20230201DiLuciano Direct.pdf

DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
[e-mail]

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-23-01
OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-G-23-01
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND ) DIRECT TESTIMONY
NATURAL GAS SERVICE TO ELECTRIC ) OF
AND NATURAL GAS CUSTOMERS IN THE ) JOSHUA D. DILUCIANO
STATE OF IDAHO )
)

FOR AVISTA CORPORATION

(ELECTRIC AND NATURAL GAS)

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

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distribution infrastructure. I will explain how our efforts to maintain the asset health and 1
performance of our electric transmission system, including compliance with mandatory 2
federal standards for transmission planning and operations, is driving a continuing demand 3
for new investment. Further, I will describe why our investments in natural gas distribution 4
are necessary in the time frames completed and why each capital investment in our operations 5
facilities and fleet operations is needed to support the efficient delivery of service to our 6
customers, today and into the future. Furthermore, I will address the electric and natural gas 7
distribution, transmission, general plant and fleet related capital additions included in the 8
Company’s Two-Year Rate Plan filed in this case, for the periods July 1, 2022 through August 9
31, 2025. A table of the contents for my testimony is as follows: 10
Description Page 11
I. INTRODUCTION 1 12
II. OVERVIEW OF AVISTA’S ENERGY DELIVERY SERVICE 3 13
III. INVESTMENTS IN THE COMPANY’S ELECTRIC 14
DISTRIBUTION SYSTEM 7 15
IV. INVESTMENTS IN THE COMPANY’S ELECTRIC 16
TRANSMISSION SYSTEM 15 17
V. INVESTMENTS IN THE COMPANY’S NATURAL GAS 18
SYSTEM 23 19
VI. INVESTMENTS IN THE COMPANY’S OPERATIONS, 20
FACILITIES AND FLEET SERVICES 31 21
Q. Are you sponsoring any exhibits in this proceeding? 22
A. Yes. I am sponsoring the following Schedules as a part of Exhibit No. 9: 23
• Schedule 1, Avista’s Priority Aldyl-A Protocol Report 24
• Schedule 2, Study of Aldyl-A Mainline Pipe Leaks - 2022 Update 25
• Schedule 3, Capital Business Case documents for each of the capital projects 26
and programs described in my testimony 27
28
Q. Will you be providing an overview of Avista’s Wildfire Resiliency Plan in 29

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your testimony? 1
A. While I am the officer responsible for our work in this important area, 2
Company witness Mr. Howell will provide an overview of the strategy and actions comprising 3
the plan, including the investments the Company is making under the plan. 4
5
II. OVERVIEW OF AVISTA’S ENERGY DELIVERY SERVICE 6
Q. Please describe Avista’s electric and natural gas utility operations. 7
A. Avista operates a vertically integrated electric system in Idaho and 8
Washington, and natural gas local distribution operations in Idaho, Washington and Oregon. 9
In addition to the hydroelectric, renewable, and thermal generating resources described by 10
Company witness Mr. Kinney, the Company has an electric transmission system comprised 11
of approximately 700 miles of 230 kV lines and 1,600 miles of 115 kV lines. Avista has 12
approximately 19,300 miles of primary and secondary electric distribution lines. The 13
Company owns and operates approximately 8,000 miles of natural gas distribution lines, 14
served from the Williams Northwest and Gas Transmission Northwest (GTN) pipelines. A 15
map showing the Company’s electric and natural gas service area in Idaho, Washington and 16
Oregon is provided by Company witness Mr. Vermillion. 17
As detailed in the Company’s 2021 Electric Integrated Resource Plan (IRP),1 Avista 18
expects retail electric sales growth to average 0.3% annually for the next ten years in our 19
service territory, similar to the rate in the 2020 IRP. Also, based on Avista’s 2021 Natural Gas 20
IRP,2 in Idaho and Washington the number of natural gas customers is projected to increase 21
at an average annual rate of 1.11%, with demand growing at a compounded average annual 22

1 The Company’s 2021 Electric IRP has been provided by Mr. Kinney (Exhibit No. 6, Schedule 1).
2 The Company’s 2021 Natural Gas IRP has been provided by Mr. Kinney (Exhibit No. 6, Schedule 3).

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rate of 0.33%. 1
Q. How many customers are served by Avista in the State of Idaho? 2
A. Of the Company’s approximate 410,000 electric and 378,000 natural gas 3
customers, 142,000 and 93,000, respectively, were Idaho customers. 4
Q. Please list the Company’s operations service centers that support electric 5
and natural gas customers in Idaho. 6
A. The Company has construction offices in Coeur d’Alene, Sandpoint, St. 7
Maries, Kellogg, Grangeville, Moscow/Pullman, and Lewiston/Clarkston. Avista’s three 8
customer contact centers, located in Coeur d’Alene and Lewiston, Idaho, and Spokane, 9
Washington, are networked, allowing the full pool of regular and part-time employees in each 10
location to respond to customer calls from all jurisdictions. 11
Q. Please describe the Company’s Service Quality Measures Program. 12
A. Avista’s Service Quality Measures Program was approved by the Commission 13
in November 2018, and includes the following measures:3 14
✓ Reporting on two (2) measures of electric service reliability. 15
✓ Seven (7) individual service standards, where Avista provides customers a 16
payment of bill credit in the event the Company does not deliver the required 17
service level (Customer Service Guarantees), and 18
✓ Five (5) individual measures of the level of customer service and satisfaction 19
the Company must achieve each year. 20
21
Q. Did Avista achieve its Service Quality Measures Program benchmarks for 22
2021? 23
A. The Company is pleased to report we exceeded all six Customer Service 24
Measure benchmarks for our most recent reporting year in 2021 and noted a continuing 25

3 Order No. 34181 in Case Nos. AVU-E-18-10 and AVU-G-18-06

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relatively stable long-term trend in electric service reliability.4 Results for Avista’s 2021 1
Customer Service Measures are provided in Table No. 1: 2
Table No. 1 – 2021 Results for Avista’s Customer Service Measures 3
4
5
6
7
8
9
10
11
Q. Please describe the approach used by Avista for evaluating and managing 12
the energy delivery capital investments required to serve our customers. 13
A. Proposals for individual projects and programs are initially developed, 14
reviewed and evaluated in each responsible business unit, often followed by review, 15
evaluation and prioritization by higher-level review committees, such as Avista’s Engineering 16
Roundtable, the Aldyl A Pipe Advisory Group, and the Facilities Steering Committee. In this 17
review, projects are evaluated for completeness of the problem statement, the identification 18
and evaluation of reasonable alternatives, and applicable risks, and other elements. Refined 19
and finalized proposals are submitted to the Company’s Capital Planning Group for 20
consideration and recommendation of funding (as described in the testimony of Company 21
witness Mr. Thies). Once approved for funding, the Project Engineer or Manager identifies 22

4 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 2022 by April 30, 2023.

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critical project milestones and the resources needed to achieve them. Major equipment with 1
long lead times may be purchased in this phase, necessary permitting identified and 2
completed, and contracting processes initiated. 3
During execution, the Company’s Project Managers create a detailed work schedule 4
and establish inspection, monitoring, safety, environmental, and invoicing protocols. Standard 5
project management practices are employed to effectively guide the work, identify, and 6
manage project risks, recommend needed changes to scope and budget, and track and report 7
out on overall status. Examples of tools that may be used to track budget and schedule, 8
depending upon the size and scope of a project, include Earned Value Measurement, cost-9
loaded scheduling, Cost Performance Index (CPI) and Schedule Performance Index (SPI).5 10
Project results are regularly reviewed with the responsible Department Manager, applicable 11
committee, and/or Director which review includes budget allocations and variances, internal 12
resource demands, customer care results and issues, and contractor performance. 13
Q. Are alternatives vetted for these projects before approvals are given? 14
A. Yes. Where there are reasonable alternatives, the evaluation of those is 15
discussed in each business case (business case documents for the capital projects I am 16
sponsoring have been included as Exhibit No. 9, Schedule 3). 17
Q. How is Avista’s leadership informed of the program status? 18
A. As described above, project and program status and results are communicated 19
up departmental lines, through various committees, and to me via my Director-level direct 20
reports. Program and project results are also reported directly to Avista’s Capital Planning 21

5 Cost Performance Index (CPI) is computed by Earned Value / Actual Cost. A value of above 1 means that the
project is doing well against the budget. Schedule Performance Index (SPI) represents how close actual work is
being completed compared to the schedule. SPI is computed by Earned Value / Planned Value.

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Group, and the Company’s senior leaders, including myself, through steering committees, 1
various business meetings, and presentations. 2
3
III. INVESTMENTS IN THE COMPANY’S ELECTRIC DISTRIBUTION SYSTEM 4
Q. Please summarize the need for continuing investments in the electric 5
distribution system. 6
Avista, like utilities across the country, continues to prudently fund the increasing 7
demand for investment in electric distribution infrastructure. The pattern of our investments 8
bears a striking resemblance to that of the industry, which should not be a surprise, since we 9
are all responding to the same predominant needs: first, we are experiencing customer growth 10
in our Idaho service territory, second, the need to replace an increasing amount of 11
infrastructure each year that has reached the end of its useful life (based on asset condition), 12
and third, responding to the need for technology investments required to build the integrated 13
energy services grid of the future. To provide better visibility of the factors driving this need 14
for investment, we continue to organize the Company’s planned spending over the current 15
five-year planning horizon by “Investment Driver” categories. Another aspect of investment 16
in electric distribution infrastructure is maintaining and upholding our current overall 17
reliability performance. In 2019, Avista developed draft recommendations for a new electric 18
service reliability strategy based on the aspects we believe are most important to our individual 19
customers and the prudent long-term management of our system. While we will continue to 20
report historic reliability performance, our new approach is forward focused to better 21
understand, evaluate and respond to long-term reliability trends and thus, investments in the 22
electric distribution system. This work is based on intensive use of historic reliability data, 23
infrastructure modeling and robust statistical forecasting. 24

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Investment Driver
Business Case Name 20221 2023 2024 20252
Customer Requested
New Revenue - Growth 42,893$ 64,393$ 58,607$ 32,947$
Mandatory and Compliance
Elec Relocation and Replacement Program 1,527$ 7,469$ 7,000$ 5,052$
Joint Use 2,033 5,000 4,000 2,667
Saddle Mountain 230/115kV Station (New) Integration Project Phase 2 - 3,204 - -
Failed Plant and Operations
Electric Storm 2,660$ 3,440$ 3,440$ 2,293$
Meter Minor Blanket 88 250 250 167
Asset Condition
Distribution Grid Modernization 1,224$ 2,219$ 1,211$ 1,089$
Distribution Minor Rebuild 6,235 13,000 13,476 9,886
LED Change-Out Program 171 248 248 163
Substation - Station Rebuilds Program 1,877 18,886 14,825 15,098
Wood Pole Management 4,066 13,000 10,000 8,613
Performance & Capacity
Distribution System Enhancements 4,862$ 7,901$ 6,998$ 3,262$
Substation - New Distribution Station Capacity Program 918 9,773 4,696 2,517
Total Planned Electric Distribution Capital Projects 68,554$ 148,783$ 124,751$ 83,754$
(1) Includes system pro forma capital additions for the period of July 01, 2022 though December 31, 2022.
(2) Includes system pro forma capital additions for the period of January 01, 2025 though August 31, 2025.
Electric Distribution Capital Projects (System) In $(000's)
Q. Would you please summarize the capital investments in electric 1
distribution plant completed in 2022 and planned for over the Two-Year Rate Plan? 2
A. Yes. As discussed by Company witnesses Ms. Schultz and Ms. Benjamin, 3
Avista’s capital witnesses, including myself, describe the capital projects included in the 4
Company’s proposed Two-Year Rate Plan, reflecting pro forma capital additions for the 5
period between July 1, 2022 and August 31, 2025. The completed and planned investments 6
related to electric distribution, presented on a system basis and grouped by investment driver, 7
are shown below in Table No. 2, and described below. 8
Table No. 2 – Electric Distribution Capital Projects (System) 9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
New Revenue Growth - Electric – 2022: $42,893,000, 2023: $64,393,000, 2024: 38
$58,607,000, 2025: $32,947,000 39

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Avista defines these investments as “customer requests for new service connections, line 1
extensions, transmission interconnections, or system reinforcements to serve a single large 2
customer.” We have often in the past referred to new service connects as “growth,” as in 3
growth in the number of customers, however, these investments are beyond the control of the 4
Company, and as such they do not reflect a plan or strategy on the part of Avista. Responding 5
quickly to these customer requests is a requirement of providing utility service. Typical 6
projects include installing electric facilities in a new housing or commercial development, 7
installing, or replacing electric meters, or adding street or area lights per a request from an 8
individual customer, a city, or county agency. As would be expected, fluctuation in the number 9
of new customer connections is largely dependent on local economic conditions both in the 10
housing and business sectors. The New Revenue Business Case is driven by requirements that 11
mandate Avista’s obligation to serve new customer load when requested within our franchised 12
area. Growth is also seen as a method to spread costs over a wider customer base, keeping rate 13
pressure lower than would otherwise be experienced. The Company has included Idaho 14
electric offsetting revenues of $3,328,000 in Rate Year 1 in Adjustments 3.12 and offsetting 15
revenues of $1,827,000 in Rate Year 2 in Adjustment 24.06. 16
17
Electric Relocation and Replacement Program – 2022: $1,527,000, 2023: $7,469,000, 18
2024: $7,000,000, 2025: $5,052,000 19
Placement of the Company’s electric facilities is generally located in easements provided in 20
public rights of way that are governed by jurisdictional franchise agreements. When requested 21
by the local jurisdiction, typically related to transportation projects, the Company must 22
relocate its facilities in the right of way to accommodate these projects. Avista is obligated 23
under terms of its franchise agreements to move its facilities at its own expense and within the 24
timeframe specified by the local jurisdiction. Using public rights of way for our many 25
thousands of miles of electric infrastructure provides a cost-effective way to serve our 26
customers, even considering the costs associated with the periodic requirement for their 27
relocation. Agreeing to move our facilities when requested is an important provision that 28
allows the Company to negotiate favorable franchise agreements, which in turn, allows us to 29
continue providing reasonable service to our customers at an affordable cost. The need for 30
electric relocations and replacements is driven by the plans of our local jurisdictions, and as 31
such, is not an activity that Avista can anticipate in definitive terms, plan for, or manage like 32
a project internal to the Company. Accordingly, the annual spending levels can be quite 33
variable so Avista budgets for this activity in coming years based on the spending levels 34
experienced in the prior five-year period. The actual spending level each year is determined 35
by the number and size of projects the Company is required to complete. 36
37
Joint Use Projects - 2022: $2,033,000, 2023: $5,000,000, 2024: $4,000,000, 2025: 38
$2,667,000 39
Joint Use is the regulated use of utility poles and other structures owned by Avista that are 40
available for use by third-party telecommunications companies to provide their services to 41
customers we have in common. Avista is reimbursed for this joint use by tariffs in each of our 42
jurisdictions, which reimbursement serves to directly lower the cost our customers pay for 43
their Avista service. These joint use projects, referred to ‘make ready,’ meet our obligation to 44
provide adequate clearance for the attachment of third-party infrastructure by installing taller 45
structures (typically wood poles) than would be required for Avista’s facilities alone. These 46
annual projects are part of a continuing program where the Company responds to the requests 47

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of third parties to make our facilities ready for their infrastructure. The Company is subject to 1
regulatory action, penalties, and/or civil litigation if it does not timely perform the mandated 2
make ready work when requested. The need for joint use projects is driven by the plans and 3
requests of third parties and is beyond the control of the Company. The amount of work 4
performed each year, and the resulting spending is therefore variable year-to-year. 5
Historically, the Company included investments supporting joint use as part of the electric 6
Distribution Minor Rebuild program. The level of investment required recently, however, 7
signaled the need to present these activities in a separate business case. 8
9
Saddle Mountain 230/115kV Station (New) Integration Project Phase 2 – 2023: 10
$3,204,000 11
Avista learned in 2013 of grid performance issues on Grant County Public Utility District’s 12
electric system that were exacerbated by Avista’s load service in our Othello service area. 13
This issue was subsequently advanced to Columbia Grid through the regional planning 14
process, which along with Avista’s own system planning analysis, determined our system 15
could not meet several NERC performance requirements during periods of summer heavy 16
load and some categories of winter loading. The Saddle Mountain project was developed as 17
the selected solution to mitigate this issue and to ensure Avista’s compliance with mandatory 18
NERC performance standards. Construction of the new substation, however, required a range 19
of other work to be completed in phases in order to integrate it into electric system. One of 20
these phases under our electric distribution plant investments is focused on electric 21
transmission system improvements required to integrate the new Saddle Mountain substation 22
with our new Othello city substation. This business case is important to customers that they 23
can continue to have the reliability of the electric system that they have become accustomed 24
to receiving. 25
26
Electric Storm – 2022: $2,660,000, 2023: $3,440,000, 2024: $3,440,000, 2025: $2,293,000 27
The Electric Storm investments cover the cost of restoring Avista’s electric transmission, 28
substation, and distribution systems to serviceable condition when damaged during a 29
significant weather (storm) event or other natural disaster. These storm events include high 30
winds, heavy wet snow, ice, lightning strikes, flooding, and wildfire, and various 31
combinations of them, to name a few. Most of this damage typically occurs on the Company’s 32
extensive electric distribution system, however, some storm events also impact our electric 33
transmission system. Significant storm events are best understood as random forces6 that often 34
occur with short notice, and that are beyond the control of the Company7 to prepare for or 35
prevent. 36
37
Investments made to restore our electric system after major events include replacement of 38
wood poles, crossarms, conductor, transformers, and customers’ secondary service lines. 39

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.
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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Making the area safe after an event, and quickly replacing damaged equipment is crucial to 1
promptly restoring service to our customers. The need for investments in infrastructure 2
restoration is difficult to predict year-to-year, requiring the Company to consider recent 3
history and long-term trends in setting forecast budgets for these types of investments. 4
5
Meter Minor Blanket – 2022: $88,000, 2023: $250,000, 2024: $250,000, 2024: $167,000 6
Utilities regularly plan for the replacement of assets that have reached the end of useful life, 7
which includes the replacement of slow, failing or stopped meters. When meters fail to read 8
accurately (typically more the case with analog electro-mechanical meters) or stop reading 9
altogether, Avista quickly replaces the meter to avoid having to estimate a substantial portion 10
of the customers’ usage. Expected capital spending for replacement of meters is based on the 11
Company’s experienced failure rates for its population of meters in service. 12
13
Distribution Grid Modernization – 2022: $1,224,000, 2023: $2,219,000, 2024: $1,211,000, 14
2025: $1,089,000 15
The purpose of this program is to cyclically rebuild and upgrade every electric feeder in 16
Avista’s distribution system, with the objectives of replacing end of life assets, while 17
evaluating improvements in feeder design to bolster service reliability, capture energy 18
efficiency savings, and improve operational ability, code compliance and safety.8 These 19
objectives are accomplished through the systematic replacement of end-of-life equipment, 20
such as old poles, conductor, and transformers, with new and more energy-efficient equipment 21
that ensures the long-term, efficient operability of the system. Other issues addressed on each 22
feeder include pole realignment to address accessibility issues and rights of way concerns, 23
potential feeder undergrounding, coordination of joint use facilities, and clear zone 24
compliance. On qualifying feeders, additional system reliability value is captured by installing 25
distribution line automation devices to help isolate outages and reduce the number of 26
customers that experience a sustained outage (also known as feeder automation). 27
28
The primary alternatives to this program are to replace distribution poles and attached 29
equipment as they fail in service or to continue funding work under the various operational 30
initiatives designed to treat individual aspects of each feeder, including the wood pole 31
management program, polychlorinated biphenyls (PCB) transformer change-out program, 32
vegetation management program, segment reconductor and feeder tie program, overhead to 33
underground conversion, and various other budgeted maintenance programs. Combining the 34
work of these individual programs into one is not only more efficient, but it also enables the 35
entire feeder to be evaluated for beneficial changes in design, alignment, and in other ways 36
not possible when individual elements of the line are simply replaced in an “as is” 37
configuration. Absent this program, the Company would continue to treat every feeder in its 38
system under individual maintenance programs. The value created by opportunities to 39
improve the design, construction and operation of the feeder would be missed. Further, 40
bundling the work of these individual programs for targeted feeders into one coordinated 41
effort improves the cost efficiency by reducing redundant travel costs and capturing labor 42
productivity. In short, customers would experience higher costs for a less robust system absent 43

8 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 the application of new technology.

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this program. The Company has included $11,495 in Idaho direct offsets, as detailed in 1
Adjustments 3.12 and 24.06. 2
3
Distribution Minor Rebuild – 2022: $6,235,000, 2023: $13,000,000, 2024: $13,476,000, 4
2025: $9,886,000 5
The purpose of this program is to replace end-of-life assets and respond to a range of 6
operations needs in order to provide public and employee safety and the continuity and 7
adequacy of service to our customers. In addition to needed work that is ancillary to customer-8
requested service, minor rebuilds, and replacement of individual assets are required across the 9
distribution system as issues are identified to maintain system integrity, reliability, and safety. 10
There are no traditional alternatives to the work completed under this program since it consists 11
of many, small unplanned projects9 across the entire electric distribution system. These small, 12
unplanned projects are responsive to a range of factors generally beyond the control of the 13
Company. Examples include ancillary work required by customer-requested rebuilds,10 14
“trouble work” – like the repair of damage from a car-hit-pole, investments needed to support 15
joint use of our facilities, replacement of deteriorated or failed equipment that is not scheduled 16
for planned asset condition replacement, and small general rebuilds required to meet National 17
Electric Safety Code (NESC) requirements, remediate failed, under-sized or unsafe 18
equipment, and install needed switches, regulators, line reclosers, etc. There are instances 19
among the small rebuild projects where limited alternatives are evaluated in the design phase 20
by the individual project designer. In general, however, there is no reasonable alternative to 21
timely making these investments once the need has been identified. 22
23
Light Emitting Diode (LED) Change Out Program – 2022: $171,000, 2023: $248,000, 24
2024: $248,000, 2025: $163,000 25
Avista operates approximately 35,000 streetlights we have installed for many public 26
jurisdictions across our service territory as well as area lights requested and paid for by 27
individual customers. In 2013, in response to the superior safety performance of LED lighting, 28
the energy savings potential, and the opportunity to reduce long-term energy costs, Avista 29
evaluated the potential benefit of converting streetlights from conventional High-Pressure 30
Sodium (HPS) to LED fixtures. LED bulbs cut electricity use by up to 85% compared with 31
incandescent bulbs, and 40% compared with fluorescent lighting.11 After careful evaluation 32
the program was launched in 2015 and focused initially on replacing our predominant 100 33
watt “cobrahead” streetlights. The program was expanded to include higher wattage lights 34
(200 and 400 watts) as subsequent price reductions for these fixtures made it cost effective for 35
customers. Under our current program, as conventional streetlight bulbs fail in service, 36
fixtures are replaced with LED lighting. Forecasted expenditures are based on the annual 37
expected failure rate of our conventional streetlights in service. 38
39
Substation – Station Rebuilds – 2022: $1,877,000, 2023: $18,886,000, 2024: $14,825,000, 40
2024: $15,098,000 41
Projects to rebuild the Company’s aging electric substations involve replacing and upgrading 42

9 For example, the average cost of each of these small projects is approximately $4,500, which translates to over
2,000 individual projects in a given budget year.
10 These investments include work required to properly maintain the system, but that are not reasonably covered
by the tariffed financial contribution required of the customer.
11 https://thinkprogress.org/5-charts-that-illustrate-the-remarkable-led-lighting-revolution-83ecb6c1f472.

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structures, fencing, grounding, apparatus and equipment at end-of-life, when obsolete, or is 1
otherwise necessary to maintain safe and reliable operation of Avista’s transmission and 2
distribution systems. While asset condition of the overall substation including major apparatus 3
and equipment is the primary driver for these investments, additional factors may broaden the 4
scope of a station rebuild project. These factors include underperforming assets as the system 5
changes (i.e., protection, reliability, or capacity), operational and maintenance requirements, 6
updated design and construction standards, SCADA communications, future customer load-7
service needs, and other programs such as Grid Modernization. This program (Substation 8
Rebuilds) differs from Avista’s Substation Asset Management program in that the latter is 9
focused on replacing only aging apparatus and equipment, and not rebuilding or refurbishing 10
the entire substation. In some instances, instead of replacing or rebuilding aging substations, 11
Avista could continue to manage stations under the Substation Asset Management Program, 12
however, this alternative is not reasonable by the time the Company has identified the need 13
for substantial rebuild or replacement. This is because aged equipment is often obsolete and 14
replacements are unavailable, because some structures such as the grounding pad, cannot be 15
replaced once failed, and because a station might have to be taken out of service for an 16
extended period of time for major work on structures and equipment. When aging substations 17
reach this point in their lifecycle, the only reasonable alternative is to completely refurbish or 18
rebuild them.12 19
20
Distribution Wood Pole Management – 2022: $4,066,000, 2023: $13,000,000, 2024: 21
$10,000,000, 2025: $8,613,000 22
Avista has approximately 240,000 wood poles13 in its combined electric distribution system 23
and a portion of these must be replaced each year based on asset condition, i.e., replacement 24
of poles and attachments that have reached the end of their useful service life. Our wood poles 25
are inspected on a 20-year cycle, resulting in our inspection of approximately 12,000 poles 26
each year.14 Individual poles or attached equipment that don’t meet our inspection criteria are 27
replaced as part of capital follow-up work. Attached equipment includes overhead distribution 28
transformers, cutouts, insulators and pins, wildlife guards, lighting arresters, cross arms, pole 29
guying, and grounds. The primary alternative to this proactive inspection and replacement 30
program is to simply replace poles as they fail in service and fall down (asset strategy known 31
as “run to fail”). Sub-alternatives evaluated include inspecting the pole population on a cycle 32
time either shorter or longer than the current 20-year cycle. 33
34
Avista analyzed the option of replacing poles as they fail, as well as a range of inspection 35
cycle intervals ranging from 5 to 25 years. The customer value of the 20-year cycle, as 36
measured by customer rates of return, is superior to both the run-to-fail option and the 25-year 37
cycle time. Perhaps even more importantly in today’s world, a run to fail strategy would also 38
increase wildfire risk. Cycle intervals shorter than 20 years do produce slightly better results 39
as measured by their respective customer internal rates of return. This incremental increase in 40
value is the result of avoiding failures in poles and attached equipment that would otherwise 41

12 When replacing a substation, the new substation is often placed adjacent to the existing substation, which
remains in service until the new substation is completed, ensuring minimal outages to the customers served on
from the station.
13 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.
14 Avista’s Wood Pole Inspection Program is funded as an expense.

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Avista Corporation
occur with longer inspection cycles.15 Importantly, any reduction in cycle time requires an up-1
front increase in expenses to pay for the increased number of poles inspected each year, and 2
a corresponding increase in requirements for capital replacements, at least through the first 3
complete inspection cycle. Avista believes this incremental increase in costs would put too 4
much near-term price pressure on our customers, considered in combination with the margin 5
of benefit and Avista’s many other infrastructure investment needs. The Company is 6
continuing with its 20-year inspection cycle. 7
8
Distribution System Enhancements – 2022: $4,862,000, 2023: $7,901,000, 2024: 9
$6,998,000, 2025: $3,262,000 10
Avista’s electric distribution system is composed of 347 individual ‘feeder’ lines that carry 11
primary electric power to customers across our service area in Idaho and Washington. As new 12
customers are added to these feeders, and as existing customers add new and different types 13
of loads to their service, the carrying capacity of feeders, and often segments of feeders, is 14
reached or exceeded. When the capacity of a circuit has been exceeded it creates excess heat 15
in the conductor and components resulting in the conductor sagging closer to the earth than 16
designed, creating a violation of NESC prescribed safety limits. In extreme situations the 17
conductor itself can melt and fail, dropping energized lines to the ground and creating a very 18
significant safety and fire hazard. Avista determines the carrying capacity margin for its 19
feeders based on SCADA monitoring, where it is available, and system load modeling and 20
analysis using the Synergee load flow computer program. When the Company identifies a 21
feeder or segment with capacity limitations the local engineer evaluates alternatives for 22
solving the problem, which most often include the installation of larger, higher-capacity 23
conductor on the target segment(s) or construction of a “tie” line to an adjacent feeder that has 24
sufficient capacity to carry a portion of the customer load of the first feeder. Managing our 25
electric distribution system in a manner that ensures our service is adequate, safe, reliable and 26
compliant, and at a reasonable cost, is in the interest of our electric system customers. The 27
Company has included $25,315 in Idaho direct offsets, as detailed in Adjustments 3.12 and 28
24.06. 29
30
Substation – New Distribution Station Capacity Program – 2022: $918,000, 2023: 31
$9,773,000, 2024: $4,696,000, 2025: $2,517,000 32
New distribution substations added to the system for load growth and reliability are critical to 33
the long-term operation of the system. As load demands increase and customer expectations 34
rise regarding reliability, incremental distribution substation capacity is required. This allows 35
for improved operational flexibility, better system reliability, and easier routine maintenance 36
scheduling as equipment is more easily taken out of service because load can be transferred. 37
Capacity on the electric system to be able to take components out of service on a planned basis 38
so that maintenance or replacements can be made has reduced as load demands have increased. 39
Having the right amount of backup capacity in each area is critical for the continued 40
appropriate management of the electric system. This business case is important because 41
through it, customers can likely continue to receive electric service at a level that they have 42
grown accustom to receiving. 43
44

15 On average, under its current 20-year inspection cycle interval, Avista experiences approximately 12 pole
failures each year out of its population of 230,000 wood poles.

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Avista Corporation
IV. INVESTMENTS IN THE COMPANY’S ELECTRIC TRANSMISSION SYSTEM 1
Q. Would you please summarize the need for continuing investments in 2
electric transmission infrastructure? 3
A. Drivers for new investment in the Company’s electric transmission 4
infrastructure include: 5
➢ System improvements required to meet the myriad and expanding federal regulations 6
governing nearly every aspect of our transmission business. Chief among these are the 7
tightening requirements to meet ever-more restrictive transmission operations and 8
planning standards, driven by the assessment of financial penalties for noncompliance. 9
10
➢ Timely replacement of end-of-life assets based on condition. This need continues to 11
be at an all-time high across the industry and will continue to increase year-over-year 12
for at least the next two decades. This need is tied to the major expansion of new 13
electric infrastructure built during the economic boom following the end of World War 14
II. Because these assets are now at or near the end of their useful lives, a substantial 15
boost in new investment is required, compared with previous years, just to maintain 16
existing systems. 17
18
➢ External demands on our transmission system, including new transmission 19
interconnections required for third parties to integrate new, variable energy resources, 20
particularly wind and solar. These interconnections require significant capital 21
investment to extend or reinforce our transmission system and often take priority over 22
investments required to provide for native load service on our system. 23
24
➢ Siting, permitting, and constructing transmission assets has become more complex, 25
time-consuming, and expensive due in part to increasing environmental, property 26
rights, and land-use requirements. Permitting can extend over several years and 27
typically includes conditions constraining how utilities site, design, construct and 28
maintain these assets. 29
30
When it comes to the impact for our customers, who must ultimately pay for these 31
requirements and investments, an exacerbating factor is our relatively stagnant load growth 32
due to relatively low increases in population and declining use-per-customer. This translates 33
into nearly flat revenues, which means that new capital investments must be covered by higher 34
customer rates. Historically, annual increases in customer loads produced new revenues that 35
were often sufficient to cover the costs for new investment and inflation without the need to 36

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Avista Corporation
increase rates. 1
Q. Please describe the Company’s process for ensuring it is making timely 2
investments in electric transmission to maintain compliance with mandatory federal 3
standards. 4
A. The Company’s process for determining which projects should be 5
recommended for funding each year includes results of comprehensive planning studies, 6
engineering and asset management analyses, and scheduled upgrades and replacements 7
identified in our operations districts and Transmission Engineering. These projects undergo 8
internal review by multiple stakeholders, who help ensure all system needs and alternatives 9
have been identified and evaluated. 10
Projects advanced for funding enter a formal review process referred to as the 11
“Engineering Roundtable” (ERT). This group carefully reviews the need for each project, the 12
primary business driver, the alternatives considered, and the justification for the approach 13
recommended. During the review, the potential benefits of any cross-business-unit synergies 14
that could better optimize project benefits and scope are also identified and evaluated. The 15
result of this process is a prioritized list of recommended projects that serves as a roadmap of 16
investments sequenced by year for at least a ten-year time horizon. Using this roadmap, each 17
department can plan ahead for the work they will be responsible to execute once projects are 18
approved for funding and implementation. Once evaluated, prioritized and sequenced, these 19
projects are recommended to the Capital Planning Group (as described in the testimony of Mr. 20
Thies) for final review and funding allocation. Representatives from eleven business units 21
participate in the ERT process. 22
Q. Would you please summarize the capital investments in electric 23
transmission plant completed in 2022 and planned for over the Two-Year Rate Plan? 24

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Avista Corporation
Investment Driver
Business Case Name 20221 2023 2024 20252
Mandatory and Compliance
Clearwater Wind Generation Interconnection 257$ -$ -$ -$
Colstrip Transmission 181 280 590 331
Generation Interconnection - 200 - 426
Protection System Upgrade for PRC-002 124 - - -
Saddle Mountain 230/115kV Station (New) Integration Project Phase 2 - 13,714 - -
Spokane Valley Transmission Reinforcement Project 65 - - -
Transmission Construction - Compliance 2,020 2,540 - -
Transmission NERC Low-Risk Priority Lines Mitigation 1,750 3,341 1,000 -
Tribal Permits & Settlements 668 400 400 267
Westside 230/115kV Station Brownfield Rebuild Project - - 7,054 -
Failed Plant and Operations
Electric Storm 1,358$ 1,560$ 1,560$ 1,040$
N Lewiston Autotransformer - Failed Plant 31 - - -
Asset Condition
SCADA - SOO and BuCC 741$ 700$ 700$ 224$
Substation - Station Rebuilds Program 1,480 29,611 14,325 4,464
Transmission - Minor Rebuild 1,567 5,416 3,343 646
Transmission Major Rebuild - Asset Condition 3 13,102 9,750 -
Performance & Capacity
Cabinet Gorge 230kV Add Bus Isolating Breakers -$ -$ -$ 1,700$
Substation - New Distribution Station Capacity Program - 3,585 163 1,101
Total Planned Electric Transmission Capital Projects 10,245$ 74,449$ 38,885$ 10,199$
(1) Includes system pro forma capital additions for the period of July 01, 2022 though December 31, 2022.
(2) Includes system pro forma capital additions for the period of January 01, 2025 though August 31, 2025.
Electric Transmission Capital Projects (System) In $(000's)
A. Yes, the completed and planned investments related to transmission 1
investment, presented on a system basis, and grouped by investment driver, are shown in Table 2
No. 3, and described below. 3
Table No. 3 – Electric Transmission Capital Projects (System) 4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
Clearwater Wind Generation Interconnection – 2022: $257,000 37
Avista is joint owner in the 500kV Colstrip Transmission System and party to the Colstrip 38
Project Transmission Agreement (“Agreement”) (Avista owns a 10.2% share in the Colstrip-39
Broadview segment and a 12.1% share in the Broadview-Townsend segment). Under rules of 40
the Federal Energy Regulatory Commission (“FERC”) and those in the Agreement, all joint 41
owners, including Avista, must comply with rules governing the interconnection of new 42
generation facilities with the Colstrip Transmission System. In accordance with those rules, 43

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Avista Corporation
Clearwater Energy Resources, LLC, requested interconnection of a 750MW wind project 1
known as the “Clearwater Wind Project.” All required studies have been completed and Avista 2
executed a Large Generator Interconnection Agreement with Clearwater Energy on May 22, 3
2019 (“LGIA”). Avista and the other joint owners are obligated to fund their respective shares 4
of the Transmission Provider Interconnection Facilities and Network Upgrades applicable to 5
the interconnection agreement. Avista’s allocation of the required construction cost was 6
originally estimated to be $650,600, the approved cost was subsequently reduced to $570,000. 7
The remaining cost of $257,000 is related to the construction of a 500 kV bay for the wind 8
generator and consisted primarily of apparatus wiring, system configurations, and final 9
conductor terminations. 10
11
Colstrip Transmission Operation and Maintenance – 2022: $181,000, 2023: $280,000, 12
2024: $590,000, 2025: $331,000 13
As noted in the business case just above, Avista is a joint owner in the 500kV Colstrip 14
Transmission System and is obligated under the Agreement to fund its commensurate share 15
of necessary construction and maintenance programs. Examples of recent and pending capital 16
expenditures in the Colstrip Transmission System include microwave communication 17
upgrades, replacement of original remedial action scheme, ballistic substation protection. 18
19
Generation Interconnection – 2023: $200,000, 2025: $426,000 20
Avista must provide for the interconnection of new generation resources with its Transmission 21
System under the terms and conditions of its Open Access Transmission Tariff (“Tariff”) 22
under the jurisdiction of the Federal Energy Regulatory Commission (“FERC”). In 23
compliance with federal statute, the terms and conditions of the Tariff, and FERC rules and 24
regulations, the Company must study, design and construct the necessary facilities (“Network 25
Upgrades”) to provide Interconnection Service to all eligible generation projects, regardless 26
of whether such generation is intended to serve bundled retail native load customers of Avista 27
or any third-party load. All aspects of the generation interconnection process, including 28
application, studies, evaluation of new or upgraded facilities, construction of new or upgraded 29
facilities, cost allocation of new or upgraded facilities, and repayment of advanced amounts 30
are prescribed by the Tariff and FERC rules and regulations. Failure by the Company to 31
provide design and construction funding for these projects would be: (i) an act of default under 32
the applicable Small Generator Interconnection Agreement (“SGIA”) or Large Generator 33
Interconnection Agreement (“LGIA”) for each project, and (ii) a violation of the Tariff and 34
FERC rules and regulations pursuant to which the Company could incur compliance penalties 35
of up to $1 million per day. 36
37
Protection System Upgrade for PRC-002 – 2022: $124,000 38
As noted in numerous previous places in my testimony, Avista is subject to a range of planning 39
and operating standards established by NERC, including the standard PRC-002, which 40
establishes disturbance monitoring and reporting requirements on our bulk electric 41
transmission system. Each year Avista evaluates every one of its electric transmission busses16 42

16 The transmission bus, or more technically ‘busbar’, is the heavy electrical conductor used in electric
substations that connect high voltage equipment, switch gear, low voltage equipment, etc. In evaluating power
flows on the electric transmission system, the bus refers to any graph node of a single-line diagram at which
voltage, current, power flow and other quantities are measured and evaluated. The NERC determination of what
portions of Avista’s electric transmission infrastructure (lines, circuits, substations, and individual busses and

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Avista Corporation
to determine our obligations under bulk electric system requirements and standards. The 1
subject standard mandates the Company have suitable protection systems to monitor and 2
record all electric disturbances occurring on each portion of our electric transmission system 3
that is within the bulk electric system. The protection systems must have the capability to 4
record electrical quantities for each element connected to every bus identified as being part of 5
the bulk electric system. 6
7
Saddle Mountain 230/115kV Station (New) Integration Project Phase 2 – 2023: 8
$13,714,000 9
The Company’s need to construct a new Saddle Mountain substation is described above in the 10
Distribution section of my testimony. Construction of the new substation, however, required 11
a range of other work to be completed in phases in order to integrate it into electric system. 12
The investments I refer to in this section of the project represent improvements to our electric 13
transmission system that are needed to effectively integrate the new Saddle Mountain 14
substation into our bulk transmission system. 15
16
Spokane Valley Transmission Reinforcement Project – 2022: $65,000 17
Load growth combined with our growing inability to meet certain NERC planning criteria, 18
required the Company to take steps over time to meet our load service and compliance 19
obligations. Initially, Avista developed operating procedures to help mitigate deficiencies in 20
this portion of our electric transmission system and has already completed system investments 21
as part of a long-term plan to meet our obligations. The remaining portions of this project 22
consist of constructing a new substation (Irvin substation) and rebuilding a portion of the 23
Beacon – Boulder #2 115 kV Transmission Line. These investments will complete the overall 24
reinforcement project, which will provide Avista the needed operational flexibility to 25
adequately serve our current and expected customer loads and meet our federal compliance 26
requirements. 27
28
Transmission Construction – Compliance – 2022: $2,020,000, 2023: $2,540,000 29
This program funds the transmission rebuild and reconductor work identified by the Company 30
as necessary to maintain compliance with NERC reliability standards.17 The applicable 31
standard requires Avista to complete an annual planning assessment, to identify shortfalls and 32
corrective actions, and for those actions to be timely implemented within specific timeframes 33
to remedy identified system performance deficiencies. Avista’s transmission construction - 34
compliance program identifies funding needed to mitigate identified reliability issues, 35
ensuring our compliance with NERC requirements. In addition to meeting NERC standards, 36
this program also includes construction to remedy issues on any transmission line that is not 37
compliant with the current capacity criteria under the National Electric Safety Code (NESC). 38
Avista is subject to substantial financial penalties for non-compliance with NERC standards, 39
and the risk of not meeting NESC minimum requirements. Given what is presently known 40
about NERC planning standards and requirements, in addition to current NESC requirements, 41

pieces of equipment) are part of the “bulk electric system” is based on analysis of our transmission system one-
line diagrams.
17NERC 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.

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Avista Corporation
this program is expected to complete in 2025. 1
2
Transmission – NERC Low-Risk Priority Lines Mitigation – 2022: $1,750,000, 2023: 3
$3,341,000, 2024: $1,000,000 4
Avista’s compliance with this mandatory standard requires that we conduct LiDAR surveys18 5
on all subject transmission circuits to determine any discrepancies between the design 6
specifications and field measurements for conductor sag.19 While the subject NERC standard 7
was offered as a recommendation to the industry, our compliance with minimum clearance 8
requirements is also required by the National Electric Safety Code. NERC, however, is also 9
closely monitoring the progress made by each utility in complying with these requirements, 10
via a required status report filed with them every six months by each subject utility. When 11
Avista identifies discrepancies through the surveys it evaluates a range of actions to be taken 12
to ensure we meet the stated clearance requirements. The actions include reconfiguring 13
insulator attachments, rebuilding or replacing structures and removing earth below the span 14
of line in question. 15
16
Tribal Permits and Settlements – 2022: $668,000, 2023: $400,000, 2024: $400,000, 2025: 17
$267,000 18
Similar to the business case just above, approximately 232 miles of the Company’s electric 19
transmission facilities are located on the reserved lands of neighboring Native American 20
Tribes. The capital costs in this business case fund easement agreements that require us to pay 21
fees and/or undertake other actions in order to occupy these trust lands. 22
23
Westside 230/115kV Station Rebuild – 2024: $7,054,000 24
The existing Westside #1 230/115 kV transformer exceeds its applicable facility rating for the 25
P1 event of the Westside #2 230/115 kV transformer. System performance analysis indicates 26
an inability of the system to meet the performance requirements in Table 1 of NERC TPL-27
001-4 in scenarios representing 2017 Heavy Summer for P1 events. Construction completed 28
to date has mitigated the P1 issues and the remaining work, to be completed by 2024 with 29
complete the performance requirements. 30
31
Electric Storm – 2022: $1,358,000, 2023: $1,560,000, 2024: $1,560,000, 2025: $1,040,000 32
Please see this program above (titled the same) under electric distribution plant for the 33
description of the Company’s investments under the category of electric storms. This capital 34
business case is similar in all respects to the program for electric distribution repair except it 35
is focused on repairs to our electric transmission system. 36
37
North Lewiston Autotransformer – 2022: $31,000 38
The North Lewiston 230/115 kV Transformer No. 1 (McGraw-Edison Serial Number C-39
06237-5-2) located in Lewiston, ID failed in February 2021. A replacement transformer was 40

18 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.
19 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.

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Avista Corporation
ordered and placed in service in June of 2022. The North Lewiston 230/115kV Transformer 1
1 provides the transformation capacity needed for the system to meet performance 2
requirements as defined by System Planning and System Operations. 3
The North Lewiston 230/115 kV Transformer No. 1 was 40 years old when it failed. Following 4
the failure, an investigation was performed with testing and an internal inspection. The 5
investigation concluded the transformer had a failed winding. The decision to replace the 6
230/115 kV Transformer No. 1 was made based on an evaluation of alternatives which also 7
included rebuilding the existing transformer and utilizing a spare transformer within Avista’s 8
system. 9
10
SCADA – System Operations Office & Backup Control Center – 2022: $741,000, 2023: 11
$700,000, 2024: $700,000, 2025: $224,000 12
The Company increasingly relies on comprehensive digital monitoring of critical power 13
system infrastructure and communication interconnectivity that provides real-time visibility, 14
status, alarms, and the ability for remote and automated operations. Avista relies on the 15
industry-standard system known as Supervisory Control and Data Acquisition (or SCADA) 16
to provide this functionality.20 The Company is required to continuously upgrade and enhance 17
its SCADA systems to replace end-of-life technology and to meet constantly expanding 18
regulatory requirements and the current and long-term needs of our business. This particular 19
project, the System Operations Office (SOO) and Backup Control Center (BuCC) is replacing 20
and upgrading existing SCADA communications for our electric and natural gas control 21
centers. Business groups who rely on these systems include Avista’s system operators, power 22
schedulers, distribution dispatchers, gas controllers, energy accounting and risk management, 23
Protection Engineering, Substation Engineering, Generation Engineering, Distribution 24
System Operations, Oracle database administration, Security Engineering, Network 25
Engineering and Network Operations. Additionally, organizations outside Avista who also 26
rely on these systems include the control centers of our neighboring electric and natural gas 27
utilities, and our regional reliability coordinator. The investments made in our SCADA 28
systems ensure we can continue to operate our energy delivery systems safely and remain in 29
compliance with a broad range of NERC standards and federal pipeline safety requirements 30
under PHMSA. The Company has included electric system offsets of $30,000 in 2023 in 31
Adjustment 3.12. 32
33
Substation – Station Rebuilds – 2022: $1,480,000, 2023: $29,611,000, 2024: $14,325,000, 34
2025: $4,464,000 35
Please see this program above (titled the same) under electric distribution plant for the 36
description of the Company’s investments under the category of station rebuilds. This capital 37
business case is the same in all respects to the program for electric distribution except it is 38
focused on the portion of substations dedicated to the electric transmission system. 39
40
Transmission Minor Rebuild – 2022: $1,567,000, 2023: $5,416,000, 2024: $3,343,000, 41
2025: $646,000 42
This program provides for the minor rebuild of electric transmission lines that are nearing the 43

20 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 22
Avista Corporation
end of their useful service life based on overall condition of the assets, and the rating for 1
likelihood of a failure and magnitude of the consequence. Factors such as operational issues, 2
ease of access during outages and potential benefits of communications build-out are also 3
considered in prioritizing the work to be completed in the planning horizon. The primary 4
alternative to this proactive inspection and replacement would be to replace poles, cross arms, 5
conductor, and other attached equipment upon failure. This alternative is not practical or 6
reasonable, however, since the consequences would be a greater overall cost to customers, an 7
increasing risk of large and lengthy service outages, much greater wildfire risk, and the 8
likelihood of penalties for non-compliance with NERC operating standards. The only way 9
Avista can properly maintain its service levels for customers and shield them from a range of 10
financial and other risks is to systematically rebuild end-of-life transmission facilities. 11
12
Transmission Major Rebuild - Asset Condition – 2022: $3,000, 2023: $13,102,000, 2024: 13
$9,750,000 14
This program provides for the major rebuild of electric transmission lines that are nearing the 15
end of their useful service life based on overall condition of the assets, and the rating for 16
probability of a failure and magnitude of the consequence. Factors such as operational issues, 17
ease of access during outages and potential benefits of communications build-out are also 18
considered in prioritizing the work to be completed in the planning horizon. The primary 19
alternative to this proactive inspection and replacement would be to replace poles, cross arms, 20
conductor, and other attached equipment upon failure. This alternative is not practical or 21
reasonable, however, since the consequences would be a greater overall cost to customers, an 22
increasing risk of large and lengthy service outages, much greater wildfire risk, and the 23
likelihood of penalties for non-compliance with NERC operating standards. The only way 24
Avista can properly maintain its service levels for customers and shield them from a range of 25
financial and other risks is to systematically rebuild end-of-life transmission facilities. 26
27
Cabinet Gorge 230kV Add Bus Isolation Breaker – 2025: $1,700,000 28
Transmission Operations has identified reliability issues with the existing 230 kV circuit 29
breaker arrangement at Cabinet substation. This is an ongoing issue since the last station 30
redesign in the late 1990’s. This project is comprised of installing two breakers to isolate the 31
230kV bus at Cabinet from the GSUs (Generation Step-Up transformers). Several times in the 32
last few years an issue with a GSU has caused an entire bus outage at Cabinet Gorge HED 33
which has limited generation output and caused several operational issues. These new 34
breakers will isolate future GSU issues to just that particular equipment without affecting the 35
whole bus. The deficiency of the current design is it is not selective enough and drops all 230 36
kV lines, the 230/115 kV autotransformer, and all Cabinet Gorge generation for issues with 37
the GSU’s. This project proposes a reliability upgrade to Cabinet substation consisting of a 38
new 230 kV breaker for each GSU, relocating (2) termination towers and adding new 230 kV 39
bus and GSU relay protection. 40
41
Substation – New Distribution Station Capacity Program – 2023: $3,585,000, 2024: 42
$163,000, 2025: $1,101,000 43
Please see this program above (titled the same) under electric distribution plant for the 44
description of the Company’s investments under the category of new distribution station 45
capacity. This capital business case is the same in all respects to the program for electric 46
distribution except it is focused on the portion of substations dedicated to the electric 47

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Avista Corporation
transmission system. 1
2
3
IV. INVESTMENTS IN THE COMPANY’S NATURAL GAS SYSTEM 4
Q. Please summarize the need for ongoing investment in Avista’s natural gas 5
distribution system. 6
A. Natural gas is a foundational energy resource for Avista’s customers. It plays 7
a critical role in our achievement of a clean energy future. It provides the clean fuel for 38% 8
of the nation’s electric generation fleet (and growing), heats more than half of America’s 9
homes, and provides the vital feedstock and energy for cooling, heating and industrial 10
processes, commerce, and industry. The Company has experienced steady growth in natural 11
gas customers in the prior decade where the annual number of new connects more than 12
doubled between 2010 and 2021. The increase in new customers has required continuing 13
investment in new connects, in addition to investments to provide the capacity requirements 14
needed to serve increasing loads. Another substantial driver for new investments is 15
maintaining compliance with federal and state regulatory requirements and effectively 16
managing the continuing safety risks associated with our natural gas distribution system. Over 17
the last decade, the Company’s investments to meet customer requests for new service and to 18
comply with a range of growing regulatory obligations has grown from approximately $15.5 19
million in 2010 to approximately $67 million in 2022. Avista’s allocation of capital 20
investment in its natural gas system for 2022 through 2025 is expected to range from 2% for 21
investments based on asset condition, 5% to meet performance and capacity needs, 9% to 22
provide for failed plant and operations, 45% to meet customer requests, and 39% for 23
mandatory and compliance requirements. 24
Q. Would you please summarize the capital investments in natural gas 25

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Avista Corporation
Investment Driver
Business Case Name 20221 2023 2024 20252
Customer Requested
New Revenue - Growth 22,693$ 34,362$ 33,859$ 16,124$
Mandatory and Compliance
Gas Above Grade Pipe Remediation Program 750$ 750$ 772$ 167$
Gas Cathodic Protection Program 733 715 715 -
Gas Facility Replacement Program (GFRP) Aldyl A Pipe Replacement 14,078 27,437 27,187 16,237
Gas Isolated Steel Replacement Program 522 850 850 577
Gas Overbuilt Pipe Replacement Program 264 400 412 -
Gas PMC Program 154 - 2,800 2,400
Gas Replacement Street and Highway Program 1,944 3,610 3,718 2,406
Gas Transient Voltage Mitigation Program 900 750 500 167
Failed Plant and Operations
Gas Non-Revenue Program 4,301$ 9,400$ 9,400$ 6,642$
Asset Condition
Gas ERT Replacement Program 238$ 348$ 225$ -$
Gas Regulator Station Replacement Program 621 1,077 1,077 951
Performance & Capacity
Gas Reinforcement Program 1,199$ 1,300$ 1,000$ 669$
Gas Telemetry Program 151 295 304 197
Gas Operator Qualification Compliance 203 27 - -
Jackson Prairie Natural Gas Storage Facility 1,203 2,370 2,422 1,607
Total Planned Natural Gas Distribution Capital Projects 49,954$ 83,691$ 85,241$ 48,144$
(1) Includes system pro forma capital additions for the period of July 01, 2022 though December 31, 2022.
(2) Includes system pro forma capital additions for the period of January 01, 2025 though August 31, 2025.
Natural Gas Distribution Capital Projects (System) In $(000's)
infrastructure completed in 2022 and planned for over the Two-Year Rate Plan? 1
A. Yes, the completed and planned investments related to natural gas 2
infrastructure, presented on a system basis and grouped by investment driver, are shown in 3
Table No. 4, and described below. 4
Table No. 4 – Natural Gas Capital Projects (System) 5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
Gas New Revenue Growth – 2022: $22,693,000, 2023: $34,362,000, 2024: $33,859,000, 33
2025: $16,124,000 34
Avista defines these investments as “customer requests for new service connections, line 35
extensions, transmission interconnections, or system reinforcements to serve a single large 36
customer.” We have often in the past referred to new service connects as “growth,” as in 37
growth in the number of customers, however, these investments are beyond the control of the 38
Company, and as such they do not reflect a plan or strategy on the part of Avista. Responding 39
quickly to these customer requests is a requirement of providing utility service. The New 40
Revenue – Growth Business Case is driven by requirements that mandate Avista’s obligation 41

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Avista Corporation
to serve new customer load when requested within our franchised area. Growth is also seen 1
as a method to spread costs over a wider customer base, keeping rate pressure lower than 2
would otherwise be experienced. The Company has included Idaho natural gas offsetting 3
revenues of $1,441,000 in Rate Year 1 in Adjustment 3.12 and offsetting revenues of $795,000 4
in Rate Year 2 in Adjustment 24.06. 5
6
Gas Above Grade Pipe Remediation Program – 2022: $750,000, 2023: $750,000, 2024: 7
$772,000, 2025: $167,000 8
Within Avista’s natural gas distribution system there are sections of gas pipelines that are 9
located above grade. Some of these sites are no longer compliant with current safety codes 10
and design practices, or the support structures are failing. Like other areas of the gas and 11
electric system, over the years construction practices have changed due to stricter standards 12
and improved construction methods. As a result, these above grade crossings have a variety 13
of construction techniques and supporting structures with varying degrees of risk associated 14
with each of them. This Business Case is intended to remediate the above grade natural gas 15
crossings. 16
17
Gas Cathodic Protection Program – 2022: $733,000, 2023: $715,000, 2024: $715,000 18
The purpose of the cathodic protection program is to provide an additional level of protection21 19
to the Company’s buried steel natural gas piping from the effects of natural corrosion. The 20
protection is provided by applying a low-voltage direct current to the subject pipe that creates 21
a corrosion free zone at the surface of the pipe. Providing cathodic protection for our steel 22
natural gas piping protects our customers and others from the potential consequence of leaks 23
on our system and helps ensure they also receive the full lifecycle value of the investments 24
made in our natural gas system by avoiding the need to prematurely replace the pipe due to 25
excessive corrosion. Besides a prudent business practice, Avista is mandated by the U.S. 26
Department of Transportation to provide effective cathodic protection for its steel natural gas 27
pipelines. The Company’s Cathodic Protection Group is responsible for the monitoring and 28
annual testing of our cathodic systems. The need for capital investments in our cathodic 29
protection systems is driven by the results of annual monitoring and testing. Because cathodic 30
systems can have variable service lives, depending on local soil conditions and the propensity 31
for corrosion, and because all the component parts are buried in the earth, the only way to 32
determine whether a system needs to be replaced is through annual performance monitoring. 33
It is often difficult to predict in advance when a specific replacement will be required so the 34
amount of replacement work experienced each year across our system can be somewhat 35
variable. Therefore, the annual funding for this program in future years is based on Avista’s 36
experience in prior years. 37
38
Gas Facility Replacement Program (GFRP) Aldyl A Pipe Replacement – 2022: 39
$14,078,000, 2023: $27,437,000, 2024: $27,187,000, 2025: $16,237,000 40
The Aldyl A Pipe Replacement Program22 is a 20-year structured pipe replacement effort with 41

21 This is in addition to providing proper protective coatings to the steel pipe. These provide the primary
protection and the cathodic system serves to protect the pipe if the coating deteriorates or is damaged.
22 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.

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Avista Corporation
dedicated internal and external resources focused on reducing natural gas system risk, on a 1
prioritized basis, by replacing priority Aldyl A pipe throughout Avista’s natural gas 2
distribution system. The program was initiated in 2011 and is slated to be completed by year 3
2032.23 The primary alternative to this proactive replacement program was to simply replace 4
sections of the subject pipe as it failed in service over time. The Company’s asset management 5
analysis, however, revealed that this approach would eventually lead to a failure rate and 6
consequences that would be unacceptable to Avista, our customers, the general public, and 7
regulators.24 The question, then, was to determine the time horizon over which a replacement 8
program should be conducted. The analysis showed that a replacement interval in the range 9
of 25 to 30 years would likely still result in an unacceptable increase in the number of annual 10
leaks, while an interval in the range of 10 to 15 years would result in substantially greater cost 11
pressure on customers, exacerbate the complexities and demands of the project, and fail to 12
produce enough of a reduction in annual leaks to overcome these burdens. A time interval in 13
the range of 20 years was determined to be optimal. The Company has continued to re-14
evaluate the analysis since the initial work was completed, which has confirmed Avista’s 15
approach and timeline for managing this issue. I have provided the most recent report updating 16
this analysis, conducted in 2022, as Exhibit No. 9, Schedule 2. Replacing this pipe in our 17
system in the manner undertaken will help the Company shield our customers from this 18
unreasonable risk and minimize, optimize and levelize the costs they pay for the work to be 19
done. 20
21
Gas Isolated Steel Replacement Program – 2022: $522,000, 2023: $850,000, 2024: 22
$850,000, 2025: $577,000 23
Related to my description of our cathodic protection systems above, the Company is required 24
to identify portions of its natural gas system where we have “cathodically isolated” sections 25
of steel piping, including natural gas service risers, and to replace them with non-corrosive 26
pipe within a specified timeframe. Isolated steel sections are just that, they are electrically 27
separated from the cathodic protection system by sections of non-corrosive (plastic) pipe. 28
Because these sections are not connected to the cathodic protection system, they are not 29
afforded the extra level of protection beyond their protective coating. Replacing isolated steel 30
sections protects our customers and others from the potential consequence of leaks on our 31
system and helps ensure customers also receive the full lifecycle value of the investments 32
made by avoiding the need to prematurely replace pipe due to excessive corrosion. Identifying 33
and replacing isolated steel sections of pipe is required by federal regulations and by 34
agreement for our system in Washington. The need for capital investments in our isolated steel 35
replacement program is driven by the results of our annual surveys of the system and the 36
amount of piping that needs to be replaced each year. It can be difficult to predict in advance 37
the amount of replacements that will be required each year so the annual funding for this 38
program in future years is based on Avista’s recent historic experience. The Company has 39

23 For a detailed description of this program, please see Avista’s Priority Aldyl A Protocol Report, provided as
Exhibit No. 9, Schedule 1.
24 As described in Exhibit No. 9, Schedule 1, in February 2012 Avista’s Asset Management Group released its
findings in the report titled “Avista’s Proposed Protocol for Managing Select Aldyl A Pipe in Avista Utility’s
Natural Gas System.” 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 Washington, Oregon, and Idaho.

DiLuciano 27
Avista Corporation
included an Idaho natural gas O&M offset of $5,000 in 2023 in Adjustments 3.12. 1
2
Gas Overbuilt Pipe Replacement Program – 2022: $264,000, 2023: $400,000, 2024: 3
$412,000 4
As a natural gas distribution system operator, Avista is required to operate within the 5
minimum safety standards outlined in Part 192 of the Department of Transportation's Code of 6
Federal Regulations (CFR). These regulations define the laws that all operators must legally 7
comply with in the operation of natural gas distribution systems. There are sections of existing 8
gas piping within Avista's gas distribution system that have experienced encroachment or have 9
been overbuilt by customer-constructed improvements (e.g. living structures, sheds, decks, 10
etc.) and were not designed for these conditions. Overbuilt facilities restrict company access 11
to the pipe resulting in accessibility issues that interfere with our ability to perform certain 12
maintenance activities required by the federal regulations, such as meter inspections or leak 13
survey. These encroachments also impair our ability to safely operate and maintain these 14
facilities, which can become impossible if access to the ground above the piping is restricted. 15
More importantly, overbuilds present an increased risk to customers due to the threat that 16
leaking gas may be trapped inside a structure, increasing the possibility of potentially 17
catastrophic accidents. Unless our system was originally designed to be overbuilt these 18
situations represent a violation of the federal regulations. 19
20
Gas PMC Program – 2022: $154,000, 2024: $2,800,000, 2025: $2,400,000 21
Avista is required by Commission rules and tariffs in its three state jurisdictions to annually 22
test a portion of its natural gas meters for accuracy and to ensure overall meter performance. 23
This program is known as the Planned Meter Changeout Program (PMC) and uses a statistical 24
sampling methodology25 to determine the number of meters changeouts that must be 25
completed each year. If samples from a meter “family” are not meeting accuracy standards, 26
then the Company will remove that population of meters from service. Conversely, if the 27
results meet our standards of accuracy then the sample size in the future for that meter family 28
may be reduced. These analytics help control costs and remove meters quickly when not 29
performing well. Ensuring the accuracy and overall performance of our natural gas meters is 30
in the interest of all customers and helps us minimize the overall cost of maintaining a high 31
standard of service. The annual volume of periodic meter changeouts is driven by the 32
determination of sample sizes, as noted above, so there is some year-to-year variability in 33
spending due to the natural change in number of units replaced each year. The Company has 34
included an Idaho natural gas O&M offset of $38,000 in 2023 in Adjustment 3.12. 35
36
Gas Replacement Street and Highway Program – 2022: $1,944,000, 2023: $3,610,000, 37
2024: $3,718,000, 2025: $2,406,000 38
Nearly all Avista’s natural gas pipelines are located in public utility easements set aside for 39
this purpose, which are controlled by jurisdictional franchise agreements. Avista is required 40
under these agreements to relocate its facilities, at our cost, when local jurisdictional projects, 41
typically transportation, require the move. Avista relies on its natural gas infrastructure to 42
provide service to its customers and uses public utility easements as a cost-effective way to 43
reduce the costs of placing new infrastructure into service. In cases where we must relocate 44
our facilities, even though there is a new incremental cost for doing so, it still represents the 45

25 ANSI Z1.9 “Sampling Procedures and Tables for Inspection by Variables for Percent Nonconforming.”

DiLuciano 28
Avista Corporation
least-cost approach for continuing to provide reliable and affordable natural gas service. In 1
some instances, the Company will have a substantial lead time to plan for, budget, design and 2
permit for the move, but in most cases, we’re notified of the need to move during the year the 3
jurisdictional project must be completed. Because these jurisdictional projects are outside 4
Avista’s control, and because it’s impossible to forecast the year-to-year costs, this program 5
and its ultimate costs are subject to considerable variability. There is no alternative to this 6
program since the Company is required to move its facilities, within a specified time frame, 7
when notified by local jurisdictions pursuant to our franchise agreements. Within each project, 8
however, there are sometimes opportunities to evaluate alternative ways to continue providing 9
service, and the Company always looks for opportunities to leverage these projects to capture 10
other system benefits. 11
12
Gas Transient Voltage Mitigation Program – 2022: $900,000, 2023: $750,000, 2024: 13
$500,000, 2025: $167,000 14
Avista has experienced safety issues including fires at Regulator Stations due to transient 15
voltage spikes from faults on the adjacent electric transmission system. The purpose of this 16
program will be to identify high pressure gas piping systems that are at risk of these conditions, 17
identify systems that have high steady state voltage, and to then install mitigation measures to 18
reduce both these scenarios on the pipelines. These efforts will protect the pipeline and 19
equipment from being damaged and reduce the voltages exposure to below compliance limits 20
keeping our employees safe. Common approaches to this include the installation of gradient 21
mats, solid state decouplers (SSD), and copper counterpoise conductor. The Company has 22
included an Idaho natural gas O&M offset of $8,000 in 2023 in Adjustment 3.12. 23
24
Gas Non-Revenue Program – 2022: $4,301,000, 2023: $9,400,000, 2024: $9,400,000, 25
2025: $6,642,000 26
This annual program, which is under the Company’s Failed Plant and Operations capital 27
investment driver, includes investments to replace obsolete facilities, pipe and equipment at 28
the end of their useful life or that have failed, equipment and/or technology to enhance gas 29
system operation and/or maintenance, projects to improve public safety, and improvements 30
ancillary to customer requested work.26 These investments, while necessary for safe and 31
reliable operation of our system, are not part of our programs to fund new customer connects, 32
increase performance or capacity, or make systematic replacements based on asset condition. 33
Like the electric distribution minor rebuild program I described earlier in my testimony, there 34
is no traditional alternative to the work completed under this program since it consists of 35
many, small unplanned projects across the entire natural gas distribution system. These small, 36
unplanned projects are responsive to a range of factors generally beyond the control of the 37
Company. Examples include ancillary work required by customer-requested service,27 repair 38
of damage from a dig-in of our facilities, investments needed relocate facilities, repair of leaks, 39
deepening pipeline sections that are too shallow, remediating failed, under-sized or unsafe 40

26 Work requested by customers is generally, by tariff, performed at the customer’s expense. Under certain
circumstances, however, Avista may choose to perform additional work needed on the system not related to the
customer’s request. An example is to replace an existing steel service with polyethylene pipe to eliminate the
possibility of future deficiencies in cathodic protection and to reduce future maintenance related to that steel
service. The cost of this conversion is assigned to this Program.
27 These investments include work required to properly maintain the system, but that are not reasonably covered
by the tariffed financial contribution required of the customer.

DiLuciano 29
Avista Corporation
equipment, and correcting overbuild issues. There are instances among the small rebuild 1
projects where limited alternatives are evaluated in the design phase by the individual project 2
designer. In general, however, there is no reasonable alternative to timely making these 3
investments once the need has been identified. 4
5
Gas ERT Replacement Program – 2022: $238,000, 2023: $348,000, 2024: $225,000 6
An Encoder Receiver Transmitter (ERT) is an electro-mechanical device that allows gas 7
meters to be read remotely. These ERTs are powered by lithium batteries, which discharge 8
over time and must eventually be replaced. Most of the gas meters in Washington, Idaho, 9
and Oregon have ERT modules. The large quantity of ERT installations will result in an 10
unmanageable quantity of battery failures in the future if the ERT is not replaced at an 11
optimized frequency. When batteries fail, the customer’s usage is estimated and entered into 12
the billing system manually. This manual process causes a high chance of customer 13
dissatisfaction because of potential billing errors associated with bill estimation. Customers 14
often express their dissatisfaction through commission complaints when this happens. In 15
Idaho the ERTs will likely be changed out in mass when the AMI project starts in 2024, 16
however it is estimated that up to 30,000 40G ERT modules may have a battery failure in 17
2022 and 2023 due to their age. These 40G ERT modules may be replaced to avoid battery 18
failure and billing issues before the AMI project is implemented. 19
20
Gas Regulator Station Replacement Program – 2022: $621,000, 2023: $1,077,000, 2024: 21
$1,077,000, 2025: $951,000 22
This program addresses needed replacements of existing ‘at-risk’ natural gas gate stations, 23
regulator stations and industrial customer meter sets (“stations”) located across Avista’s 24
natural gas service territory. These stations to be replaced have reached the end of their useful 25
service life, fail to meet the Company’s current natural gas standards, and can no longer be 26
properly maintained because of obsolete equipment. These replacements improve system 27
operating performance, enhance operating safety, remove operating equipment that is no 28
longer supported (obsolescence), and ensure the reliable operation of metering and regulating 29
equipment. There are no practical alternatives to providing for the compliant, safe and reliable 30
operation of our natural gas stations. As a hypothetical, the Company did consider the option 31
of responding to station needs only when equipment failed in service, however, this approach 32
would expose our customers to greater risk, would expose Avista to compliance violations 33
and financial penalties for failure to properly maintain station equipment, and would cost our 34
customers substantially more than the cost associated with our current proper lifecycle 35
management. Our Gas Engineering department also considered the options of not replacing 36
end-of-life stations, but only replacing obsolete and failed components. This option would 37
result in higher lifecycle costs for our stations because we would be making many more 38
service calls to each station, and eventually, would be required to replace an increasing 39
number of stations on a crisis basis each year as the backlog of required work became 40
unsustainable. This option, too, would drive up the lifecycle cost of our stations, result in an 41
increasing service and regulatory risk, and would increase our customers’ cost of natural gas 42
service. The Company has included an Idaho natural gas O&M offset of $3,500 in 2023 in 43
Adjustment 3.12. 44
45
Gas Reinforcement Program – 2022: $1,199,000, 2023: $1,300,000, 2024: $1,000,000, 46
2025: $669,000 47

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Avista Corporation
Avista systematically monitors and models natural gas operating pressures throughout our 1
system in an ongoing effort to ensure we have the capacity needed to serve our firm customer 2
loads on our coldest expected winter “design days.” Areas identified as having insufficient 3
capacity to meet design day requirements are prioritized based on the severity of the risk 4
associated with the potential inability to serve firm loads. Investments made under this 5
program provide supply reinforcement to these capacity-constrained areas. There is no 6
alternative to providing for the capacity needs of our firm natural gas customers who rely on 7
Avista to ensure they have the supply needed to heat their homes and businesses and supply a 8
range of industrial needs, most especially during extreme weather conditions. The natural gas 9
reinforcement program helps ensure the Company meets this need, and to deliver an adequate 10
supply at the most reasonable cost. 11
12
Gas Telemetry Program – 2022: $151,000, 2023: $295,000, 2024: $304,000, 2025: 13
$197,000 14
Avista's commitment to safety and reliability dictates we monitor our gas system to ensure its 15
safe and reliable operation and to accurately meter and account for natural gas purchased and 16
sold. In addition to sound business practices, this monitoring is required by federal and state 17
rules for “Natural Gas Control Room Management.” Telemetry provides the visibility and 18
data needed to pro-actively detect abnormal operating conditions - before they can become 19
major problems that could impact safety or natural gas delivery. Additionally, telemetry is 20
used to remotely monitor system pressures, volumes, and flows from areas of special interest 21
such as gate stations, supply to natural gas transportation customers, regulator stations, select 22
large industrial customers, and end of line pressures. Alarm set points in field instruments 23
such as flow computers, electronic volume correctors, and electronic pressure monitors are 24
used to alert the Gas Control Room of abnormal operating conditions such as low or high 25
pressure, high flow, or high or low gas temperatures that could indicate problems with gas 26
heaters at gate stations or sensing equipment failures. By proactively monitoring these sites, 27
Avista can dispatch field personnel during normal business hours instead of responding to a 28
conventional alarm that could occur at any time. Telemetry also allows us to identify low 29
pressure on the system and to take quick action to avoid our customers potentially losing their 30
natural gas service. Additionally, data from these telemetry sites is used to validate the system 31
modeling tool used by our Natural Gas Planning group. 32
33
Gas Operator Qualification Compliance – 2022: $203,000, 2023: $27,000 34
Similar to the apprenticeship training I described just above, as an operator of natural gas 35
infrastructure, Avista Utilities is required by federal regulation to minimize safety and 36
integrity risks that could result from an employee’s lack of knowledge, skills, or abilities 37
during the performance of required activities and tasks. Craft Training and Gas Operations are 38
responsible for ensuring we can field a qualified and competent workforce, accomplished by 39
evaluating and qualifying internal and contract employees on Operator Qualification tasks 40
specific to Avista’s natural gas infrastructure. The capital investments in this business case 41
provide the tools, vehicles, and equipment necessary to meet the PHMSA regulations for 42
Operator Qualification. The alternative of not providing the resources to support the 43
qualification is not viable and would ultimately result in regulatory penalties and the potential 44
for incidents impacting Avista’s employees, customers and the public. These investments 45
support Avista’s natural gas operations in Idaho, Washington and Oregon. 46
47

DiLuciano 31
Avista Corporation
Jackson Prairie Joint Project – 2022: $1,203,000, 2023: $2,370,000, 2024: $2,422,000, 1
2025: $1,607,000 2
Avista is a one-third joint owner in the Jackson Prairie Natural Gas Storage Project and has 3
long relied on this asset to optimize gas prices and supply for the benefit of its customers. As 4
one example of the benefit of this asset, over the natural gas procurement year of 2016-2017, 5
the storage optimization provided by Jackson Prairie saved our natural gas customers over 6
$20 million. Like any asset, investments must be made in the facility each year to ensure the 7
integrity of its safe, efficient, and cost-effective operation. Avista participates with its joint 8
owners to identify and vet upcoming capital needs and to approve annual investments to be 9
made. Company witness Mr. Kinney provides further information regarding Avista’s 10
ownership in Jackson Prairie. The Company periodically evaluates the practicality of 11
acquiring alternative natural gas storage capacity that includes leased pipeline capacity and 12
storage for replacing the Jackson Prairie and the option of constructing a new stand-alone 13
compressed natural gas storage facility. Both the leasing of natural gas pipeline capacity and 14
leased storage capacity would provide only part of the flexibility provided by Jackson Prairie 15
and at a much greater cost. The alternative of constructing a new compressed natural gas 16
facility is very cost prohibitive. Maintaining Avista’s ownership in Jackson Prairie, including 17
investments to maintain the integrity and safe operation of the facility, provides our customers 18
the least cost solution to meeting our natural gas storage needs. 19
20
IV. INVESTMENTS IN THE COMPANY’S OPERATIONS, FACILITIES AND 21
FLEET RESOURCES 22
23
Q. Please summarize the need for ongoing investment in Avista’s operations, 24
facilities and fleet resources. 25
A. Adequate operating facilities are a critical ingredient to the success of all 26
organizations, especially those like Avista that are office facility, information technology, 27
heavy asset and field-operations intensive. Our fleet infrastructure includes a wide range of 28
light to heavy trucks specialized for electric and natural gas operations, diverse and specialized 29
equipment, all manner of tools, and extensive material and supply storage areas. Though it is 30
easy to take for granted, our office and operations facilities are at the heart of our ability to 31
serve customers effectively and efficiently. In addition to employees supporting our field 32
operations, our facilities are required to support a broad range of technical and administrative 33
staff, including accountants, engineers, attorneys, customer service representatives, and 34

DiLuciano 32
Avista Corporation
information technology experts. Besides the facilities themselves, our operations depend on 1
extensive information technology infrastructure, diverse and stand-alone communication 2
networks, and myriad other support systems. 3
As would be expected for a Company that has been in business over 132 years, many 4
of our facilities have been kept in operation well beyond their useful service life. A few 5
remaining structures were built in our early years of service, while many, like our energy 6
delivery infrastructure, were built during the economic expansion of the 1950s, placing them 7
now in the range of 60 to 70+ years old. Common sense and good stewardship require caring 8
for old buildings that need increasing levels of maintenance or retrofits to keep them 9
serviceable. Even so, over the years many of these facilities became inadequate to meet the 10
Company’s growing needs given their age and condition and the increasing levels of 11
maintenance required to keep them serviceable. To better extend their life, these facilities were 12
often upgraded and updated to meet contemporary operating requirements, which included a 13
steady increase in the number of customers served, the growing regulatory and technology 14
complexity in our business, and the need to care for aging infrastructure, to name a few. 15
These same factors also contributed to the need for more employees and workspace, 16
supporting infrastructure and related equipment. Both traditional and modern building layouts 17
will need essential modifications to adapt to the social norms brought on by COVID-19. There 18
will be renewed vigor around installing contactless technological solutions to reduce the 19
opportunity for disease transmission. The increase of hybrid and remote work, normalization 20
of video conferencing and virtual conferences and events necessitate technology and office 21
improvements to meet the needs of these functions. The increase in remote work will drive 22
the need for increased cybersecurity requiring added effort around remote devices, equipment, 23
and tools. Trucks and vehicles also increased in size and complexity over time requiring larger 24

DiLuciano 33
Avista Corporation
service space and specialized maintenance requirements. To meet these demands, older 1
facilities were continuously upgraded, expanded, remodeled and extensively repaired to keep 2
them minimally serviceable. These efforts helped the Company reach the point where we 3
could embark on a comprehensive planning initiative focused on replacing a wide range of 4
facilities well beyond their useful service life, and their cost-effective capability to be further 5
adapted to the future. Over the prior 15 years Avista has been systematically replacing 6
facilities that were simply inadequate to meet the Company’s current and future needs. 7
In addition to replacing end-of-life facilities, we have also reorganized our business to 8
improve the service we provide our customers by responding more quickly to outages and 9
equipment failures. We have accomplished this by locating stocks and supplies in closer 10
proximity to crews and the geographic areas they will be used and storing parts and equipment 11
in more organized and efficient spaces for quick access. The Company goes through 12
systematic procedures and protocols to determine how to best manage its facilities as well as 13
determining when they should be replaced. Part of this evaluation includes industry best 14
practices by national organizations that specialize in this area, including Building Owners and 15
Managers Association (BOMA) and the International Facility Management Association 16
(IFMA). These investments are needed not only to keep up with current service requirements, 17
but they also save money for our customers by lowering the overall cost of service over the 18
long term. 19
Q. Would you please summarize the capital investments in general plant, 20
fleet and facilities resources completed in 2022 and planned for over the Two-Year Rate 21
Plan? 22
A. Yes, the completed and planned investments related to general plant, fleet and 23
facilities resources, presented on a system basis and grouped by investment driver, are shown 24

DiLuciano 34
Avista Corporation
Investment Driver
Business Case Name 20221 2023 2024 20252
Mandatory and Compliance
Apprentice/Craft Training 52$ -$ -$ -$
Saddle Mountain 230/115kV Station (New) Integration Project Phase 2 - 950 - -
Asset Condition
Capital Equipment Program 1,457$ 2,069$ 2,074$ 1,386$
Fleet Services Capital Plan 5,588 6,185 5,623 3,749
Oil Storage Improvements - 1,642 - -
Structures and Improvements/Furniture 2,708 5,468 3,582 2,835
Substation - Station Rebuilds Program 1,860 1,689 1,178 1,515
Telematics 2025 501 808 200 133
Performance & Capacity
Substation - New Distribution Station Capacity Program 600$ 662$ 791$ 469$
Total Planned General Plant & Fleet Investment Capital Projects 12,766$ 19,473$ 13,448$ 10,087$
(1) Includes system pro forma capital additions for the period of July 01, 2022 though December 31, 2022.
(2) Includes system pro forma capital additions for the period of January 01, 2025 though August 31, 2025.
General Plant & Fleet Investments Capital Projects (System) In $(000's)
in Table No. 5, and described below. 1
Table No. 5 – General Plant Capital Projects (System) 2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Apprentice Craft Training – 2022: $52,000 24
Avista manages 11 Federally regulated apprenticeships that require instructional aides and 25
equipment deemed necessary to provide quality instruction.28 The Company’s Joint 26
Apprenticeship Training Committee (JATC) administers these apprenticeships and capital 27
funds are used to purchase tools, materials and equipment for training apprentices and journey 28
workers in all crafts. The trained and competent workforce produced through the various 29
apprenticeships benefit customers in all aspects of our service across all Avista service 30
territories. Support of apprenticeship training at Avista through this capital program aligns 31
with Avista’s mission and focus areas, allowing us to deliver innovative energy solutions 32
safely, responsibly, and affordably. Absent this capital funding, Avista would lack the ability 33
to train craft workers, likely resulting in our inability to fill many critical positions in crafts 34
ranging from meter and SCADA technicians, generation mechanics and electricians, natural 35
gas pressure control and service personnel and microwave and radio communications systems, 36
to name just a few of our many specialized and highly-trained positions. Our inability to train 37
craft employees would also add significant cost to our business as we would be forced to pay 38
premium labor costs in order to attract employees trained and employed at other utilities and 39
to outsource the specialized training required to maintain our many skillsets. This is not a 40
viable alternative for cost-effectively, safely and efficiently serving the needs of our 41
customers. 42
43
Saddle Mountain 230/115kV Station (New) Integration Project Phase 2 – 2023: $950,000 44

28 Regulated by 29 CFR 29 & 30.

DiLuciano 35
Avista Corporation
The Company’s need to construct a new Saddle Mountain substation is described above in the 1
Distribution section of my testimony. Construction of the new substation, however, required 2
a range of other work to be completed in phases in order to integrate it into electric system. 3
The investments I refer to in this section of the project represent improvements to the 4
communication equipment (SCADA backhaul) in order to monitor (i.e., review telemetry), 5
operate, and control the status of the equipment. 6
7
Capital Equipment Program – 2022: $1,457,000, 2023: $2,069,000, 2024: $2,074,000, 8
2025: $1,386,000 9
This program funds the tools and equipment needed by our employees to perform new 10
construction, conduct system monitoring, ensure system integrity, and the repair and 11
maintenance of our facilities safely and efficiently. This equipment, which needs to be in 12
adequate supply and fully available for both planned work and emergency response, supports 13
the work of our electric, natural gas, communications, fleet, facilities and generation crews 14
and infrastructure. There are no alternatives to having the specialized tools required to perform 15
the work of providing safe, reliable and affordable service to our customers. The Company, 16
does, however, promote the continuous improvement process of always exploring more 17
efficient and cost-effective ways of performing our work, including its application to the tools 18
and equipment necessary for the tasks. 19
20
Fleet Services Capital Plan – 2022: $5,588,000, 2023: $6,185,000, 2024: $5,623,000, 2025: 21
$3,749,000 22
Fleet vehicles and equipment simply do not age well, as they are subject to a duty cycle that 23
most vehicle owners would not imagine for their personal car or truck. Avista’s fleet of 24
vehicles operate in environments that are often at the extreme; the hottest or the coldest, the 25
dustiest, constant in and out, starting and stopping, high idle time and high loads. These factors 26
lead to substantial wear and tear on our vehicles, even under our prudent and proper use, which 27
over time leads to substantial maintenance and repair costs, and reduced availability and 28
reliability. The Company’s fleet replacement program optimizes the life of each vehicle 29
allowing us to extract the right amount of useful value from our vehicles before they 30
experience an accelerating rate of repair expenses. The investments made under this plan 31
represent the annual investments needed to replace a portion of our service fleet each year 32
based on asset condition (replacement at end-of-life). Avista’s fleet group uses industry best 33
practices, data, and a proprietary, third-party asset management system29 to identify when to 34
replace equipment in order to achieve the lowest total cost of ownership for our customers. 35
The analysis is based on the initial cost of each fleet unit, actual maintenance and repair costs, 36
depreciation expense and salvage/resale value to establish the lowest lifecycle cost for each 37
class of vehicle in the Company’s fleet. In addition to achieving the lowest cost for customers, 38
this strategy allows our fleet services group to achieve an equipment reliability/availability of 39
96%. Having equipment that is available when needed allows Avista to provide efficient, 40
timely and cost-effective service to our customers. 41
42
In the absence of good data and analytics, it can be tempting to keep equipment in service 43
beyond its optimum service life. After all, the equipment can appear to be in relatively good 44

29 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 36
Avista Corporation
shape, and the repair and maintenance costs may not yet have begun to accelerate. In years 1
past, Avista, like many organizations, did not have access to good data and analytical tools 2
for determining the optimum replacement strategy. And we often kept equipment in service 3
because it represented the lowest incremental cost for operating ‘the next day.’ Once the 4
Company had better access to good data and analytics, and the asset management culture and 5
focus on lifecycle cost management, we became better at recognizing the value of replacing 6
fleet assets based on condition and developing the capital budgets needed to support that 7
philosophy and practice. The optimized lifecycle cost strategy employed by the Company 8
ensures we’re investing the right amount of capital at the right time to achieve the lowest cost 9
of service for our customers. 10
11
Oil Storage Improvements – 2023: $1,642,000 12
Historically, Avista operated several oil storage tanks contained in an underground vault on 13
the Mission campus. These tanks, which were interconnected with several facilities by 14
underground piping and pumps, contained new oil products, used, but still viable oil, and spent 15
scrap oil, all related to our substation maintenance and electric distribution operations. Over 16
time, the Company experienced spill incidents and leaks in this underground system, and in 17
2014, we installed two new above-ground scrap oil storage tanks as part of a new Waste and 18
Asset Recovery building. Installation of the new above ground tanks allowed the Company to 19
decommission two of the tanks in the underground vault, however, four of the underground 20
tanks and their associated piping still remain in service. As noted above, this underground 21
infrastructure poses a continuing risk of undetected leaks, in addition to access issues that 22
have compounded as we have redeveloped the Mission campus. The vault itself similarly 23
limits use of the area for other purposes. Finally, the vault has been infiltrated by water and 24
maintenance costs to ensure the vault provides proper containment are increasing. The 25
selected alternative to eliminate the risks and issues related to the underground vault, tanks 26
and piping is to build two additional oil storage tanks above ground adjacent to the new above-27
ground tanks, accompanied by several smaller ‘day containers’ located in the electric shop. 28
29
Structures and Improvements/Furniture – 2022: $2,708,000, 2023: $5,468,000, 2024: 30
$3,582,000, 2025: $2,835,000 31
These investments fund the capital maintenance, site improvement, security, and related needs 32
for the Company’s 40 building facilities providing office space, operations, storage, and other 33
core business functions. The capital maintenance projects include roofing, siding, asphalt, 34
electrical and plumbing work, remodeling, furniture replacements and new furniture for 35
replacements and growth in operations. Approximately half the investments fund asset 36
replacements based on end-of-life condition and the Company’s facilities management group 37
uses a specialized application to help determine the optimum timing for these replacements. 38
Approximately 30% of the annual funding supports immediate needs identified by the Avista 39
work groups with responsibility for each facility, and the remainder funds emergent needs that 40
could not be anticipated in the planning process. The level of funding approved to meet these 41
needs in prior years has only been adequate to address the highest priority projects, which has 42
required the facilities group to keep beyond end-of-life assets in service in a manner to 43
minimize the impact on overall lifecycle cost. The primary alternative to making these 44
investments is to keep end-of-life assets in service and to perform emergency repairs and 45
replacements as components fail. This is similar to the alternative described above for fleet 46
services where it is possible to keep beyond end-of-life assets in service with the consequence 47

DiLuciano 37
Avista Corporation
of building a ‘bow wave’ of deferred investment that must be addressed in the future, while 1
driving higher long-term lifecycle costs for our customers. Another alternative would be to 2
fully fund this program to replace all assets at end of life and meet all other identified business 3
needs. The selected alternative is to fund only the highest priority needs, which allows the 4
Company’s Capital Planning Group to allocate funding to other highest-priority projects that 5
have greater risk if not adequately funded. This approach, as noted above, requires Avista’s 6
facilities group manage the backlog of unfunded needs in a way that minimizes the long-term 7
lifecycle cost impact to our customers. The Company has included system offsets of $11,000 8
in 2023 in Adjustment 3.12. 9
10
Substation – Station Rebuilds – 2022: $1,860,000, 2023: $1,689,000, 2024: $1,178,000, 11
2025: $1,515,000 12
Please see this program above (titled the same) under electric distribution plant for the 13
description of the Company’s investments under the category of station rebuilds. Construction 14
of new substations requires a range of other work to be completed in order to integrate it into 15
the electric system. The investments referred to in this section represent improvements to the 16
communication equipment (SCADA backhaul) in order to monitor (i.e., review telemetry), 17
operate, and control the status of the equipment. 18
19
Telematics 2025 – 2022: $501,000, 2023: $808,000, 2024: $200,000, 2025: $133,000 20
Since 2012, Avista has used Zonar30 telematics systems to track and record key operational 21
data on the Company’s fleet vehicles.31 The first generation of telematics was implemented to 22
streamline, track and administer the state and federally required inspections of trucks and 23
mounted equipment, which proved to be very successful for the Company. Our current 24
provider has notified the Company that the scheduled shutdown of AT&T 3G networks in 25
February 2022, which are used to interconnect our vehicle-mounted devices, will render them 26
no longer usable. In planning for the replacement of our current system Avista is considering 27
moving to a contemporary cloud-platform application that will integrate geographic location 28
data to improve our operations efficiency or provide our customers more-accurate information 29
about our response to their service needs, among other uses. In the future, the Company plans 30
to further leverage vehicle location and other data to provide coaching to drivers as well as 31
collecting and analyzing leading indicators on decisions fleet drivers are making in the field. 32
Selection and implementation of a new telematics system must begin in 2021 to provide ample 33
time before the planned 3G network retirement. The Company has included system offsets of 34
$42,555 in 2023 in Adjustment 3.12. 35
36
Substation – New Distribution Station Capacity Program – 2022: $600,000, 2023: 37
$662,000, 2024: $791,000, 2025: $469,000 38
Please see this program above (titled the same) under electric distribution plant for the 39
description of the Company’s investments under the category of new distribution substation 40
capacity. Construction of new substations requires a range of other work to be completed in 41
order to integrate it into the electric system. The investments I refer to in this section represent 42
improvements to the communication equipment (SCADA backhaul) in order to monitor (i.e., 43

30 https://www.zonarsystems.com/
31 Telematics systems include transmitting/receiving/data storage device installed in a vehicle that captures can
include location, speed, idling time, harsh acceleration or braking, fuel consumption, vehicle faults, and more.

DiLuciano 38
Avista Corporation
review telemetry), operate, and control the status of the equipment. 1
2
Q. Does this conclude your direct testimony? 3
A. Yes. 4