 $5,000,000
2025 $5,250,000 $5,000,000
2026 $5,410,000 $5,200,000
2027 $5,700,000 $5,500,000
2028 $5,900,000 $5,700,000
2029 $6,195,000 $6,000,000
Project Life Span 1 year
Requesting Organization/Department Facilities
Business Case Owner Sponsor Eric Bowles Kelly Magalsky
Sponsor Organization/Department Shared Services
Phase Planning
Category Program
Driver Performance & Capacity
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
Many of the Service Centers in Avista's territory were built in the 1950s and 60s and are starting
to show signs of severe aging. Almost half of Avista's assets were built before 1980. Most of
the building systems, such as electrical and mechanical, are past their recommended life based
on recognized industry standards defined by Building Owners and Managers Association
(BOMA), and International Facility Management Association (IFMA) and are requiring
renovation or replacement. Many of the original campus layouts and buildings at our Service
Centers are no longer functional due to changes in vehicle size, materials storage needs, and
operational flow.These sites and structures were designed for the requirements of the business
at the time and over the years those needs have grown and transformed. These changes have
caused the necessity for project funding to address changing business and site requirements.
Business Case Justification Narrative Template Version: February 2023 Page 2 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 505 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
ER7001/ 7003 Requested vs. Funding
$9,000,000
$8,000,000
$7,000,000
$6,000,000
$5,000,000
$4,000,000
$3,000,000
$2,000,000
$1,000,000
2018 2019 2020 2021 2022 2023 2024
■Requested ■Initial Funding ■End of Year Funding ■Asset Condition Backlog
*The Asset Condition drop in 2023 is due to funding some larger Asset Condition projects.
This backlog is continuing to grow due to the average age of our infrastructure. As projects are address the backlog is
adjusted and those projects are removed. Larger projects can impact the backlog,as noted in 2023.
Funding backlog
There is an identified backlog and requirements totaling over$15.8M (as of April 2024) in Asset
Condition work needed across the system of assets Facilities manages. In 2017 Terricon identified
$6M in work on their initial assessment. This list is growing every year as our buildings age and
new items are identified that need replacement. The backlog is growing faster than our current
funding model can accommodate.
2024 ER7001/ 7003 Funding Breakdown
■ Manager Requested Prioritized Work ■Condition Assessment Work
■2023-24 Carryover Projects ■Safety/Drop In/Failures
■ Furniture
Capital Lifecycle Asset Replacements ER 7001
Business Case Justification Narrative Template Version: February 2023 Page 3 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 506 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
This portion of the Structures and Improvements Program is based on the results of the Facilities
Condition Assessment Survey. This survey considers the condition and lifecycle of each Facilities
asset. Assets are graded and those requiring replacement within the next 10 years will be
estimated and scheduled for replacement at an appropriate year during the 10-year time frame of
the survey. These identified projects are prioritized within the Paragon Asset Management system.
This process takes into consideration risk, safety and impact to the business. Buildings as a whole
are assigned a Facilities Condition Index (FCI) as part of the survey to help compare future capital
needs and drive the decision of continued capital expenditures vs. possible replacement.
Examples (asphalt and structural issues):
g �
k h kr44 af�n,r
,3
Al
Furniture Replacement or Additions: ER 7003
The Furniture portion of the program is for new furniture solutions as well as replacements of
existing assets based on industry standard lifecycles, condition, and availability of parts. The
furniture program is also meant to support new furniture additions required as part of approved
remodel and reconfiguration projects. The hybrid work environment is impacting this program as
we work toward solutioning ergonomic needs of employees working outside of the typical office
environment.
This evolving process is also impacting how the existing office space is utilized and designed to
support work. This results in Facilities examination of how spaces are being utilized and can be
better optimized for performance and experience. As technology and work styles transform, the
workspace for impacted employees needs to be modified to support the business needs. These
modifications can include furniture reconfigures, replacements and upgrades and can also include
large scope renovations.
The lifecycle of commercial office furniture is typically 10-15 years and portions of our furniture
assets across the business needs to be replaced every year in an ongoing replacement process.
Facilities estimates that the majority of our panel systems furniture, approximately 70%, is well past
Business Case Justification Narrative Template Version: February 2023 Page 4 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 507 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
this lifecycle. The average 6' x 9'fully ergonomic workstation, the Avista standard size, is $1 OK to
replace. The furniture additions and replacements portion of the program is typically funded at
$400K per year.
Examples:
i
I
Business Additions or Site Improvements: ER 7001
This portion of the program is intended to support site improvement requests and productivity or
business-related needs. Project requests are made by Managers throughout Avista, including both
operations and office staff. These requests are submitted in June of the previous year. The list of
requests is then vetted for validity and business need by director-level management. Approved
projects are prioritized vs. capital asset replacement priorities and assigned per available capital
funding. Projects that are tied to compliance, safety, or productivity will be given funding
preference. This portion of the program is typically funded at 30% of the overall funding for the
Business Case.
Example (security fencing and gate, weld shop crane):
------------
_ I a
pow
a
9
A robust operations and maintenance program is required to help further extend the lifecycle of
our Facilities assets and help to lessen capital replacement needs. Conversely, limited O&M
maintenance programs will result in shorter than standard asset lifecycles, and ultimately
increased Capital spending. Existing O&M funding has required a shift to maintaining only the
most critical systems, thus more aesthetic problems such as dirty carpets and windows are
"selectively neglected." This reduction in scope reduces the expected life of assets and
Business Case Justification Narrative Template Version: February 2023 Page 5 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 508 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
increases long term maintenance costs. As the condition of our Facilities improve, capital asset
replacements should lessen in future years of the program.This is again dependent on sufficient
O&M maintenance budgets and workforce.
1.2 Discuss the major drivers of the business case.
The major driver of this business case is Asset Condition. Facilities apportions approximately
50% to Asset Condition work that is identified using Paragon Asset Condition software
(Terracon), 30% is set aside for Manager Requested projects, and 20% is kept aside for
unexpected capital needs and furniture replacements. A proactive Asset Management program
prevents the occurrence of asset failures or breakdowns. This also allows the company to
spread these investments across time and plan for this work, rather than responding to critical
failures after the fact that can impact business operations.
Customers benefit from this project by Facilities providing safe, usable buildings through which
our Operations teams provide electricity and gas to our customers.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
As previously stated, there is an Asset Condition backlog and requirements identified totaling
over$15.8M. This list is growing every year as our buildings age and new items are identified
that need replacement. Deferring this work will cause a large bow wave of Capital investment
in future years. Providing a level investment over the next 10 years will allow us to prevent
equipment failures and the need for a large unplanned capital investment.
10-year Forecast- 75% Funding:
YEAR REQUESTED SPEND 75% OF REQUESTED SPEND
AMOUNT($) AMOUNT($)
2024 $5,200,000 $3,900,000
2025 $5,250,000 $3,937,500
2026 $5,410,000 $4,057,500
2027 $5,700,000 $4,275,000
2028 $5,900,000 $4,425,000
2029 $6,195,000 $4,646,250
Business Case Justification Narrative Template Version: February 2023 Page 6 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 509 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
Forecast Analysis
536,000,000 0.0650
533,000,000 0.0600
$30,000,000 0.0550
$27,000,000 - 0.0500
$29,000,000 0.0450
0.0400
$21,000,000
0.0350 T
$18,000,000 D
0.9300
515,000,000
0.0250
512,000,000
0.0200
59,000,000 0.0150
56,000,00a 0.0100
0.9050
53,000,0;0 . 0.0000
2024 2024 2025 2025 2026 2026 2027 2027 2028 2028 2029 2029 2030 2030 2031 2031 2032 2032 2033 2033 2034 2034 2035
E StartingBaddo9 E Requirements E Spending E Ending6acdo9-0-FCI
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
The major reason to perform the projects within this program is to align with Avista's Focus
Areas of Our Customer and Our People. Being able to provide service to our customers safely
and efficiently is a cornerstone of Avista and the facilities our crews report to is a vital piece of
this service effort. Having facilities and storage yards that meet the needs of both electric and
gas operations benefits both Our People and Our Customers.
This program also aligns with our value of Innovation and our Mission of innovative energy
solutions. Innovation is change and having an openness to improve products, processes, and
services. Whether it is from incorporating new ideas into already established systems, or
completely transforming how something is done, innovation is the key to solving the
challenges Facilities is faced with today. An example of this effort is how Facilities has used
part of the existing building cooling system at our main campus to create a Data Canter cooling
system that currently uses no mechanical cooling to operate. Providing savings to both the
company and customers by reducing company utility bills.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
The Asset Condition Study and Asset Condition Report for all Avista's Assets is used to help
determine the best options to resolve the various Asset Condition needs. It is used to help
determine the best projects to fund in any given year. Projects are prioritized by the Paragon
Asset Condition program using metrics such as risk, impact, and ROL This prioritized list is then
used to create the Asset Condition project list for the coming year.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 510 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
Example of Paragon Work Package List:
Dmkayem iJ Ly1X�py,YatJe Wrtie i_ IteyatJry IVau ��0...t ,�,�:�w��,��L,�`•,,GL l"I UUF_�l a�wun �,S xu :-�
2017(G-, =171)
820-93854 CMU'.Fai.. A'=Carp•Tekoa Facility 11501 Tema FeoTey 10.00 78.1 5.00 I OBat Deiclercy Repairs 5453.81
G20-93764 Peplsce care pub th-91Sa:c Av=Carp•Co d'Alr.Sen-Cerrer Cr Site-Coeur cAlam Service 10.00 1A 3.00 1 Capita. Capul Replace-irts 53970.84
G20-93760 Replace cc c ee retaining well, A-ta Carp•ft2rille Faol¢y 113 Sn-NM,i4 Facility 10.00 -0.8 6.00 0 Ca:c3 Capital Replaarrenes 50.00
8 0-939M Replace Plyiood cis N A-oee Carp•SerdMm Service Cercer 12632 SaMzirc Tn,d Grapy 8.50 0.3 3.0D I Captor Capin Replete e,ts 55,529.69
820.93853 Repwnt b,ildrg eateior A09a Corp.Rwille Faci0ly 113DI Rtmlle Faci,cy 8.50 -0.4 3.00 I Capita Capi l Replaoanees 53,063.22
030-93814 830-Deficiency Repaim Aw Cop•0er•elah N.1ev 10301 Ch-1,Faclitti 8.50 221.9 3.00 2 W1 0e9ae Repair 4245.05
810-93799 Demoteh CM endoaae a oral &r C . 10105 M-Canµ.R-Park
shoot ArP Main Carpus B:edrg 8.50 •0.3 5.00 3 08-M De•iderq Repaid 5124,796A7
8 30-9 3 786 Om r 5 to the exsng BUR A.,.Carp•Main Campus 10101 Ger�al Office Bu do 8.50 3.8 6.OD I OW De d-j
re4c,rr en 9 Repairs 513,345.28
G20-93766 of asphh Aye Carp•Grange,..Fedtty 118 Ste-G-gerille Fac_ci 8.50 0.5 3.00 1 Captor C.Pul RepI-er. 563306.66
C20-9375 Remae arc relre 9wrt sine.va� Arsa Corp•Dapnport Senioe Cernx 108 S�Da.Erport Se�ke Ce•�cer 8.50 0.5 LOD i Cacir= Cap21 Ypia�+�e^a 590762
along north sde of propertl.
G20-93762 C20.Deficieicy Repairs Axsa Carp•Spokane Valley Call Center 114 Site-Spokane%4*W Cesar 8.25 6L1 ISO 2 O&M Deider Repairs 51,134.53
B20-93831 &or.Mall rep.-. Av=Corp•Colfax Facilir, 10602 Coax Sm ge Rw d^g 8.00 15 5.00 I 0&M De%o ,R.paim 511,345.28
DSO-93792 Perth a abandoned vanscorrrzr A•.sa Carp.Main Cartpus 1005 Buidng n CamP.Ross Park 8.00 -LO 3.D0 1 0&11 Defoe-i Repairs SL269.06
G2043761 C-10-D ba-Y Rem,,. Av-Corp•R-ill.Faor¢y 113 Site-R=,la Fedlitv 7.50 -0.9 3.00 2 Ca7m Capal,Replace-ie- 511L383.73
C20-9379S C20-Defo Repairs A,-Carp•Flair 10/05 Main Canµ.Rass Park 7,00 -0.5 5.00 2 0&M 0.cje en}' Cartpus Btutirg ncY Repairs $33,614.34
830.93889 R30-D.1d6-,Repairs A•,•so cop•omfro Facility 122010,d6.Faot¢y 6.50 25.6 5.00 2 0&M Oa+d-,Repairs 52.178.31
B10-93851 Report cqaAamed cwwp wpccrm Av Carp•Randle Factory 11301 Ritmile Fora ty 6.50 121 L00 1 OLM Deioency Repairs S2722.87
CZD.93838 Repant rtte-stair in wareFeuse A-M Carp•D.-port 5-ice Cermr 10801 Da•,.n S-ice Caner 6.50 A2 200 1 O&Vt D.noerci Repairs 5147.49
D10-93791 Remp:e aband-crsrre. A-M Carp•Main C-p. 9 105 M n Cnp�Ross Park 6.50 -110 3.00 1 O&M Ddid.eq n Repairs s22,69056
G20-93777 Rc--=-aip.eaFc ari i As-=Carp•laCra Senior Center 129 Site-LaGra•de S-e Ce^te• 6.50 0A LOD 1 OB.Vt Deciercy Repairs 5293.63
G20-93751 G20-Oefici^y Repairs A•v+sta Carp•GDM le Se,-Crtr 105 SexevC.Service Cen 6.50 11.2 2.33 3 O&M Deidency Repairs 51085.93
G20-93765 G20-DeFiarcy Rep,r A-M 116 S,*ro r cA'ene S r;c=
Corp.Cnet:r d'Alere Serice Gw+xr CeYr 6.08 30.1 3.33 6 O&M iJeider_y Repairs 524,9B6.84
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Fund Program at full amount of$5.2M for 2025 and then fully therafter
Funding the Structures and Improvements Program and the full proposed amount allows
Facilities to address capital asset replacements and business needs. Safety, compliance, and
productivity requests are rated highest and given priority first. Many of these replacements can
create safety risk if not addressed (sidewalks, structural repairs). Not systematically
addressing maintenance needs could ultimately result in complete replacement of the
buildings at some point.
Exmple priority list based on safety, compliamce and risk:
Business Case Justification Narrative Template Version: February 2023 Page 8 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 511 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
atu•�atnl l A,creyt
PaSerJe 1D � Wurt Pe:keye N�e k6aar ,Aatt .__. Inipait � PfMYYY
5-t 7.1 FeUny
B30-93786 ern repairs to the ecsdrg BUR roof A.;sa Gorp.Man Carnous 10101 General Office Bwl3g 8.50 3.8 6.00
5ystern
G20-93760 Replace mrete reminrg wad• A;sa Corp.Ritr.-e Facl r, 113 Sme-Rim•ille Facky 10.00 -0.8 6,00
610-102860 Repace�-epair:,00c trtsses A,;sa Corp.Sanepo-t Ser.ice Cerret _2602 Sandpont T udc Canopy 4.00 -0.7 S.oO
810-102859 Replace Colirnns asses stn=rai Avsn Ca-o•Sandpo-t Service Center 2602 Sandpoint T ucic Canopy 6.00 -0.1 S•00
00-101247 Carpet ReJlacer^er t Avsta Corp.Pu9mar Ser:ce Center -1201 Pi man Ser,ice Center 6.50 0.3 5.00
DSO-101242 Replace aged t-.vxh}zar M-=Cap.Ma-Campus 10101 General ORics Bwld,.y 6.00 -1.0 S.00
GZO-101240 Repace Asphalt Avsa Odra.Sancpo,t Service Center i26 Set-Sandpoint Se-;ce Ce^ta 4.S0 1.6 S•00
G20.101238 Replace Ermv Snors Avg Cora.Pulh tan Sav ce Carter 1.12-I*wPllman Service Center ISO -0.8 S.00
030.97245 Replace w-n imed 1,eld,rc bre collecor A:sa Cap.Beacon 10204 Beacon GPSS 1.6etal 5-,oa 9.50 -0.5 S.00
G20-97243 Replace Damaged Secoo--or asphalt Avsa Corp.Omf no Facility 122 Ste-Orofino Faolici B.SO -0.4 S.00
020.939i7 Cea>ing.p e.err re•nantvar,ce arc A.;sa Cap.MedL z S=_r;ce Center _3001 hlertcrd Svoce Cer er 6,00 0.1 5.00
tesdnc of erergenci eye wwh
B20-93895 Exmro-%veil 2pairs. A;sa Corp.St Mares Se-,ice Ce• er 2401 St,Manes Ser.ce Center 2.50 10.4 S.00
A1ti93894 Stnt-raI e.z atcn, Arsa Cory.St Mares Se-,ica Ce-s• 2401 St.ManeE Ser.ce Cente- 6.00 4.6 S.00
At the current funding level this backlog of capital work will continue to grow. The backlog is
growing faster than our current funding model can accommodate. It is the goal of this program
to maintain a level backlog that projects are selected from using Terracon's risk assessment
and the impact the item has on the Company's ability to perform its work, making the highest
priority projects readily apparent.
10-year Forecast- Fully Funded:
Forecast Analysis
0.0600
$33,000,000
0.0550
$30,000,000
0.0500
$27,000,000
0.0450
$24,000,000
0.0400
gzl,000,000
0.0350
$18,000,000 T
0.0300 !7
$15,000,000
0.0250
$12,000,000
0.0200
$9,000,000
0.0150
$6,000,000
0.0300
A000,000 0.0050
$a lit 0.0000
2024 2024 2025 2025 2026 2026 2027 2027 2028 2028 2029 2029 2030 2030 2031 2031 2032 2032 2033 2033 2034
Startingaaddog M Requirement M Spending Endingaaddoq FCI
Business Case Justification Narrative Template Version: February 2023 Page 9 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 512 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
,-ear
ID Grouping Accaw:ttt - M24 Z025 2026 =7 1 2028 2029 2030 2031 2032 ZD33
Capital Replammertts SS,386.268 $5,116,549 $5,034,971 $4,707,423 $4,285,929 S3,835,S21 $3,3S3,927 $2,840,724 $2,389,6S1 $2,461.341
Component Rare"at S26.994 $3,968,047 $4,647,484 $6,420,912 S6,723.134 $7,828,481 $7,142,207 $13,100,689 518,812.431 $19,278.699
Backlog(Star.of ESL
D kwicy Repairs S1.437.303 $1,398,128 51337.130 S1,274,357 S1,209.620 51.142,975 $1,128474 $1,163,358 51,198,259 S1,234.207
efKency
Repairs,'ReplacernaKs 5704,008 $725,129 5746.883 $769,289 5792,368 5816,139 5840.623 $865.842 $891,817 5918.571
Bacidog(Stert of Year)Total S7,574.S74 $11,207,852 $11,766.468 S13,171,980 $13,013ASO S13.623,116 $12,466,231 517.970.613 S23.292,159 $23,891818
Capital Replacements SSL161 $295,192 S69AS7 $o 50 SO $0 50 So SO $4451810
Compoter!t Rereval at ReWvemenG ESL S5,197,283 $2,089,050 $3.180.229 SL726,464 $2,551.426 S844,593 57.351,816 56,954,965 $1;767,178 56,819374 S38,482,978
2
pn�ntamNe S1,100.812 $1,133,837 SI.167.852 $1.202.887 $1,Z38.974 S1.278143 $1.314,428 51,353.860 51.394476 51,436.311 512,619,581
Mastena—
RequiemertsTod $6,379,256 S3.518,079 $4,417,S38 S2.929351 $3:790.400 S2,120736 58,666,243 5&30882S S3,16L655 5&2S6.284 SS1,548,369
3 wog, $13,953,630 $14.725,931 $16,186007 $16,101,332 $16.80L451 515,743,$SZ $21,13ZA75 $26,279A38 526,453,813 $32,149,103
Capital Replacements 55001000 S515,00o SS30ASO $546,365 SS62,755 S579,635 5597,025 S614.93S S633385 S652385 55,731,93S
Cariponent Renewal at 51,500,000 S1.545,000 $1,591,350 $1,639,095 $1,688,265 $1,73&905 $1.791,075 SL844,80S $1,900,155 51,957,155 $17.195,805
ESL
4 Budget DEfiKiancy Repairs 5100,000 S100,ODO S_00.000 SIMON 51001000 $100,000 5100,000 $100,000 $100,000 SIOD,000 S1,000,000
p n SIX000 S1001O00 S100.000 S100,000 S100.000 $100,000 5£00,000 $100,000 $100100o S10o.000 S1A001000
MaaaerwKa
BwdpxTotal 52,200,000 $2,260,OD0 $2,321,800 $2385,460 $2,451,020 52.51&S40 $2,588,100 $2,659,740 S1733,540 $2,809,540 S24,927,740
Capital Replacernents 5499.9% $514,821 S530,128 $546,327 S962.122 $579,281 S59S,943 SS20.674 So 50 S4,349,201
Cmtponant Re+wwal at 51.499.698 51.544,976 $1,591.280 51.638,735 $1,688,242 $1.739,891 $1,791,072 $L844.709 S1.900.127 $1.957.051 517,19C783
ESL
Spending
$ DefKletKy RepafR 5991898 $99,943 599.891 599,969 599.935 346,399 S0 50 30 50 S546,034
prew mt S99.999 $1001000 51DO.000 $1001-0.00 S 00.000 $10000D SWUM $99.999 MUM S1001000 $999,9918
Mas"INN,arKe
Spending Total S211991501 SZ,259,740 $2,321.299 52.385,030 S2,450.299 52,464,571 $2.457,015 S2,465382 S2,000,127 52.057,051 523,M,016
Capital Replacwsants S94 S179 5322 538 $633 $354 51,082 S94.261 $633,385 $652.385 5138L734
Compon eReneaal at S302 S24 570 Mr, 523 S14 53 $% 528 S104 $1,022
Variance(Budget E5-
6 minus SP&*v) Def ssnt,Repairs 5102 $57 5109 S31 S65 S53,601 5100,000 $100,000 $100,000 S7oD.000 $453,966
pre,entatre 51 So 50 So SO So So SI So 50 S2
Maartwnnce
WMnca(Bttd"mims SW&9)Tad S499 S260 $50, 5430 $721 $53,969 MIMS S194,358 $733.413 S752.489 SL837,724
Capital Replacernants 54.967,523 S4,888,322 54,570,313 54.161,096 $3.723.807 $3,256,239 $2,757,984 S2,320,050 52,389.651 52,461.341
Compo"enc Renewal at S3,852,473 54.512,121 $6,233,895 $45,527,315 S7,600.467 56,934,162 S32,719,116 518,264,496 $18,717,184 $24,141.621
BKWog(End of ESL Y&W) Dafoarcy Repairs S1,357,406 $1.298,185 51,237,239 51,174,388 $1,109.685 S1.096,577 $1,129.474 $1163,3S8 $1.198259 $1,234.207
Defciec 5704,008 $725,129 5746.883 $769,289 $792.368 $816,139 5840,623 S865,842 5891,817 5918,571
Repaim-Replacements
SKMog(OW ofYear)Tow SlOAL410 S11,423,756 512,788.330 $12,632,088 S33,2Z6326 S11103,137 S17,44Z197 $22,613,746 SZ3,196,911 $2&75S,741
Unfunded
8 Neaencat"I pRYe" '� SIMD,813 SLO33,837 S1,067,8S2 S1.102,888 S1,138.974 S1.176,143 $1,214,428 S1,253,861 S1,294476 $1,336,311 S11,619,583
Maintenance
9 Fa 0,0288 0.0293 0.0316 0.D304 0.0309 0.0277 0.0378 0,0470 0.D468 0,0558
10 Total"cemaK 5413,189,93E $425.585,633 $438,353,202 54SL503,798 $465,D48,912 5479.000,379 $493,370.390 S508,17LS02 SS23,416,647 $S39,119,146
11 Spending a%of 0.53% O.S396 0.53% 0.53% 0.53% 0.S1% 0.50% 0.49% 0.38% 0.38%
TRY
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
Base known projects over the next 10 years- including backlog:
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 10 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 513 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
Requirements
8,000,000
Capital Replaceme6 6,000,000
Component Renewal at ESL
Deficiency Repels 4,000,000
Deficiency Repairs/Replitl 2,000,000
Preventative Maintenance
2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
Account 2024 2025 2026 2027 2028 2029 203D 2031 2032 2033 Grand Total
Capital Replacements $4,593,070 $360,266 $0 $0 $0 $0 $0 $0 $0 $0 $4,953,336
Component Renewal at ESL $5,038,133 $386,887 $1,063,903 $3,320,802 $1,823,829 $2,703,262 $78,743 $7,816,348 S8,358,659 $327,377 $31,117,943
Deficiency Repairs $2,116,355 $0 $0 $0 $0 $0 $0 $0 $0 $0 $2,116,355
Deficiency Repairs/Replacements $746,925 $0 $0 $0 $0 $0 $0 $0 $0 $0 $746,925
preventative Maintenance $1,174,680 $1,167,852 $1,202,887 S1,238,974 $1,276,143 $1,314,428 $1,353,860 $1,394,476 $1,436,311 $1,479,400 $13,039,011
Grand Total $13,669,163 $1,915,004 32,266,791 $4,559,777 $3,099,972 $4,017,689 1 $1,432,603 $9,210,824 $9,794,969 $2,006,7771 $51,973,570
Active Assets 1171 117 117 117 1171 117 117 117 1171 117
Total Replacement VaWe $413,189,933 1 $425,585,631 $438,353,199 1 $451,503,7951 $465,M,9D91 $479,000,3771 $493,370,388 1 $508,171,500 $523,416,644 $539,119,144
Facilities 10 Year plan Matrix:
-e wny a conamnnRaeaa steutaimtan benuReaaneatk cnw,onmemalxtrk wattea nepplamemedewKeaaAtHpn
Pullman 1Z,, 63 l,g ,r Poor 5 Polr Over Ca 1, Med Med 2 BsnY N9hwaywms,site droirwge issues 20 Shc and Relocate I-IW
3endpoi,R 1957 63 Med Fir 2 Poor 4 Fir 3 Over Ca fy 4 Hgh 4 High 3 loea[ed in residenhal area/SpdnpdalmgeflaoMp 20 Sell and RebmK Ftlfily
Davenport 1966 54 Med Poor 4 Pow 4 Fir 2 Over Copoofy 4 Med 3 High 3 bw5mnuvlOroairp ron cehiroy veM4es/bD ertrorage ZO Selland Re/ocaKFarW
M river/Opsrte pole prdflaads
Graneeville 1933 87 Med , 2 Paw 4 £m-r 3 Over Cnp ty 4 Hyh 4 Hiph 3 Trurkpvrdrg weess,sa)ery issue M Sell and Rel--lily
Chewelah 1985 35 Sm Fir 2 Pow 4 Pow 5 3 Med 3 High 3 A—yy395,RMfta psw ny ewh SXW 20 Sell and RelomKor Merye with
WWI-OP]
Othello 1974 46 Med Fir 2 Poor 4 Fair 3 Over0a ,afy 4 Med 3 Med Z 9opcd/winmprd hward/droimge 18 .11—d RCIwaK Faolity
R-11, 1955 65 Sm Fir 2 Pow4 Poor 5 „ 3 Med 2 1 Rfand RerINnisp Woll lssaes 17 RenovaK exisdn9 bvildin9w
build ne xisan site
Spokane Valley Call Center 1979 41 AM Fir 3 Fair 3 Good 1 Over Capoaly 4 High 5 1 Semdryissoet ord dosvd[otress off Mgh speed highway 1) Maintain and Opemfe or5ell and
Me a.,M Ca
St Meries 1974 46 Med Fair 3 Flr 3 fair 3 orr 3 Med 3 Med 2 Steep slope,win[ersliee,b,per/srorage yard on]00 year)lopp 17 Mainbin and Opemre Ojfi¢/
plain Reroraresrpm a ore
cm 1994 26 XL,g bond 1 1.11 3 Fir IOver Copadb'/ Med 1 Med OeareCampu wan/Propertyowned a,dmnilawe/prrompus 14 Mlor Ya,d Refresh/Ex,n—
£x ndabe expansion
Over Capacity/ Creme Campus won/PropertyawnM oM mpiladejorrompus
Clarkston 1975 45 !ry Good I Flr 3 Fair 3 ndable L.. I low 1 expansion 13 M for Yard Rfsh/Expansion
lack Stewart Tralmn8 1993 27 Xlry Brad t Fah 2 4Over Copaafy/ Inw Iw 0 Trailers in powamMtlan/RemNioKd spill sire/Cap Fr6edw 12 SiKRfsh
Ex ndable
Ororino 1970 50 Sm air 2 Folr 2 Fair 2 AdeavaK 2 low 1 Inw 1 Loral Rep Offire 10 Mainfainand.p—
C9nax 1990 30 5m Goad 1 2 Fall, 3 6rpnndabae I lnw I Med 2Loral Rep Offiw,mn develop yordfw)mure expansion 10 Mainbinand OpemK
Irvisbn Call Center 1976 44 XL,g Goad 1 Good I Fir 2 Fah 3 Med 3 Imv 0 Oownrown Area.Terumy Risk 10 MainfainandO,x—
Medford 1999 26 !ry Good a I fWr 2 Over Capovty/ Fw I law 0 ywdlsneadrecap .y 10 Mainbinand Ope
E ndable
Tekoe 1971 49 S. Gaud 1 fair 2 For} 2 Adiq— 2 W. I Med 2 Hew Rmfin X110 30 Maintainand0,—
Kllb- 1960 60 Med Goad IQ W 1 Fair2 Ade n, 2 Med 2 Med 1 —,n,Ummunirypreseree widr ae hrbeirp donaown 30 Maintain and OpemK
Grants Pass 1960 60 S. Good 1 Fair 2 Fir 2 Adm.- 2 Low 1 Low 1 SmmrtM odoauaKfmrKed 9 Mainfainand OpemK
Roseburg 2000 16 Med Good I Fair 2 £a11 2 Ad-— low low 9nallsiK aWawrKJor need 8 Mainbinand OpemK
Example of projects in Asset Condition System:
Business Case Justification Narrative Template Version: February 2023 Page 11 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 514 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
PadegrlD O WuctPakeycNone Wver_Iw Aid Inipecic :tO �vxiv
St.:ac Rallry
830-93786 Per�orn repairs to the xsting BUR roof A:sm Co:•ate^Campus :0101 Gane-al Rfice Bu:td g 8.50 3.8 6.00
o
G20-93760 Replace mnc ete re-aln.'g v,B,. Avila Co,•Riz::e Facility 113 5.m-Ritrille Faceei MOO -0.8 6.00
810-102860 Repace epair:,00c try A%�m Co-,.Sancpo t Ser.ice Center 12602 Sandpo nt T uek Canopy 4.00 -0.7 5.00
B10-102859 Repace Colu•nns assess str ncaua Avsa Coo•San cpant Service Center 12602 Sanciparrt Truck Canopy 6.00 -0.1 5.00
C30-101247 Carpet Re:4cerrer: Avsa Co-,.auli•nw Serrce Cent? 112D1 Pi man Service Center 6,50 03 5.00
050-10:242 Repace aged s:,•xhg ar kism Ckro•Main Campus 10101 Gene-al Office Bwk#+g 6.00 -1 A S.00
G20-101240 Repace Aephatt Avsm Co,,.)•Sandpov t Ser.ice Cerrer i26 5x-Sandpoint Se-:,ce Ce^w 4.50 1,6 5.00
G20-101238 Replace Erym Sm rs Av,tsza Co z.RrRman Serrce Center 112 Ste-Pllman 5--ice Cer:e 250 -018 5.00
030-97245 Replace w^isxd�4ding fume oollec:or Avila Co. .Beams 10204 Beam,)GP55 Meal 5-oo 950 -0.5 S.00
G20-97243 Replace Damages+Secoo oa asphalt Avsa Corp.Orafm Facility U15-na-orcAno FarmlT� 850 44 5.00
020-939:7 Cea^ing.peYere..e mainte^arce arr. ks'a Cc-6•%$eefe-c Sense Center 13001 I•►-dlcrd Service Cer:er 6.00 0.1 S.00
testing of errergenclr eye wash
620-93895 Exert kvell epairs. Avsm Cop•St Mares S=--,ice CL-m, 12401 St.Maries Sen•ce Cente• 2.50 10.4 S,00
Al:<93894 Stnxtt r-I e'reuaton, Av sta Coro•St Mares Se-,ice Ce-m, 12401 R.Manes Ser:ce Cante- 6.00 4.6 5.00
830-93889 630-Dencie,)cy Repairs A%�sm Carp.Orofino Fadlit, UM1 Orofm Fadlity 650 25.6 S.00
820-93854 LMLI repairs. Av sta Carp•Telma Fact,, 11501 Teluoa Facilit, :0.00 78A S.00
DSO-93846 Replace elecrnca pane A sm Carp•Pu9rnan Service Center 11202 Putman Service Cerrer Canopy 4.00 -0.5 5.00
B30-93842 BUR re--iaceme-- M•isa Cora•Pulrna-Secr.-ce Center 11201 PUl nan Service Ceter 250 0.2 S,00
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital Scope Reduction:Planned Work $20,600 $21,220 $21,860 $22,510 $
0&M Estimated Energy Savings+3% $11,330 $11,670 $12,020 $12,380 $
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M Operational Efficiencies+3% $301,746 $310,799 $320,123 $ $
This program is intended to systematically address the following needs:
Lifecycle asset replacements (examples: roofing, asphalt, electrical, plumbing)
Examples of saving by performing planned replacements vs delayed:
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 12 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 515 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
• Estimated 3-5 projects a year: HVAC, Plumbing and Electrical systems: Possibility of a
failure resulting in emergent site visits of crew members and non-scheduled
replacements resulting in office downtime and broader employee impacts.
• Examples of these failures can include unplanned electrical fire damaging
electrical infrastructure often resulting in an extended outage; central plant HVAC
failures, with widespread building or campus HVAC losses; unplanned roof leaks
affecting workspace.
• For the electrical risk calculation, Avista is assuming that this possible electrical
or HVAC risk could be conservatively assumed to be anywhere from $100,000 to
$1,000,000 per incident. Examples of this risk would be excessive arc flash risk,
breakers not operating as expected due to age, connection resistance between
buses and various connections causing excessive temperature. Loss of main
circulating pump motor, large compressor failures.
• Avista has taken the average of these ranges presented above ($550,000) and
divided it over the 30-year accounting depreciation rate of this investment. Lastly,
a conservative estimate of likely occurrence of this risk would be approximately
10%, so that is multiplied by the yearly figure.
■ $550,000/30 years x 10% = $1,833.33 yearly
• Reduction in energy usage due to more efficient equipment, estimated at 1%
year over year.
■ $1.1 M yearly energy costs x 1% = $11,000 yearly
• Reduction of risk to employee productivity from an unplanned failure (average
number across all sites):
■ 25 emp x 4 hr. per failure x$85/hr. avg loaded rate= $8,500
■ $8,500 per project x 5 projects = $42,500
• Estimated 1-2 projects a year: Roofing: Possibility of a failure resulting in emergent site
visits of crew members and non- scheduled replacements resulting on office downtime.
• Reduction of unplanned leaks resulting in additional sub roof damage requiring
an increased scope of work. A proactive asset-based replacement vs. run to
failure ensures a minimal scope of work.
■ Additional scope average project cost increase of=$10,000
■ $10,000 per project x 2 projects = $20,000
• Estimated 1-2 projects a year: Asphalt and sidewalks: Possibility of a failure resulting is
emergent site visits of crew members and non-scheduled replacements resulting on
office downtime.
• Reduction in safety issues related to cracking, heaving and slips, trips, and falls.
This data under investigation and will be included in future reporting.
• All projects:
• Planned replacements can result in savings due to competitive bidding.
Unplanned failures are often unbid, time sensitive contracts
• Reduction of risk related to damage to equipment and buildings
Business additions or site improvements (examples: adding a welding bay, vehicle storage
canopy, expanding an asphalt yard. Can sometimes include property purchases to support site
expansions.)
• Examples of savings:
• Estimated 2-3 projects a year: Extended/improved storage yards or storage
facilities: Improved business operations and time efficiencies for crews. An
example of this would be added storage racking resulting in easier material
access, yard consolidation.
■ 5 emp x 0.25 hr./day x 260 workdays x$85/hr. avg loaded rate= $27,625
■ $27,625 per project x 3 projects = $82,875
• Estimated 1-2 projects a year: General improvements: Efficiencies created
through improved storage, more efficient workspaces and expanded workspaces
as required for growth.
Business Case Justification Narrative Template Version: February 2023 Page 13 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 516 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
■ 25 emp x 0.15 hr./day x 260 workdays x$85/hr. avg loaded rate=
$82,875
■ $82,875 per project x 2 projects = $165,750
Lifecycle furniture replacements and new furniture additions (to support growth)
• No savings to report
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternative 1: Partially Fund Program based on priority
This option would decrease the capital program and increase existing O&M budgets to prolong
structures' lifecycles beyond rated life and reduce capital needs. This option is not the
preferred approach due to he Avista business model. Capital investments can be limited with
a corresponding increase in O&M dollars. As building systems continue to decline O&M
burden will increase.
The reduction of the program would result in larger project being differed due to lack of
funding. These projects are considered to have a high impact on the business and failue could
result in an O&M impact. If these items were to fail a request to the CPG would be required at
that time.
Potential differed projects with reduced in funding over the next 5 years:
Project Cost Estimate
Mission Site Design: Sidewalk upgrades/de-ice, pond, landscaping end of life $1 M
Irrigation Water Line Replacement $600K
Cafe Elevator Replacement $500K
Extend Generator Service to the Service Building $400K
Service Building Switch ear and Transformer Replacement $2M
Replace Elevator Motors @ Mian Building $700K
Main Building Roof Replacement $375K
Service Building Freight Elevator Replacement $500K
Business Case Justification Narrative Template Version: February 2023 Page 14 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 517 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
H07 Budget Varience
$10,000,000 —
$8,000,000
$6,000,000 — —
$4,000,000
$2,000,0$00 I
2016 2017 2018 2019 2020 2021 2022 2023 2024
■Recommended O&M:2%of Replacement Value
■Budget C&M
■Actual O&M
■Actual Capital
The estimated replacement value of Avista's assets when the Terricon survey was taken in 2017
was approximately$242 million, with estimated operations and maintenance requirements based
on the Terracon report of$8,800,640 per year, which equals 3.64% of the current replacement
value of the assets. Today the replacement value of Avista's facility assets is $413,190,000. The
graph above clearly demonstrates that the amount spent by Avista (the green bars)typically does
not reach the minimum level of O&M expenditures (the blue bars) standard in the building
industry for basic sustenance of facilities. This level of underfunding would need to be addressed
if the choice is made to underfund this program. If capital replacements are unable to be funded,
additional O&M work would be required to keep systems functioning.
Business site improvement requests are intended to address changing business needs. These
projects are usually linked to an enhanced productivity outcome. Having the ability to incorporate
structures and equipment that fall within the improvement and business needs category can help
support improved processes and lead to enhanced safety and longer lifecycles. When the budget
needs to be reduced, reductions are first made to requests in this category.
Replacement is intended to replace aging units to achieve more predictable capital requirements
and avoid replacement peaks caused by large-scale failures. Cutting into these requests over an
extended period could lead to reduced efficiency and have safety impacts.
Funding this business case at less then $4M will require a reallocation of the dollars, reducing the
funding for Manager Requested Projects.
Business Case Justification Narrative Template Version: February 2023 Page 15 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 518 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
The first metric that would be used to demonstrate the investment was successful would be a
leveling out of the Asset Condition Backlog. While a reduction in the backlog would be ideal, due
to funding limitations, a flattening of the curve would constitute success.
Beyond this, the only measure that can be used is to design solutions that provides room for
growth, expands technology requirements, and adheres to safety and security best practices.
Some of these solutions would include items such as:
1) Materials/Storage: Provide spaces that meet the needs of the Stores team and Operations
a. Estimated 1-2 projects a year: General improvements: Efficiencies created through
improved storage, more efficient workspaces and expanded workspaces as required
for growth.
2) Estimated 1-2 projects a year: Extended/improved storage yards or storage facilities:
Improved business operations and time efficiencies for crews. An example of this would
be added storage racking resulting in easier material access, yard consolidation.
3) Environmental/Compliance: Ensure that the building and site meets with Avista's
environmental standards
4) Employee/Customer Impacts: Room for employee or operations growth
5) Operational Efficiency: Ensure that operational needs of employees are being met
6) Asset Condition: Provide systems and materials that meet with Avista standards
a. Estimated 1-2 projects a year: Roofing: Possibility of a failure resulting in emergent site
visits of crew members and non- scheduled replacements resulting on office downtime.
i. Reduction of unplanned leaks resulting in additional sub roof damage requiring
an increased scope of work. A proactive asset-based replacement vs. run to
failure ensures a minimal scope of work.
b. Estimated 1-2 projects a year: Asphalt and sidewalks: Possibility of a failure resulting is
emergent site visits of crew members and non-scheduled replacements resulting on
office downtime.
Reduction in safety issues related to cracking, heaving and slips, trips, and falls. This data under
investigation and will be included in future reporting.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Most projects in the Facilities Structures and Improvements program begin work in the 2n, or 31
quarter of each year and will usually transfer to plant before the end of the year. Some of the larger
projects, or projects with extensive design, can carry over to the following year.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
ER7001 Facilities Structures and Improvements is a 5-year program created to address the capital
lifecycle asset replacements and business/site improvements at all Avista's regional sites and
offices.Asset lifecycle replacements are compiled by Facilities and are based on an asset condition
report and industry recognized lifecycles. Site improvement projects are approved based on
productivity and/or business need.
Asset Lifecycle Replacement Projects
Business Case Justification Narrative Template Version: February 2023 Page 16 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 519 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
In 2017 and 2022 Avista hired Terracon Consultants to perform a condition assessment on 76
Avista-owned facilities and 35 real estate sites at 34 different locations, comprising approximately
1,186,000 square feet. These facilities were constructed between 1903 and 2019. Terracon
estimated the value of this infrastructure at approximately$365 Million.
The Terracon study was highly detailed and in depth. They examined every characteristic of each
facility from a variety of perspectives. External structures from asphalt in the parking lot to roof
condition, fences, curbs, work, and storage areas were examined to ascertain and score condition
and to identify issues and note concerns. Internal aspects such as walls, carpets, and furniture
condition were evaluated.
They surveyed building systems including plumbing, heating, and cooling, electrical, lighting, air
quality, drainage, and security. They also looked at safety aspects from both the customer and
employee perspective. Then each item in the facility was rated based upon its condition and
assigned a budget category of O&M Preventative Maintenance, O&M Deficiency Repairs, Capital
Replacement, and Capital Renewal/In-Kind Replacement. Terracon's list is sorted by relative risk
and the impact the item has on the Company's ability to perform its work, making the highest
priority projects readily apparent. Of the 363 "at risk" items Terracon identified, nearly 60% had a
risk rating higher than 5 (on a 1 to 10 scale) and 20% were identified as having an actual impact
on operations. This rating is what is used to identify the highest risk replacements needed and the
project list is created using this information.
Site Improvement Projects
These types of requested facilities projects undergo a multi-level internal review process. It begins
with the related manager who either identifies the capital need themselves or is notified of an issue
that needs to be resolved by an employee. If the manager believes the project is in the best interests
of his group and the Company, the proposal is submitted to that manager's director. If the director
also sees the value of the request, it is submitted to a group known as the Facilities Capital Request
Board.
This Board meets every fall to review the requested projects for the upcoming year. Managers from
each major business area send a representative (the employee chosen usually changes every
year). In addition, there is a requirement of at least one person from Operations, Environmental
Affairs, Materials Management, and Facilities. This broad mixture of perspectives is designed to
provide a neutral and "outside" perspective while having access to the expertise and experience of
the directly related and impacted business entities.
By the time the Board receives the list of requests, it has already been vetted twice within its related
department. The requests are prioritized based on the Capital Request form that was filled out and
approved. At the Board level, each request is reviewed for required criteria such as risk, safety,
environmental impact, and compliance. Thus, this process is designed to ensure that multiple
stakeholder participation provides a thorough and robust analysis of all facility needs and
alternatives across the Company.
Facilities Capital Steering Committee
Once the project list is assembled, the finalized list of projects is approved by the Capital
Facilities Steering Committee. This Committee of Directors is responsible for approving the
submission of Business Cases to the Capital Planning Group and approval of projects and any
changes within this program.
In the past this has most often been:
• Director of Shared Services
• Director of Environmental Affairs
Business Case Justification Narrative Template Version: February 2023 Page 17 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 520 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
• Director of Financial Planning and Analysis
• Director of Generation, Production, Substation Support
• Director of IT and Security
• Director of Natural Gas
The project shall use certain Project Management Professional (PMP) guidelines and procedures
during this project.
A Project Execution Plan, consisting of the documents below, will be drafted and approved by the
SteerCo described in Section 3.1 (A).
• Project Charter, Change Management Plan, Communication Management Plan, Cost
Management Plan, Procurement Management Plan, Project Team Management Plan, Risk
Management Plan and Risk Register, Schedule Management Plan, Scope Management
Plan, and Project Execution Approval Form.
Each month, the project manager will provide the following information either at the scheduled
SteerCo meeting, or via email.
• Approved Yearly Budget, Accrued Yearly to Date, Year Estimate at Complete, Year
Variance at Complete, Approved Lifetime Budget, Accrued Life to Date, Lifetime Project
Estimate at Complete, and Lifetime Project Variance at Complete.
Each month, the SteerCo will make decisions on cost, scope, or budget items as required by the
Project Execution Plan. The project manager reserves the right to present items not outlined in the
Project Execution Plan if he/she determines its importance is relevant to SteerCo input.
Decision Making, Prioritization and Change Requests:
• The final decisions regarding these items, especially certain change requests as required
by the Project Execution Plan, will be presented to, and voted upon by the SteerCo. The
decisions will be documented in a monthly meeting minutes of the SteerCo for
documentation and oversight.
• It will be the Project Manager's role to monitor the scope, budget,and schedule and present
the results to the SteerCo, regardless of if they are within tolerances, or not.
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Structures and Improvements and agree with
the approach it presents. Significant changes to this will be coordinated with and approved by the
undersigned or their designated representatives.
DocuSigned by:
Signature: `� 6 156W�,S Date: May-03-2024 1 10:56 AM PDT
Print Name: Eri c Bow`es
Title: Corporate Facilities Manager
Role: Business Case Owner
DocuSigned by:
Signature: Date: May-03-2024 1 2:52 PM PDT
Business Case Justification Narrative Template Version: February 2023 Page 18 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 521 of 535

DocuSign Envelope ID:65DED319-C3D8-490E-AF6E-B6BE5E65C859
ER700117003 Structures and Improvements
Kelly Magalsky
Print Name: Director-Shared Services
Title:
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 19 of 19
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 522 of 535

DocuSign Envelope ID:BDF05058-842B-4637-B226-3006525C1ADB
Telematics 2025
EXECUTIVE SUMMARY
Fleet operations across the US and within the utility industry are implementing telematics
solutions to solve complex business problems. The Advisory Group has identified five
ways that vehicles on the road impact Avista. The first represents the first generation of
telematics and is focused on utility owned trucks. The next four have the potential to
positively or negatively impact our business but they are vehicles not owned by the Avista.
It could be the contractor working for Avista in a contractor owned truck, a contractor in
their personal vehicle, Avista's employee's doing business on behalf of the utility in their
personal vehicle and crews responding to mutual aid in our service territory. Telematics
has been implemented on the Avista's fleet since 2012. The first generation of telematics
was implemented to streamline and track the inspections of trucks and mounted
equipment. The digitization of inspections has been very successful and has improved
the tracking of federally required inspections and the administration of those records as
required by the same authorities.
In February 2022 our current provider has notified us that the 3G network that nearly 500
devices connect to would sunset. This network shut down forces us to invest capital in an
upgrade. Additionally, customer requirements and our strategy to put the customer at the
center of every decision necessitate the need for us to leverage vehicle location data on
a modern and timely platform. Finally, best in class utilities are using telematics to provide
both coaching to drivers and collecting leading indicators on decisions a fleet of drivers
are making. The Advisory Group's recommendation is to replace Zonar telematics with a
modern cloud platform system. Both platforms address latency issues and integrate more
info sources than ever before. The final estimated cost for this is upgrade $2,387,500
spread over three years. An upgraded system will integrate location data with the CX
platform to give our customers accurate response info, safer roads for all and lower overall
costs by streamlining our operations with data. We began this investment in 2021 with
the 2022 shutdown of the AT&T 3G network. In doing nothing we will lose our ability to
complete a critical compliance function by being unable to complete our daily vehicle
inspections. Additionally, we fail to meet our customers where they expect us to be in
today's digitally connected economy.
VERSION HISTORY
Version Author Description Date Notes
Draft Greg Loew Initial draft of original business case 6/19/2019
1.0 Greg Loew Updated business case 7/21/2020
2.0 Greg Loew Updated business case 9/1/2022 Includes change to program
Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 523 of 535

DocuSign Envelope ID:BDF05058-842B-4637-B226-3006525C1ADB
Telematics 2025
GENERAL INFORMATION
Requested Spend Amount $2,185,250
Requested Spend Time Period 4 years.
Requesting Organization/Department Fleet K51
Business Case Owner I Sponsor Greg Loew Alicia Gibbs
Sponsor Organization/Department Energy Delivery
Phase Execution
Category Program
Driver Asset Condition
Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 524 of 535

DocuSign Envelope ID:BDF05058-842B-4637-B226-3006525C1ADB
Telematics 2025
1. BUSINESS PROBLEM
Advances in technology, customer requirements and safety are driving the need to
invest capital in our connected vehicle systems. Implementing the next generation of
telematics in vehicles on the road operating on behalf of Avista have the opportunity
to delight our customers, reduce our liability exposure and improve operational safety.
Technological Changes: Telematics works by connecting the vehicle to the cellular
data network. Currently, most telematics connectivity use third generation networks
(3G) provided by the major carriers. In February 2022 this network will no longer be
supported and many carriers are already preventing new 3G devices on their
networks. To ensure current functionality we will need to equip our vehicles to connect
to the fourth and fifth generation networks (LTE and 5G respectively). We also know
that connected worker solutions are proliferating across our workforce. This has driven
numerous data connections inside and outside of the vehicle. Telematics technology
has advanced to allow the consolidation of connections. Leading telematics providers
have embraced a platform perspective. They have acknowledged that original
equipment manufacturers are controlling some of the data flow from the vehicle or like
Caterpillar it is just build in to the equipment computer. This migration to a platform is
beneficial for Avista as we advance solutions for the fully digitized worker of the coming
decade.
Customer Requirements: Our customers are being influenced by Amazon and Google
and other leading customer experience companies. They expect timely and relevant
communications from everyone they do business with. The utility is not exempt from
these expectations. Next generation telematics is an enabling technology for a fully
integrated and digital field work process. The connected vehicle and worker,
integrated with the mobile work management system and customer experience
platform will provide greater visibility about where our field personnel are and when
they will arrive. The information will be available to employees and to customers,
improving our ability to provide firm estimates of when we will be there to complete the
work. The platform will also improve emergency response times through improved
routing and real time location services. Finally, providing more crew location
information to our dispatchers will allowing us to dispatch the crew closet to the work
saving valuable time and resources.
Safety: The impact of telematics on the overall safety to a fleet of vehicles is under
estimated. Telematics allows the capture of data around all facets of the drive cycle.
More importantly, telematics is to several leading indicator safety metrics. Next
generation telematics integrations will allow us to see items as specific as seat belt
usage, the engagement of reverse or how close we backed up to an object. Telematics
also has the ability to coach drivers in real time and or provide them a summary of
their performance on a pre-determined interval. Finally, the next generation systems
will provide metrics on the co-location of supervisors to the crews which has been
proven to be a major predictor in crew safety performance
Additionally, as the Advisory Group has engaged internal stakeholders we have
created a required functionality list. Based on current published Zonar capabilities the
following issues with Zonar were identified:
Issue Impact on Capability
Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 525 of 535

DocuSign Envelope ID:BDF05058-842B-4637-B226-3006525C1ADB
Telematics 2025
Dynamic Reporting Provides inconsistent data points
Server based system 5-8 minute lag in actual unit status
Only support Android operating system Avista has standardized on iOS
No vehicle as a hotspot capability Multiple connections and expense
Driver coaching Requires dedicated tablet
Workflow management No integrations or partnerships
Behavior metrics No metrics outside of speed to posted
Auxiliary system data capture No 3rd party device integration
Point designed solution No platform capabilities at this time
No manufacture API integration Requires us to always us an ancillary
device
Telematics 2025 will initially provide a platform for compliance. We can and will continue to
measure inspections completions and other safety related functions. We will use this
platform to capture, track and communicate this information to users and leaders. A
feedback loop to the driver on their driving performance will be a key feature of this initiative.
Over time the advanced telemetry data from this system will help us shrink the gap between
actual behaviors and expected behaviors.
The Driver Safety team that was stood up in 2017 identified a dozen key actions to improve
our vehicle incident rate. These recommendations where based on the analysis of multiple
best in class companies and the programs/practices they had in place to achieve such
results. Every program we looked at had some sort of driver performance feedback
mechanism.
1.1 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant& Operations) and the benefits to the customer
Asset Condition
Telematics 2025 is also an enabling platform for Customer Experience
advancements and Business Intelligence. We could measure improvements in
customer satisfaction, reduced maintenance costs, and lower overall cost per
customer being driven by fleet related activities.
1.2 Identify why this work is needed now and what risks there are if not
approved or is deferred
The 3G network that Zonar currently operates on will cease operations in February of
2022. Our DOT/FMCSA compliance with CFR49 and the inspections required before and
after operation are digitally managed. Not doing anything will force our commercial vehicle
operators to complete inspections by pen and paper and creates a document
management challenge because we must keep them for 12 months before disposing of
them. Failure to do so opens the company to additional liability.
Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 526 of 535

DocuSign Envelope ID:BDF05058-842B-4637-B226-3006525C1ADB
Telematics 2025
1.3 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
4. Direct Savings - Description of Estimated Direct Savings Resulting from this Business Case (please
describe and quantify any hard cost savings Avista's customers will gain due to the work under this project.
Such savings could include reductions in labor, reduced maintenance due to new equipment, or other):
By implementing vehicle telemetry as a part of this project and the subsequent data analytics that is part
of the program we will experience direct savings in the following areas:
Maintenance—Current maintenance practices are based on time, This practice means we over service a
portion of the fleet while at the same time underservicing high use vehicles.The process to manage the
underservicing is problem therefore a manual process that currently has no automation and relies on
staff knowledge/awareness. By integrating real time usage data into the Fleet Management Information
System (FMIS)we can base maintenance on actual use and potential diagnostic codes to perform
maintenance only when approaching the threshold or codes indicate an issue.
Vehicle Maintenance Potential Annual
$ 0.85 Miles Driven Per Year* 8344
Cost Per Mile* Savings
Maintenance 2 0% $ 106,386.00
Reduction
Allocation:
O&M—$42,555
Capital—$63,831
Based on current clearing account O&M vs.Capital split
Quantified direct savings:
2022 2023 Lifetime
SO $106,386 $212,772
D. Indirect Savings - Description of Estimated Indirect Savings and/or Productivity Gains Resulting from
this Project(please describe and quantify any indirect cost savings or productivity gains Avista's customers
will gain from this project). For example,deploying this capital investment reduces the future need to hire
Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 527 of 535

DocuSign Envelope ID:BDF05058-842B-4637-B226-3006525C1ADB
Telematics 2025
X number of employees. For a new substation or transmission line, are there efficiencies to be gained
from less line losses. Or, if we don't do this project now, if may cost more in the future (cost avoidance).
Telematics 2025 has the following indirect savings areas
Utilization—Vehicle use each day can be tracked and the validation of equipment needs can be verified.
The company's primary focus in the first two years will be pickup trucks. Based on utilization data and
subsequent analysis in the first two years, based on peer utility results, it is estimated that Avista can
reduce the number of light duty trucks by 7-8 units.That reduction in count results in a two year total of
$330,000(based on 2020 class average spend) is vehicles that will not need to be replaced.Additionally,
the company estimates that it can reduce is light and heavy trailers by 1% or it total units for an
additional $201,000 in capital savings These reductions may not be realized immediately but over the
class average life span we will see this reduction. This initiative will begin in 2022 and run through 2024.
It will require approximately 6 months of data for validity. This reduction also results in a total life-time
operating cost savings on maintenance of$440,310 in 2020 dollars.This is based on the light duty fleet
operating cost of$4,516 including major costs Such as fuel, maintenance, repairs and licensing over the
13 year life of a pickup truck and finally multiplying that across our estimated reduction.
Light Duty Pickup Reduction Summary Estimate
Average Vehicle Purchase
5 44,000 Fleet Reduction 0.5'% Potential Annual Savings
Price`
Realization Period(Years) 2 Vehicle Reduction 3.8 S 16S,000.00
Light and Heavy Trailers Reduction Summary Estimate
Average Non-Vehicle
S 18,295 Fleet Reduction 1.00% Potential Annual Savings
Purchase Price'
Realization Period(Years) 2 Non-Vehicle Reduction 5.5 5 100,622.50
Allocation':
O&M—$176,124
Capital—$795,186
Based on current clearing account O&M vs.Capital split
Reduced Total Mileage—Avista's fleet travels more than 7.5 million miles annually. By reducing our total
mileage driven .25% we can save $44,000 per year. The focus of this is route optimization, commuter
miles and dispatch efficiency.
Vehicle Operating Cost Potential Annual
(With Fuel) Per Mile' $ 2.84 Mileage Reduction 0.25% Savings
Miles Driven Per Year' 8344 $ 44,431.80
Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 528 of 535

DocuSign Envelope ID:BDF05058-842B-4637-B226-3006525C1ADB
Telematics 2025
Allocation:
0&M—$17,773
Capital—$26,658
Based on current clearing account O&M vs.Capital split
Customer Service
The three year average for complaint calls related to vehicles and the potential whereabouts of people
doing work on behalf of Avista totals 55 call hours per year using customer complaint records and an
average call duration of 6.5 minutes.
Calls per year Average call duration (min) CSR cost per minute Potential Annual Savings
*assumi-)g 552/hr loaded
55 6.5 $.87 $310
Allocation:
O&M—$310
Safety& Risk Reduction
The use of telematics allows us to identify risky driving behavior.
Average Accident Cost 1,788 1.00°�0
Preventable Accident Potential Annual
$
Reduction Savings
Number of
30 $ 536.40
Preventable Accidents
2020 Vehicle accident Average annual Catastrophic accident Catastrophic accident
rate per million miles corporate miles driven settlement/verdict frequency
driven
5.8 7,500,000 $7,500,000 8.5 years
Average recordable Average # of accidents Potential risk exposure Total annual risk cost
accidents per year per 8.5yr period
43.5 1 370 1 1/370 1 $20,270
Allocation:
O&M—$20,484
Capital—$321
Based on current clearing account O&M vs.Capital split
Maintenance
Under maintenance, on diesel engines with high idle times, has the potential to cost the company
$111,702 annually. By basing maintenance scheduling on real time use age data both hours and miles
we have the potential to save engine repair or replacement costs.
2020 engines replaced due to excessive idle Average cost per Potential annual
and hours exceeding manufactures engine parts& labor savings
recommended maintenance interval
5 $18,617 $93,085
Allocation:
O&M—$37,234
Capital—$55,851
Based on current clearing account O&M vs.Capital split
Business Case Justification Narrative Template Version: 04.21.2022 Page 7 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 529 of 535

DocuSign Envelope ID:BDF05058-842B-4637-B226-3006525C1ADB
Telematics 2025
Compliance
DOT inspection administration
Average admin cost per Total number of Man hours per vehicle Avoided labor cost
hour loaded commercial vehicles per year
$40 489 1 $19,560
Allocation:
0&M—$19,560
Capital—$0
Quantified indirect savings:
2022 2023 Lifetime
$238,477 $443,815 $1,907,277
Calculation details
2022 2023
Light Duty Pickup Reduction Summary Estimate $ 82,500.00 $ 165,000.00
Light and Heavy Trailers Reduction Summary Estimate $ 100,622.50
Reduced Total Mileage $ 22,215.90 $ 44,431.80
Customer Service $ 310.00 $ 310.00
Safety and Risk Reduction $ 20,806.40 $ 20,806.40
Maintenance $ 93,085.00 $ 93,085.00
Compliance 5 19,560.00 $ 19,560.00
Total $ 238,477 $443,815
1.4 Supplemental Information
1.4.1 Please reference and summarize any studies that support the problem
See the Driver Safety Team report out February 2018 by Greg Loew and Tony
Klutz
1.4.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
The current network for Zonar will ceased operation in 2022. As noted in section
1.1 several functions were noted as missing for future anticipated business
processes.
2. PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Cost Start Complete
Full telematics program implementation $2,185,250M 01 2021 122026
Partial funding telematics program $1,208,250 01 2021 122026
Business Case Justification Narrative Template Version: 04.21.2022 Page 8 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 530 of 535

DocuSign Envelope ID: BDF05058-842B-4637-B226-3006525C1ADB
Telematics 2025
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
CapabilitiesTelernatics
Identify ate Iematics solution that provides safety and compliance data on vehicles doing work
Problem Statement on behalf of Avista and enables orsupports solutions connected to the digital workerof the
future.
Required Priorit Focus
Functionality - Details - Alternatives y Area
Electronic Inspections The completion and documentation of DOT required inspections plus pre-flight inspections Paper Compliance
Regulatory Mileage
Reporting Multiple federal and state agencies require exact mileage to be reported per state N/A Compliance
Diagnostic Alerting and
Reporting The ability for the truck to pushdiagnostic troublecodestoFleet N/A Fleet
AssetWorksIntegration Pushing mileage to database to act as system of record eliminatin the need forthe vehicle ledgeN/A Fleet
iOSCompatible Must work oniOSdevices N/A IT
Driver Behavior Scoring
and Coaching Feed back mechanism to help drivers know howthey are driving In cab ordaily summary Safety
in
4G and 5G capable 3G network is at end of life N/A IT
Customer
Customerfacing info Customer know who the worker is that will be serving them and visibility into when they will betN/A Service
Utilization Reporting and mechanisms for understanding under utilized equipment N/A Fleet
Idle Reduction Knowingwhat it productive idle and non-productive idle N/A Fleet
ECM data/Vehicle Maintain current system
Performance Real-time performance data to build dynamic maintenance response of time base Fleet
Integration for
Distribution Dispatch Showin vehicle assetsto distribution dispatchers to improve dispatch capabilities N/A 11T
Work Flow Management Match personnel and resourcesto work requiring completion(work management)(maybe a tie tc N/A Operations
Assumptions based on
Driver Identification Knowing who is driving every single truck every time it moves inspection Safety
Behavior Metrics Data analysis info to understand trends and habits N/A Safety
Uses air bag computer
Accident Reconstruction Capability to record some amount of data that can be analyzed after minor crashes after major crashes Safety
Integration of mulitple
telemetry data systems Trailers and other AVA assets can use different location systems. Put everything one syste Fleet
Auxiliary System Data
Capture Capability to capture data from other systems installed on the truck(back up sensors,seatbelt us N/A Safety
GPS location for non
motorized units Find the losttrailer N/A Fleet
Current system with
Vehicle Hotspot Vehicle based data connection point rugged laptops 11T
App that could be installed on contractors phone to know where they are at in our system(think
Smart Phone App gas survey) N/A IT
Productivity Expedited routin N/A Operations
Co-Location Where are supervisors(GFs,managers)in relations to crews N/A Safety
Mobile Device Use Utilizing mobile device app integrated with telematics to know if the phone is used while vehicle App deployed with MDM
Reporting is in motion solution Safety
Satellite Connectivity For use in remote wilderness areas N/A Safety
One vehicle foreach
Vehicle Pooling Dynamic assignment of available vehicle toworker requiring vehicle worker Fleet
Forward facing camera
Driver Cameras lForward and rear facing in cab cameras lonly ISafety
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
Telematics 2025 will be implemented over a six year period beginning in 2021 in order
to meet 3G obsolescence. In year one our commercial fleet will be functional and on
Business Case Justification Narrative Template Version:04.21.2022 Page 9 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J.DiLuciano,Avista
Schedule 3,Page 531 of 535

DocuSign Envelope ID:BDF05058-842B-4637-B226-3006525C1ADB
Telematics 2025
the new systems. In years two and three we will bring our light duty vehicles fully on to
the platform plus trailers and complete integrations to systems like Assetworks, Intelex
and Oracle.
On an ongoing basis the operational costs for telematics flow to the Fleet Clearing
Account. From there a portion of the costs go to capital and some to O&M depending
on the class of vehicle. Vehicle rates for light duty trucks and trailers will see a small
impact from this technology.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward(ref. WUTC Docket No. U-190531 Policy
Statement),therefore it is critical that these impacts are thought through in order to support rate recovery.]
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Telematics 2025 will continue to be used by Fleet and Distribution Ops. The CX project
will use the data stream from this system as described in section 1.1. Vehicle
electrification efforts have the potential to tap into the platform.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Upgrade existing system. Preserve current functionality with technology that
does not meet current or future business needs across the enterprise.
Partial install on only the on-road portion of our fleet (excludes trailers)
Partial install of new system on commercial motor vehicles only. Preserves
current functionality does not integrate or capture almost a third of all Avista
owned vehicles. Many safety and operational benefits would not be met.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
$808K Q1-2023 Q2-2023 Q3-2023 Q4-2023
Product orders Product Vehicle installs Project
and TTP EOFY installs TTPs as planning and
22 work districts or orgs remaining TTP
completed
$400K Q1-2024 Q2-2024 Q3-2024 Q4-2024
Planning and Development Development Development
sow
$200K Q1-2025 Q2-2025 TTP Q3-2025 Q4-2025
Implementation 2024 work
$200K Q1-2026 Q2-2026 Q3-2026 Q4-2026
Planning and Integrations,
sow installs and
final TTP
Business Case Justification Narrative Template Version: 04.21.2022 Page 10 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 532 of 535

DocuSign Envelope ID:BDF05058-842B-4637-B226-3006525C1ADB
Telematics 2025
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Enhancing the telematics in the fleet vehicles directly aligns with the four focus areas,-
customers, people, perform and invent.
Customers are better served by providing a platform that enables notifications and
awareness of crew arrival times. Avista Employees are better served through
interactive coaching and feedback on their driving behavior. Performance is better
served through the enhanced integrations that are enabled and the information that can
be shared across multiple systems. Invention is served by recognizing that the
expectations of customer service has changed, and that technology is required, not
only in our back office but in the front-line vehicles that serve as the initial touchpoint
for many customer interactions.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The majority of Telematics 2025 scope is the replacement of a system that will no longer
operate after February 2025. As outlined in section 1.1 our next generation telematics
will enable additional functions and help streamline analog processes. Project
management and business case owner will continue to review the scope of the project
for material changes.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Stakeholder Name Department
Andrea Pike Customer Service
Reuben Arts Distribution Dispatch
Amy Parsons Finance
Paul Good Gas Ops
Alexis Alexander GPSS
Mike Littrel Enterprise Technology
Jon Thompson Enterprise Technology
2.8.2 Identify any related Business Cases
Business Case Justification Narrative Template Version: 04.21.2022 Page 11 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 533 of 535

DocuSign Envelope ID:BDF05058-842B-4637-B226-3006525C1ADB
Telematics 2025
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
This project reports in with the executive advisory committee comprised of:
Heather Rosentrater Jason Thackston Jim Kensok
Alicia Gibbs Jeremy Gall Kermit Olson
Jim Corder Liz Fredrickson
3.2 Provide and discuss the governance processes and people that will
provide oversight
Specific project updates will be provided and key decisions will be confirmed by the
group from the program owner.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The project manager and the business case owner will be responsible for monitoring
and recording priority changes and material change requests.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the <Business Case Name> and agree
with the approach it presents. Significant changes to this will be coordinated with and
approved by the undersigned or their designated representatives.
Signature: ,b.,�0�- Date: Sep-09-2022 1 8:42 AM PDT
eozeeeme.rz�izi
Print Name: Greg Loew
Title: Fleet Manager
Role: Business Case Owner
Business Case Justification Narrative Template Version: 04.21.2022 Page 12 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 534 of 535

DocuSign Envelope ID:BDF05058-842B-4637-B226-3006525C1ADB
Telematics 2025
Signature: aGaa Gilby
Date: Sep-08-2022 11:16 PM PDT
�T9CA2BSo3Q5EII83._
Print Name: Al i ci a Gi bbs
Title: Alicia Gibbs
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: 04.21.2022 Page 13 of 13
Exhibit No. 10
Case Nos.AVU-E-25-01/AVU-G-25-01
J. DiLuciano,Avista
Schedule 3,Page 535 of 535