20210129Rosentrater Exhibit 11 Schedules 1-9.pdf

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

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-21-01
OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-G-21-01
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND ) EXHIBIT NO. 11
NATURAL GAS SERVICE TO ELECTRIC )
AND NATURAL GAS CUSTOMERS IN THE ) HEATHER L. ROSENTRATER
STATE OF IDAHO )
)

FOR AVISTA CORPORATION

(ELECTRIC AND NATURAL GAS)

Avista Utilities
Distribution Infrastructure Plan
2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 1 of 28
Table of Contents

Executive Summary ........................................................................................................................... 1
Introduction ...................................................................................................................................... 2
Avista’s Distribution Capital Investments .......................................................................................... 4
Classification of Infrastructure Need by Investment Drivers ..................................................................................4
Currently Planned Capital Investments in Distribution ..........................................................................................6
Avista’s Distribution O&M Investments ............................................................................................. 7
Distribution Upcoming Programs....................................................................................................... 7
Wrap Up ........................................................................................................................................... 7

Table of Figures

Figure 1. Electric Customer Growth ............................................................................................................................................. 3
Figure 2. Distribution Total Historic Actual Capital Spending by Investment Driver: 2010-2019 .................................................. 4
Figure 3. Projected Five Year Budget for Distribution Capital Expenditures by Investment Driver: 2020-2024 ........................... 4
Figure 4. Capital Budget by Investment Driver ............................................................................................................................. 6
Figure 5. Capital Actual & Budget Expenditures Based on Customer Requests / Growth ........................................................... 7
Figure 6. Capital Actual & Budget Expenditures Based on Mandatory & Compliance ................................................................. 7
Figure 7. Facilities Relocation Capital Expenditures .................................................................................................................... 7
Figure 8. Capital Actual & Budget Expenditures Based on Failed Plant & Operations ................................................................ 7
Figure 9. Capital Actual & Budget Expenditures: Storms ............................................................................................................. 7
Figure 10. Capital Actual & Budget Expenditures Based on Asset Condition .............................................................................. 7
Figure 11. Capital Actual & Budget Expenditures Based on Customer Service Quality & Reliability ........................................... 7
Figure 12. Capital Actual & Budget Expenditures Based on Performance & Capacity ................................................................ 7
Figure 13. Distribution O&M Expenditures 2009-2019 ................................................................................................................. 7
Figure 14. Padmount Transformer Issues Identified .................................................................................................................... 7

Table of Tables

Table 1. Distribution Capital Budget by Program 2020 - 2024 ..................................................................................................... 6
Table 2. Planned Capital Budget by Driver 2020 - 2024 .............................................................................................................. 6
Table 3. Customer Requested / Growth Capital Budget .............................................................................................................. 7
Table 4. Mandatory & Compliance Capital Budget....................................................................................................................... 7
Table 5. Failed Plant & Operations Capital Budget ...................................................................................................................... 7
Table 6. Asset Condition Capital Budget ...................................................................................................................................... 7
Table 7. Customer Service Quality & Reliability Capital Budget .................................................................................................. 7
Table 8. Performance & Capacity Capital Expenditures .............................................................................................................. 7
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 2 of 28

Avista’s Distribution business unit is experiencing the need for increasing investments as they work to
replace, upgrade, and repair aging infrastructure across the service territory. This never-ceasing work
has been increased significantly by the addition of providing new technologies to benefit customers
such as energy efficient LED (light emitting diode) street lighting and advanced metering infrastructure.
All of this has the aim of providing a level of service reliability that is satisfactory to customers at a
price that is fair and reasonable. Some individual infrastructure programs are responsive to investment
demands that are beyond the control of the Company, such as the customer requests for service or
mandatory and compliance projects. Other programs respond to needs that
are necessary and immediate such as failed equipment or storm damage.
Others are put in place to benefit reliability and customer service such as
adding devices to reduce the number of customers impacted by an outage.

Over time these investments change, programs come to an end, or new
programs are introduced based on need. This team stays on top of issues
and technology applications that can bring value to customer service as well
benefitting system stability, reliability, and resiliency. An example of this
foresight is the revamp of the Segment Reconductor and Feeder Tie
business case, which is being enhanced to provide additional value as
described in the text below. Another example is the implementation of a
padmount transformer inspection program which was recommended by
the Company’s insurance carrier. The Company leveraged this opportunity
to create a robust program that emphasizes public safety and quality of
service. Another creative and beneficial program being developed by the
team this year is the Wildfire Resiliency Program. Recognizing the increasing
risk of utility-caused fires, Avista is developing a comprehensive program to
safeguard customers and Company assets. This program includes enhanced
vegetation management practices, transmission and distribution system digital data collection to
monitor both vegetation and line/structure/equipment condition, development of appropriate power
line corridors, public outreach, and partnering with associated state and local agencies to address fire
issues. Further details on these new programs are included later in this report.

Avista’s Distribution team is continually challenged by a variety of circumstances, from budget
constraints to aging equipment to changing technologies and customer expectations. Through the
programs and tactics described in this report, they successfully navigate these changes and provide a
proven level of service in keeping the lights on. In fact, based on the Company’s outage data, the
average Avista customer had service 99.999741% of the time in 2019.1
1 The total outage duration for 2019, spread across every individual customer, was 2.27 hours per customer (SAIDI = 2.27) / 8760 hours in a year =
0.000259 or 99.999741%
Executive Summary

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 3 of 28

Avista owns and operates nearly 19,000 miles of electric distribution lines serving nearly 380,000 retail
electric customers in Washington and Northern Idaho, providing energy to over 1.6 million people.2
This infrastructure, designed, built, operated and maintained by the Company, includes both overhead
wire (conductor), underground electric lines (cable), secondary transformers, service lines (feeders),
and customers’ electric meters.
This system is interconnected
with 176 related substations.3
Avista must continually make
new investments in this system
in order to continue providing
customers with safe and reliable
electric service, at a reasonable
cost, and with service levels that
meet customer’s expectations
for quality and satisfaction.

In order to meet all of these
requirements, the Company
develops specific capital programs. These programs are developed through planning and engineering
studies and analyses, as well as scheduled upgrades or replacements identified in the operations
districts and within engineering groups. These projects undergo internal review by multiple
stakeholders who help ensure all system needs and alternatives have been identified and addressed. If
proposed projects are initially approved, they go through a formal review process referred to as the
Engineering Roundtable, a diverse group of engineering leaders4 who track project requests, prioritize
them, and establish committed construction package dates and required in-service dates for projects.
Once a project has passed this phase of evaluation, it moves to the Capital Planning Group.

The Capital Planning Group (CPG) is a group of Avista Directors that represent capital intensive areas of
the Company. Committee members are directors from a variety of business units to add a depth of
perspective, though their role is to consider capital decisions from the perspective of overall Company
operations and strategic goals as well as spending guidance set by senior management and approved
by the Finance Committee of the Board of Directors. They develop a final budget that represents a
reasonable balance among competing needs required to maintain the performance of Avista’s systems,
as well as prudent management of the overall enterprise in the best interest of customers.
2 Avista Quick Facts, https://investor.avistacorp.com/static-files/a7342b27-72cc-44d4-b9a7-b62903e999df
3 This includes 13 generation (step-up) substations, 22 transmission and switching substations, 31 transmission with distribution substations, 110
distribution only substations, and two substations that are owned by other utilities but contain Avista equipment.
4 Eleven representatives are included in this group from: Transmission and Distribution Planning, Transmission, Distribution, and Substation Design,
System Protection, System Operations, Asset Management, Communications and Generation Engineering, and Transmission Services.
Introduction

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 4 of 28
This report provides a summary overview of the Company’s recent historic, current, and planned
infrastructure investments in the electric distribution system for the period 2020-2024. For the
purposes of this report, discussions of “infrastructure investments” are confined to the physical energy
delivery facilities used to link electric substations with each customer’s meter. Operations and
maintenance (O&M) programs such as Vegetation Management are also included because they play a
key role in helping provide safe and reliable service.

Collectively, the investments described in this report allow Avista to effectively respond to customer
requests for new service or service enhancements, meet regulatory and other mandatory obligations,
replace equipment that is damaged or fails, support electric operations, address system performance
and capacity issues, and replace infrastructure at the end of its useful life based on asset condition. All
of this is subject to what is known about the business today, including a range of precision in future
cost estimates, applicable laws, regulatory requirements, and the capabilities of current technologies.

Avista has experienced relatively flat customer growth over the past few years, about 1% per year, as
shown in Figure 1. Between 2005 and 2019, the Company has responded to an average of over 4,600
requests for a new residential electric
service connection each year. For the
current five-year planning period, Avista
expects customer growth to continue at
about 1% per year based on regional
economic and population forecasts.
On the commercial side, the Company
connected an average of over 1,000 new
commercial customers per year
between 2005 and 2019, peaking in
2007 with nearly 1600 new commercial
customers. Today we are expecting
growth rates more in the range of 700
new commercial connects per year.

The programs put forward by the Distribution business unit encompass a broad spectrum of the
utility’s business needs including such things as infrastructure needed for new subdivisions or
businesses, mandatory work required when a county or a city relocate a roadway, dealing with failed
equipment or storm damage, replacing aging critical assets such as transformers and underground
cable, inspecting and replacing wood poles, installing new and customer-beneficial technologies such
as energy efficient lights and automated meters, and more. The current programs and their associated
expenditures are described in the following pages.

Figure 1. Electric Customer Growth

Avista’s Distribution Capital InvestmentsFigure 1. Electric Customer
Growth

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 5 of 28

Classification of Infrastructure Need by Investment Drivers

As a way to create more transparency around the particular needs being addressed with each capital
investment as well as simplify the organization and understanding of overall project plans, the
Company has developed “investment drivers” to classify its capital projects. These drivers are broad
categories that attempt to sort projects by the need
they are addressing, as described below:

1. Customer Requested – This category is set
aside primarily for connecting new customers
or enhancing their service as requested.
Typical projects include installing or extending
electric service to new subdivisions or
commercial developments.

2. Mandatory & Compliance – This category of
capital spending includes investments driven
by compliance with laws, regulations, and
contract requirements. Avista operates in a
complex regulatory and business framework
and must adhere to national and state laws, state
and federal agency rules and regulations, and
county and municipal ordinances. Compliance
with these rules, as well as contracts and
settlement agreements, represent obligations
that are generally external and largely outside of
the Company’s control. The types of electric
distribution investments that fall into this driver
include the obligation to relocate facilities to
accommodate state, county and municipal
infrastructure projects (frequently transportation
related) and compliance with environmental
regulations.

3. Failed Plant & Operations – This category of
spending replaces failed equipment, typically related to storm damage or other unexpected
failures of capital assets. While large-scale outages such as windstorms or ice storms are vividly
remembered by both Avista employees and its customers, the Company responds to thousands of
outage events each year that occur almost daily. Cars hit poles, ice overloads and breaks lines,
Avista’s Distribution Capital Investments

Figure 3. Projected Five Year Budget for
Distribution Capital Expenditures by Investment
Driver: 2020-2024

Figure 2. Distribution Total Historic Actual Capital
Spending by Investment Driver: 2010-2019Figure 3.
Projected Five Year Budget for Distribution Capital
Expenditures by Investment Driver: 2020-2024
Figure 2. Distribution Total Historic Actual Capital
Spending by Investment Driver: 2010-2019

Table 2. Planned Capital Budget by Driver 2020 -
2024Figure 2. Distribution Total Historic Actual
Capital Spending by Investment Driver: 2010-2019
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 6 of 28
trees fall or grow into circuits, animals get into the
equipment and create faults, and more. Company
crews manage issues like this on a daily basis to
keep the power flowing to customers.

4. Asset Condition – This driver is focused on
replacing assets at the end of their useful service
life. Avista uses an analytical approach to asset
replacement which includes asset criticality,
inspections, and optimization of life cycle costs. For
example, the Company is actively replacing failure-
prone underground cable and transformers
containing PCBs, and has a robust inspection program for wood
poles to identify issues before failure. Some non-critical assets
are allowed to fail to maximize their lifespans and minimize
costs. Some are so critical to providing service that they cannot
be allowed to fail and must be replaced as they reach end-of-
life.

5. Customer Service Quality & Reliability – This category of
spending helps Avista meet customers’ expectations for quality
of service and electric system reliability. Programs in this category include the Washington and
Idaho advanced meter infrastructure (AMI) programs to enhance customer and Company access
to information. Another program in this category is the replacement of old style streetlights with
energy-efficient LED lights to save money for customers.

6. Performance & Capacity – This driver helps ensure that the
Company’s assets satisfy business needs and meet
performance and safety standards. Avista develops and
maintains multiple standards related to operating their
electric facilities safely as well
as following the National
Electric Safety Code, which
impacts nearly all of the
Company’s programs and
projects. This category also
includes investments designed
to improve the performance of
the distribution system, such as
reconductoring feeders to
remedy overloading problems
and balancing the load on
feeders across the system to maximize asset performance and lifespan.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 7 of 28
Currently Planned Capital Investments in Distribution
2020 – 2024

For the next five-year
planning horizon, Avista
expects to spend nearly
$463 million in capital
dollars for the
Distribution side of the
business, allocated
across the six investment
drivers described above.
These programs are
summarized below.

Figure 4. Capital Budget by Investment Driver

Figure 5. Capital Actual & Budget Expenditures Based on Customer
Requests / GrowthFigure 4. Capital Budget by Investment Driver

Figure 5. Capital Actual & Budget Expenditures Based on Customer
Requests / Growth

Table 3. Customer Requested / Growth Capital BudgetFigure 5.
Capital Actual & Budget Expenditures Based on Customer Requests
/ GrowthFigure 4. Capital Budget by Investment Driver

Figure 5. Capital Actual & Budget Expenditures Based on Customer Requests / GrowthFigure 4. Capital Budget by Investment Driver
Table 2. Planned Capital Budget by Driver 2020 - 2024

Table 1. Distribution Capital Budget by Program 2020 - 2024Table 2. Planned Capital Budget by Driver 2020 - 2024

Table 1. Distribution Capital Budget by Program 2020 - 2024
Business Driver 2020 2021 2022 2023 2024
Customer Requested $19,272,425 $17,662,805 $17,264,366 $17,218,924 $17,523,576
Mandatory & Compliance $3,970,000 $4,500,000 $4,600,000 $4,600,000 $4,600,000
Failed Plant & Operations $3,200,000 $2,540,000 $2,632,000 $2,650,000 $2,650,000
Asset Condition $29,848,500 $34,535,000 $37,550,000 $38,980,000 $40,161,900
Customer Service Quality & Reliability $39,792,537 $28,057,245 $26,700,000 $26,600,000 $0
Performance & Capacity $7,012,500 $7,125,000 $7,125,000 $7,125,000 $7,125,000
Grand Total $103,095,962 $94,420,050 $95,871,366 $97,173,924 $72,060,476
Project Business Driver 2020 2021 2022 2023 2024 5-Year Total 5-Year Average
New Revenue - Growth Customer Requested $19,272,425 $17,662,805 $17,264,366 $17,218,924 $17,523,576 $88,942,096 $17,788,419
Elec Relocation and Replacement Program Mandatory & Compliance $2,470,000 $3,000,000 $3,100,000 $3,100,000 $3,100,000 $14,770,000 $2,954,000
Joint Use Mandatory & Compliance $1,500,000 $1,500,000 $1,500,000 $1,500,000 $1,500,000 $7,500,000 $1,500,000
Electric Storm Failed Plant & Operations $3,000,000 $2,340,000 $2,432,000 $2,450,000 $2,450,000 $12,672,000 $2,534,400
Meter Minor Blanket Failed Plant & Operations $200,000 $200,000 $200,000 $200,000 $200,000 $1,000,000 $200,000
Distribution Grid Modernization Asset Condition $8,000,000 $10,000,000 $12,000,000 $12,200,000 $13,000,000 $55,200,000 $11,040,000
Distribution Minor Rebuild Asset Condition $8,768,500 $10,000,000 $10,000,000 $10,000,000 $10,000,000 $48,768,500 $9,753,700
Distribution Transformer Change Out Program Asset Condition $541,000 $600,000 $0 $0 $0 $1,141,000 $228,200
Downtown Network - Asset Condition Asset Condition $1,539,000 $1,600,000 $2,800,000 $2,800,000 $2,800,000 $11,539,000 $2,307,800
LED Change-Out Program Asset Condition $500,000 $585,000 $500,000 $500,000 $500,000 $2,585,000 $517,000
Primary URD Cable Replacement Asset Condition $0 $750,000 $750,000 $750,000 $750,000 $3,000,000 $600,000
Wood Pole Management Asset Condition $10,500,000 $11,000,000 $11,500,000 $12,730,000 $13,111,900 $58,841,900 $11,768,380
Idaho Advanced Metering Infrastructure Customer Service Quality & Reliability $2,500,000 $26,700,000 $26,700,000 $26,600,000 $0 $82,500,000 $16,500,000
Washington Advanced Metering Infrastructure Customer Service Quality & Reliability $37,292,537 $1,357,245 $0 $0 $0 $38,649,782 $7,729,956
Segment Reconductor and Feeder Tie Performance & Capacity $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $30,000,000 $6,000,000
Downtown Network - Performance & Capacity Performance & Capacity $1,012,500 $1,125,000 $1,125,000 $1,125,000 $1,125,000 $5,512,500 $1,102,500
Total $103,095,962 $94,420,050 $95,871,366 $97,173,924 $72,060,476 $462,621,778 $92,524,356
Table 1. Distribution Capital Budget by Program 2020 - 2024

Figure 4. Capital Budget by Investment DriverTable 1. Distribution Capital Budget by Program 2020 -
2024

Figure 4. Capital Budget by Investment Driver

Figure 5. Capital Actual & Budget Expenditures Based on Customer Requests / GrowthFigure 4. Capital
Budget by Investment DriverTable 1. Distribution Capital Budget by Program 2020 - 2024

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 8 of 28
Customer Requested

Growth often refers to new service
connections, as in growth in the
number of customers, however,
these investments are primarily
beyond the control of the
Company, and as such they do not
reflect a plan or strategy on the
part of Avista. Responding quickly
to customer requests for service is
a requirement of providing utility
service. Direct costs associated
with extending feeder and service
wires and cables to provide
requested service to a customer are
subject to cost sharing between that customer and Avista. As the number of customers on a feeder
grows over time however, the Company may have to replace or upgrade the capacity of trunk line
feeders or laterals. The investments needed for this work, which are included under the operations
capital, are paid for by all customers because they are required to provide reliable service to everyone
on Avista’s system.
Mandatory & Compliance

Avista operates within a complex
regulatory and business
framework and is required to
comply with laws and regulations
from the local to the federal level.
The types of investments that fall
into this driver include
compliance with safety and
environmental regulations and
contractual work such as joint
projects with other utilities and
relocating facilities as requested
by state, county, or local Figure 6. Capital Actual & Budget Expenditures Based on Mandatory &
Compliance

Table 4. Mandatory & Compliance Capital BudgetFigure 6. Capital Actual &
Budget Expenditures Based on Mandatory & Compliance

Table 4. Mandatory & Compliance Capital Budget

Figure 5. Capital Actual & Budget Expenditures Based on Customer
Requests / Growth

Table 3. Customer Requested / Growth Capital BudgetFigure
5. Capital Actual & Budget Expenditures Based on Customer Requests /
Growth

Table 3. Customer Requested / Growth Capital Budget

Table 3. Customer Requested / Growth Capital BudgetFigure
5. Capital Actual & Budget Expenditures Based on Customer Requests /
Growth

Table 3. Customer Requested / Growth Capital BudgetFigure
5. Capital Actual & Budget Expenditures Based on Customer Requests /
Growth
Table 3. Customer Requested / Growth Capital Budget
Customer Requested 2020 2021 2022 2023 2024 5-Year Total 5-Year Average
New Revenue - Growth $19,272,425 $17,662,805 $17,264,366 $17,218,924 $17,523,576 $88,942,096 $17,788,419
Actual Budget
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 9 of 28
jurisdictions. Distribution has two primary programs in this category: the Relocation and Replacement
Program and a Joint Use Program. Both will be described below.

Electric Relocation & Replacement Program

Avista is required to move its electric distribution infrastructure in response to municipalities, counties
and state-level agency projects, often related to rebuilding or realigning roads, streets and highways.
This work must be performed at the
Company’s expense, and while Avista
may have some latitude to negotiate
the timing of the construction, it has
no choice with regard to removing and
relocating its infrastructure as
requested and paying all of the
associated costs. Avista works with the
Departments of Transportation in both
Washington and Idaho to renew and
maintain crossing and encroachment
permits, which often requires the
Company to move its distribution
infrastructure at its own expense. This
work may require the Company to realign or modify existing infrastructure to comply with state clear
zone, conductor clearance, and other regulations regarding the location of poles, guy wires, pad
mounted equipment, and overhead conductors. These costs are increasing over time as jurisdictions in
which Avista must perform the work are becoming more and more demanding in their requirements,
including calling for additional work as a condition of construction such as extensive landscaping or
hiring additional flaggers, all of which increase costs. As shown in Figure 7, these costs are also highly
variable from year to year and difficult to predict.

Joint Use Program

Joint use occurs when one or more utilities share space on the same pole. Avista currently has over 74
joint use and licensee partners in Idaho and Washington, including those related to telephone,
telecommunications, cable television, etc. On average, Avista has at least two joint use cables on about
Table 4. Mandatory & Compliance Capital Budget

Figure 7. Facilities Relocation Capital ExpendituresTable 4. Mandatory & Compliance Capital Budget

Figure 7. Facilities Relocation Capital Expenditures

Figure 7. Facilities Relocation Capital ExpendituresTable 4. Mandatory & Compliance Capital Budget

Figure 7. Facilities Relocation Capital ExpendituresTable 4. Mandatory & Compliance Capital Budget
Mandatory & Compliance 2020 2021 2022 2023 2024 5-Year Total 5-Year Average
Elec Relocation and Replacement Program $2,470,000 $3,000,000 $3,100,000 $3,100,000 $3,100,000 $14,770,000 $2,954,000
Joint Use $1,500,000 $1,500,000 $1,500,000 $1,500,000 $1,500,000 $7,500,000 $1,500,000
Total $3,970,000 $4,500,000 $4,600,000 $4,600,000 $4,600,000 $22,270,000 $4,454,000
Figure 7. Facilities Relocation Capital Expenditures

Figure 7. Facilities Relocation Capital Expenditures

Figure 7. Facilities Relocation Capital Expenditures

Figure 7. Facilities Relocation Capital Expenditures
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 10 of 28
half of its utility poles across the service territory (about 150,000
structures). Sharing poles is completely routine and makes sense for
all parties, as there is a logical maximum to the number of utility
poles that can exist in an area, and having multiple wires from
several independent sources can create safety and maintenance
hazards. The joint use concept creates a more organized system for
managing the diverse needs for poles. Avista provides fair and non-
discriminatory access to Company distribution poles and coordinates
the work involved in attaching to Avista’s structures to ensure that
the attachments have the proper clearance, the poles have the
required strength, and that there is adequate climbing space for line
work.

Capital expenditures in this category may include putting in a
taller pole or more robust pole anchors to handle the
additional weight, rearranging poles, or installing additional
grounding. If a joint use pole is failing, Avista may replace it by
agreement with the associated party to ensure continued
service for Avista customers. The Company is typically
reimbursed for customer-requested work or requests for
work made by other utilities but provides a capital budget for
work on the Company’s own shared structures.

Failed Plant & Operations

This business driver is designed to fund replacement of assets that have failed and which must be
replaced, including customer meters. A
portion of Company assets fail each
year as a result of damage from storms,
fires, vehicle accidents, third-party dig-
ins, etc. When this happens, the
Company must quickly respond to
replace the failed infrastructure in order
to ensure the continuity of service to
customers.

Typical joint use situation

Table 5. Failed Plant & Operations
Capital BudgetTypical joint use situation

Typical joint use situation

Table 5. Failed Plant & Operations
Capital BudgetTypical joint use situation

Typical joint use situation

Table 5. Failed Plant & Operations
Capital BudgetTypical joint use situation

Typical joint use situation

Table 5. Failed Plant & Operations
Capital BudgetTypical joint use situation
Figure 8. Capital Actual & Budget Expenditures Based on Failed
Plant & Operations
TV coax expansion loop Telephone splice case
Electric lines
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 11 of 28
Electric Storm Budget

During this budget cycle the Company
expects to spend about $2.7 million on
distribution storm repairs but, as can be
imagined, this amount could vary
substantially. As shown in Figure 9, one
major event can have drastic impacts on
Avista’s capital budget. For example, in
2015 a historic 100 year wind storm
event rolled through the area. Hurricane
force winds caused the greatest level of
damage to Avista’s system ever experienced. At the
peak of this storm, more than 180,000 Avista
customers were without power, some for up to two
weeks. It took nearly a year for the Company to
complete permanent repairs on its infrastructure. This
event cost nearly $23 million in damage to equipment
and facilities. Though this situation is not typical, such
unexpected expenditures are always possible.

Meter Minor Blanket

Part of the routine work the Company experiences are meters and/or metering equipment failures.
Meters are a critical component to supplying customers with electricity and to accurately measuring
their energy consumption. When meters fail, immediate
action must be taken to repair or replace the meter. A
failed meter will not provide accurate consumption data,
requiring the customer’s usage to be estimated, which
has been shown to cause customer dissatisfaction. In
determining the best course of action in dealing with
failed meters, the Company looked at three options (shown in the box above) and determined that the
most cost effective course was to replace a failed meter with a new meter. The expenses associated
with replacing meters are allocated to the Failed Plant & Operations budget category.
Failed Meter Options Cost Installation
Labor Total Cost
Refurbish Meter $37.26 $35.76 $73.02
Return to Manufacturer $35.76
Removal Cost $9.31
Shipping Cost $7.17
Repair Cost $30.00 $82.24
Install New Meter $20.43 $35.76 $56.19
Table 5. Failed Plant & Operations Capital Budget

Figure 9. Capital Actual & Budget Expenditures: StormsTable 5. Failed Plant & Operations Capital Budget

Figure 9. Capital Actual & Budget Expenditures: Storms

Figure 10. Capital Actual & Budget Expenditures Based on Asset ConditionFigure 9. Capital Actual & Budget Expenditures:
StormsTable 5. Failed Plant & Operations Capital Budget

Figure 9. Capital Actual & Budget Expenditures: StormsTable 5. Failed Plant & Operations Capital Budget
Failed Plant & Operations 2020 2021 2022 2023 2024 5-Year Total 5-Year Average
Electric Storm $3,000,000 $2,340,000 $2,432,000 $2,450,000 $2,450,000 $12,672,000 $2,534,400
Meter Minor Blanket $200,000 $200,000 $200,000 $200,000 $200,000 $1,000,000 $200,000
Total $3,200,000 $2,540,000 $2,632,000 $2,650,000 $2,650,000 $13,672,000 $2,734,400
Figure 9. Capital Actual & Budget Expenditures: Storms

Figure 10. Capital Actual & Budget Expenditures Based on Asset ConditionFigure 9. Capital Actual & Budget Expenditures: Storms

Figure 10. Capital Actual & Budget Expenditures Based on Asset
Condition

Table 6. Asset Condition Capital BudgetFigure 10. Capital Actual &
Budget Expenditures Based on Asset ConditionFigure 9. Capital
Actual & Budget Expenditures: Storms

Figure 10. Capital Actual & Budget Expenditures Based on Asset
ConditionFigure 9. Capital Actual & Budget Expenditures: Storms
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 12 of 28
Asset Condition

Assets of every type will degrade with age, usage, and other factors, and must be replaced or
substantially rebuilt at some point
in order to ensure the reliable and
acceptable continuation of service
as well as the safety of the public
and Avista employees. The
replacement of assets based on
condition is essentially the practice
of removing them from service and
replacing them at the end of their
useful life. Across the utility
industry and likewise for Avista, the
replacement of assets based on
condition constitutes a substantial
portion of the infrastructure
investments made by the Company each year.

At Avista, the goal is to manage assets in a manner that optimizes their overall value over the lifecycle
of each particular asset class. Asset replacement strategies are “optimized” in the sense that a given
approach may not achieve the overall lowest possible lifecycle cost, but rather the lowest cost that
allows the Company to meet a variety of important performance objectives, such as public safety or
the efficient use of employee crews. Because failure of critical assets is unacceptable, they must be
replaced before the end of their useful life even if they are still providing reliable service. In other
instances it may be reasonable to wait until an asset fails before it is replaced, a strategy known as “run
to failure.”

In Distribution, the Asset Condition business driver includes the Grid Modernization Program, replacing
aging or PCB transformers, wood pole work, underground cable and street or area light replacement,
upgrading the Downtown Network system, and performing system-wide repairs. Each of these
programs is described in more detail below.
Figure 10. Capital Actual & Budget Expenditures Based on Asset Condition

Table 6. Asset Condition Capital BudgetFigure 10. Capital Actual
& Budget Expenditures Based on Asset Condition

Table 6. Asset Condition Capital Budget

Table 6. Asset Condition Capital BudgetFigure 10. Capital Actual
& Budget Expenditures Based on Asset Condition

Table 6. Asset Condition Capital BudgetFigure 10. Capital Actual
& Budget Expenditures Based on Asset Condition
Table 6. Asset Condition Capital Budget

Table 6. Asset Condition Capital Budget

Table 6. Asset Condition Capital Budget

Asset Condition 2020 2021 2022 2023 2024 5-Year Total 5-Year Average
Distribution Grid Modernization $8,000,000 $10,000,000 $12,000,000 $12,200,000 $13,000,000 $55,200,000 $11,040,000
Distribution Minor Rebuild $8,768,500 $10,000,000 $10,000,000 $10,000,000 $10,000,000 $48,768,500 $9,753,700
Distribution Transformer Change Out Program $541,000 $600,000 $0 $0 $0 $1,141,000 $228,200
Downtown Network - Asset Condition $1,539,000 $1,600,000 $2,800,000 $2,800,000 $2,800,000 $11,539,000 $2,307,800
LED Change-Out Program $500,000 $585,000 $500,000 $500,000 $500,000 $2,585,000 $517,000
Primary URD Cable Replacement $0 $750,000 $750,000 $750,000 $750,000 $3,000,000 $600,000
Wood Pole Management $10,500,000 $11,000,000 $11,500,000 $12,730,000 $13,111,900 $58,841,900 $11,768,380
Total $29,848,500 $34,535,000 $37,550,000 $38,980,000 $40,161,900 $181,075,400 $36,215,080
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 13 of 28
Distribution Grid Modernization Program

Avista is systematically rebuilding and upgrading its electric distribution feeders and, where cost
effective, is installing feeder automation with the objectives of improving service reliability, capturing
energy efficiency savings, and improving operational ability, code compliance, and safety. These
objectives are accomplished through the systematic replacement of aging equipment that has reached
the end of its useful life, such as old poles, conductor, and transformers, with new and more energy
efficient equipment that ensures the long-term operability of the system. The program also replaces
pre-1981 distribution transformers with energy efficient units that meet current standards. This
program also replaces underground cables that have uninsulated neutrals, which pose a system
reliability risk.

This Program not only focuses on rebuilding feeders that are at or
nearing the end of their useful life, but also evaluates the potential
benefits of a range of physical reconfigurations of the feeders, taking
into account opportunities to improve voltage settings, fuse
coordination, line losses, transformer losses, power factors, and the
potential benefits of feeder automation. By integrating all of this
information, along with the full range of asset age and condition data,
engineers recommend a comprehensive set of actions that will be
applied to the feeders, identifying the investment requirements and
the cumulative estimated benefits.

The Grid Modernization Program is the only program at the Company
that provides a holistic approach to each feeder by addressing asset
condition, transformer change outs, efficiency improvements,
improved reliability, real estate encroachments, highway clear-zone
issues, avian and animal protection, environmental permits, and other
unique considerations that are specific to each feeder all at the same time. This increases crew
efficiency and minimizes the number of outages and instances that crews will be deployed to affected
communities. Rather than multiple outages that address each of these issues as they arise, one
planned outage is taken to address all relevant issues.

Minor Rebuild Program

In addition to outage response, Avista’s routine operations include reconfiguration and replacement of
electric facilities under a variety of circumstances. This spending category allows the Company to
address small unplanned asset failures or customer requested modifications to their electrical service
that don’t rise to the level of requiring their own capital program. Even though relatively small in cost,
these are projects that impact the reliability of the distribution system, customer service, or the safety
of the public or employees and must be addressed. Typically these projects are related to meeting
•Undersized or deteriorating
conductor
•Failed poles, crossarms, fuses,
insulators, guy wires, arrestors,
cutouts, street lights

•Avian protection

•Accessibility issues
•Right-of-way concerns
•Potential for undergrounding

•Coordinating joint use facilities

•Clear Zone compliance
•Safety Issues

GRID MOD FOCUS AREAS

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 14 of 28
safety codes, inoperable equipment such as failed poles or
broken crossarms, or unpredictable circumstances such as
when vehicles hit poles.

At times equipment must be modified or upgraded to handle
changing customer load conditions such as installing a system
of fuses that protect the system from line faults, adding
voltage regulators or reclosing equipment, or replacing a pole,
cross arm, or transformer in poor condition. Avista monitors
circuit loading and may shift load from one circuit to another
during winter or summer peak usage, which often involves
extending overhead or underground primary wires and cables.
These types of capital infrastructure work do not qualify as a
project or program on their own but must have funding, so are
handled through the Minor Rebuild general budget account.
Occasionally larger projects are constructed under this
category if there is an urgent need and a short timeframe for
implementation, but that is not typical.

Transformer Change-Out Program

The Transformer Change-Out Program has three primary
drivers. The program initially focused on replacing pre-1981
transformers to increase the reliability and availability of the
electric system and ensure that
transformers potentially
containing polychlorinated
biphenyls are removed from
Avista’s distribution system.
Polychlorinated Biphenyls (PCBs) were commonly used in the oil of
electrical transformers in past decades due to their high dielectric
strength5 and resistance to fire. Studies conducted in the 1960s and
1970s revealed, however, that these compounds are also toxic,
carcinogenic and highly resistant to biodegradation in the environment.
Their production was banned in the United States in 19796 and Avista
has been programmatically replacing these transformers. There were
about 12,000 such transformers on Avista’s system when this program
started. In 2020 there were less than 300 remaining PCB transformers.
5 Dielectric strength refers to the ability of a material to resist carrying an electrical current, which is a measure of its potential to insulate against electric
short circuit or fault.
6 “PCBs Questions & Answers,” United States Environmental Protection Agency, https://www3.epa.gov/region9/pcbs/faq.html.
•Repair broken or damaged
equipment and fixtures whether or
not they are related to a customer
outage.

•Add an additional phase (overhead conductor or underground cable) to
support customer loads requiring
three-phase service.

•Replace undersized conductor or
cables as needed to provide
adequate service.

•Reconfigure overhead feeder
conductors to meet the clearance
requirements for joint use facilities,
such as telecom fiber attached to
Avista’s poles.

•Load balancing among the phases
on a feeder to reduce the return
current on the neutral wire.

•Modifications or line additions to
protect birds and animals.

•Repair or replacement of equipment
damaged by vandalism or theft (e.g.
copper wire theft.)

•Replacement of failed customer
demand meters.

Typical Minor Rebuild
Work

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 15 of 28
Downtown Network – Asset Condition Program

The Downtown Network has funding set aside under both the
Performance and Capacity and the Asset Condition investment
drivers. Most of the Network’s equipment is located in
underground vaults, manholes and hand-holes in Downtown
Spokane. With ongoing growth in Spokane, the downtown area
is in a continual state of construction, requiring the Company to
upgrade old equipment, relocate assets due to road work or
construction, or respond to city, county, or customer requests
that are fairly random every year, yet make up a large portion of
the Downtown Network operations.

The majority of the Network’s structural assets (such as manholes,
vaults, and ducts) have exceeded their expected life and must be
programmatically replaced in order to continue service. When this
equipment fails, it can have a significant impact on downtown
businesses as well as pose safety hazards for the public. The
Company is in a state of constantly replacing old structural and
electrical equipment while at the same time addressing requests
from the city, county, and customers for service changes in addition
to mitigating construction impacts on Company facilities and
operations. These projects fall under the Asset Condition investment
driver for the Downtown Network.

LED Change-Out Program

Avista operates approximately 35,000 street lights across the service
territory as well as area lights requested and paid for by individual
customers. Avista manages street lights for many local and state
government entities by installing and replacing street lights per their
request. In 2013, in response to the superior safety and efficiency
performance of Light-Emitting Diode (LED) lighting, the energy savings
potential, and the opportunity to reduce long-term energy costs, Avista
evaluated the benefit of converting from High Pressure Sodium (HPS) to
LED fixtures and, based on significant savings opportunities, developed a
replacement program. LED bulbs are six to seven times more efficient than
traditional bulbs, cutting energy use by up to 80%. In addition, they can
operate more than 25 times longer than conventional bulbs.7 This program
7 “How Energy-Efficient Light Bulbs Compare with Traditional Incandescent,” U.S. Department of Energy, https://www.energy.gov/energysaver/save-
electricity-and-fuel/lighting-choices-save-you-money/how-energy-efficient-light
Above & Below: Downtown Network Vaults

Downtown Network Vault

Above & Below: Downtown Network Vaults

Downtown Network Vault

Above & Below: Downtown Network Vaults

Downtown Network Vault

Above & Below: Downtown Network Vaults

Downtown Network Vault

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 16 of 28
also helps the Company be in compliance with Washington State Initiative 937 (or the “Clean Energy
Initiative”),8 part of which required that Washington utilities undertake all cost-effective energy
conservation measures. LED streetlight technology is part of this energy conservation work.

Primary URD Cable Replacement Program

Underground Residential District Cable (URD) has been used by the utility industry since the 1930s,
though Avista did not begin installing the cable until the late 1960s. During the 1990s it became
apparent that the cable manufactured prior to the 1982 had numerous problems, primarily a lack of
insulation that allowed water penetration and corrosion. It also had a lack of protection from dig-ins,
animals, vegetation and lightning all leading to numerous faults and failures. Prior to the underground
cable problems becoming apparent to the industry, Avista had
installed over 6,000,000 feet of this type of cable.

By the mid-1990s, customers served by this cable began to
experience outages that were increasing in number as the cable aged
and continued to deteriorate. Repairing these failures is particularly
expensive (about $3000 per event) due to the complexity involved in
locating the fault, digging up the cable, and splicing in new sections.
The Company initiated a program to systematically replace pre-1990
cable about 15 years ago. Unfortunately, unmapped sections of this old cable are being continually
found, typically when the cable has failed, thus this program will be ongoing into the near future.

Wood Pole Management Program

Avista has 347 overhead electric feeders that are supported by
approximately 230,000 poles. These poles are predominantly wood (about
99%). The attached equipment includes crossarms,
transformers, cutouts, insulators and pins, wildlife
guards, lightning arresters, guy lines, and pole
grounding. Avista’s wood pole population is
inspected on a 20-year cycle interval, which means
about 11,500 poles, crossarms, and associated
equipment are inspected on average each year.

Avista’s distribution wood poles have an average lifespan of approximately 70
years as they are managed in the system today.9 A key part of maintaining the
wood pole population is Avista’s robust inspection program. The condition of
each pole is assessed during this inspection to determine whether any issues
8 https://www.commerce.wa.gov/growing-the-economy/energy/energy-independence-act/
9 This lifespan can be increased by stubbing and chemically treating the wood poles.
Stubbed Pole

Avista Wood Pole
Inspection

Avista Wood Pole
Inspection

Avista Wood Pole
Inspection
Avista Wood Pole Inspection

Avista Wood Pole Inspection

Avista Wood Pole Inspection

Avista Wood Pole Inspection

Avista Wood Pole Inspection

Avista Wood Pole Inspection

Avista Wood Pole Inspection

Avista Wood Pole Inspection
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 17 of 28
need to be addressed, rather than relying only upon only age information to categorize the health of
the pole. The inspection process identifies damage from insects, animals, lightning, fire, decay,
mechanical damage, equipment failure (such as a leaking transformer), unauthorized attachments, and
other issues such as a broken guy wire, grounding, or soil concerns. Decay is the most common reason
for pole failure and is detectable with proper inspection. Inspectors also assess components including
transformers, ground, and guy wires. The capital
investments made under this program cover the
needed repair and replacement of poles and
attached equipment that is
identified during the
inspections.

Customer Service Quality & Reliability

This category of spending helps Avista
meet customers’ expectations for quality
of service and electric system reliability.
The programs in this category are the
Washington and Idaho advanced meter
infrastructure (AMI) programs.
Traditionally, utility customers have had
few tools to effectively understand and
manage their energy use because
conventional meters are not equipped to
provide near real-time information on
energy consumption. AMI offers a
variety of benefits for customers
including providing them with the
framework for new technology options, increased information availability, and a measure of control
over their energy usage and expenditures. It allows customers the ability to integrate new “smart”
devices into their homes, and provides the ability to offer customers technology products and services
into the future. From the Company’s perspective, Avista will see general savings (which ultimately
benefit customers) via voltage reductions, reduced theft and unbilled usage, consistency and simplicity
in metering applications, remote service connectivity, and outage management.
Figure 11. Capital Actual & Budget Expenditures Based on Customer Service
Quality & Reliability

Table 7. Customer Service Quality & Reliability Capital
BudgetFigure 11. Capital Actual & Budget Expenditures Based on Customer
Service Quality & Reliability

Table 7. Customer Service Quality & Reliability Capital Budget

Table 7. Customer Service Quality & Reliability Capital
BudgetFigure 11. Capital Actual & Budget Expenditures Based on Customer
Service Quality & Reliability

Table 7. Customer Service Quality & Reliability Capital
Types of Pole Inspection Issues
Identified in Inspections
Identified

Figure 11. Capital Actual &
Budget Expenditures Based on
Customer Service Quality &
ReliabilityPole Inspection Issues
Identified

Figure 11. Capital Actual &
Budget Expenditures Based on
Customer Service Quality &
Reliability

Table 7. Customer
Service Quality &
Reliability Capital
BudgetFigure 11. Capital
Actual & Budget Expenditures
Based on Customer Service
Quality & ReliabilityPole
Inspection Issues Identified

Figure 11. Capital Actual &
Budget Expenditures Based on
Customer Service Quality &
ReliabilityPole Inspection Issues
Identified
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 18 of 28

Washington Advanced Metering Infrastructure

The Washington Advanced Metering Infrastructure (AMI)
program encompasses Avista’s Washington service territories.
Also popularly known as “smart meters,” this effort keeps pace
with the evolving metering standard of the industry and will
deliver a range of cost-effective benefits to customers as shown in
the blue text box on the right. This project will take approximately
six years and will deploy advanced meters to approximately
253,000 electric customers and 155,000 gas customers. Avista is
planning to replace all of its existing Washington electric meters,
the majority of which are conventional electro-mechanical
meters, with a new advanced meter. The existing natural gas
meter will not be replaced but will be upgraded with a new digital
communications module. Since most gas meters are mechanical
devices, installation of AMI technologies use a radio device
attached to the existing gas meter to communicate the amount of
gas used.

Idaho Advanced Metering Infrastructure

The Idaho AMI Project will install an advanced metering system to
include meters, the communication network and data repository.
Advanced meters will be deployed to approximately 136,000
electric customers and 87,000 gas customers starting in 2020. All
existing Idaho digital electric meters will be replaced with a new
advanced meter. As was the case in Washington, existing natural
gas meters will be upgraded with a new digital communicating
module; the natural gas meter itself will not be replaced. Idaho
AMI customers will be
integrated into Avista’s
current hardware/software
system for Washington AMI
customers, reducing
duplication of resources.
Table 7. Customer Service Quality & Reliability Capital Budget

Table 7. Customer Service Quality & Reliability Capital Budget

Table 7. Customer Service Quality & Reliability Capital Budget

Table 7. Customer Service Quality & Reliability Capital Budget
Customer Service Quality & Reliability 2020 2021 2022 2023 2024 5-Year Total 5-Year Average
Idaho Advanced Metering Infrastructure $2,500,000 $26,700,000 $26,700,000 $26,600,000 $0 $82,500,000 $16,500,000
Washington Advanced Metering Infrastructure $37,292,537 $1,357,245 $0 $0 $0 $38,649,782 $7,729,956
Total $39,792,537 $28,057,245 $26,700,000 $26,600,000 $0 $121,149,782 $24,229,956
• Customer access to interval
energy usage data
•Customer tools to help them
manage their energy use
•Enables smart home options
•Energy alerts for customers
when their bill reaches a
predetermined level
•Customer property privacy
•Migration away from manual
meter reading

•Remote and rapid disconnect /
connect / reconnect

•Outage management

•Energy efficiency - more
efficient feeder operation
•Energy theft and unbilled
energy usage detection
•Billing accuracy

•Data for utility system studies

•Improved utility employee
safety
•Variable rate options
•Enhanced data analytics
•Support for micro grids and
smart cities
•Foundation for distributed
generation

ADVANCED METERING
INFRASTRUCTURE BENEFITS

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 19 of 28
Performance & Capacity

Avista’s projects and programs
grouped in this category of need
include a range of investments that
address the capability of assets to
meet defined performance
standards, typically developed by the
Company or based on a
demonstrated need. Avista is also
attentive to investment opportunities
to improve the performance of the
distribution system when supported
by a study or analysis that
demonstrates the cost-effectiveness of the benefits achieved for customers.

The performance of distribution systems is guided by industry accepted practices, but prescribed by
internal company policies, procedures, and standards. These standards have been developed to ensure
the safe, efficient, reliable and prudent management of utility infrastructure and operations. When the
Company determines its operations no longer meet a given standard, infrastructure needs must be
assessed in order to make the timely capital investments necessary to remain within the limits of the
standard. A common example is the objective to operate within established thermal limits for electrical
equipment. During this budget cycle, two primary programs fall into this category. These programs are
described below.

Segment Reconductor and Feeder Tie

This program is designed to remedy the overloading of electric equipment and cable, as well as the
conductor sag that results from overheating of the overhead wire. These instances of system
overloading result from load growth and shifts in load demand that occur over time on the distribution
system.

Avista’s distribution system follows the industry standard of using relatively short sections of main
feeder trunk supporting longer connected lateral lines that carry electricity to the customer’s service.
Though the overall load on a feeder as it leaves the substation is often known and monitored in real
time, the actual loading on the downstream trunk and lateral branch circuits must be estimated and
Figure 12. Capital Actual & Budget Expenditures Based on Performance &
Capacity

Table 8. Performance & Capacity Capital ExpendituresFigure
12. Capital Actual & Budget Expenditures Based on Performance &
Capacity

Table 8. Performance & Capacity Capital Expenditures

Table 8. Performance & Capacity Capital ExpendituresFigure
12. Capital Actual & Budget Expenditures Based on Performance &
Capacity

Table 8. Performance & Capacity Capital ExpendituresFigure
12. Capital Actual & Budget Expenditures Based on Performance &
Capacity
Table 8. Performance & Capacity Capital Expenditures

Table 8. Performance & Capacity Capital Expenditures

Performance & Capacity 2020 2021 2022 2023 2024 5-Year Total 5-Year Average
Segment Reconductor and Feeder Tie $6,000,000 $6,000,000 $6,000,000 $6,000,000 $6,000,000 $30,000,000 $6,000,000
Downtown Network - Performance & Capacity $1,012,500 $1,125,000 $1,125,000 $1,125,000 $1,125,000 $5,512,500 $1,102,500
Total $7,012,500 $7,125,000 $7,125,000 $7,125,000 $7,125,000 $35,512,500 $7,102,500
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 20 of 28
field tested to verify whether a problem exists. Resolving these overloading issues involves a
combination of two strategies known as “load shifting” and “segment reconductoring.”

The strategy of load shifting involves
extending existing lines on one feeder
to an adjacent feeder that has the
available capacity to carry the
additional transferred load. Shifting the
load from one feeder to another not
only solves the overloading issue but
also helps capture additional value from
the existing infrastructure. Segment
reconductoring involves the removal of
the wire or conductor that is too small in
diameter for the current loading and replacing it with larger conductor that can easily and more
efficiently carry the load. It is the most direct approach for mitigating overloaded circuits; however,
Avista considers a range of options that not only meet the current need to relieve the loading but also
optimize the overall distribution system.

Currently the Company is facing an increasing number of new
large spot loads, typically ranging anywhere from one to five
megawatts. The size of these new loads increases the need for
unplanned reconductoring of distribution feeder segments. In
turn, this unplanned work is hindering the ability to complete
planned and preventative work and creates unanticipated budget
pressures, creating a situation in which work is becoming more
and more reactive in nature and necessary maintenance and
repair work begins to fall behind. In an effort to address these circumstances in a proactive way, the
Distribution team is updating the Segment Reconductor and Feeder Tie business case. This business
case will be renamed “Distribution System Enhancements,” and in the future will encompass more of
the work that is being done to maintain and improve the distribution system.

This business case will become the main budget source for the Avista Area Engineers. These specialized
employees are responsible for continually monitoring, analyzing and evaluating the overall health of
the distribution system. They act upon issues such as conductor or equipment overloading due to
customer growth, power quality issues caused by voltage or current harmonics, power quality issues
caused by over or under voltage, and reliability issues that can be improved with the installation of
new equipment or new sections of power lines. These issues will all be addressed under the new
Distribution Systems Enhancement business case.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 21 of 28
Downtown Network Performance & Capacity

Avista owns and maintains an underground electric network that serves
the core business, financial, and city government district of downtown
Spokane. This network encompasses over a thousand underground
manholes, hand-holes, and vaults. There are two investment drivers
associated with the Downtown Network: Asset Condition, and
Performance & Capacity. Under the Performance and Capacity
investment driver, the Downtown Network provides funding to address
load growth at the system level, network grid expansion, as well as
crew and public safety issues. A key focus area is to add the ability to
remotely observe the actual flow on the secondary networks and
equipment to provide the status of the network protectors. Increasing
loads due to the growth in Downtown Spokane are beginning to
overload the network, requiring additional line and/or transformer
capacity. It is critical for the Company to track the load status to ensure
that equipment is not overloaded and to identify where additional capacity is needed. In addition,
safety equipment such as operable customer disconnects are required. Currently roughly 10-15% of
the Network is at a high safety risk level for faults, fire, or electrical shock. Measures must be taken to
mitigate this risk to the public, Avista employees, and contract crews. Those types of expenditures fall
under this investment driver.
Downtown Network vault

Avista’s Distribution O &
M InvestmentsDowntown
Network vault and cable work

Avista’s
Distribution
O&M
Investments
Downtown Network vault

Avista’s Distribution O &
M InvestmentsDowntown
Network vault and cable work
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 22 of 28

Avista monitors the distribution system very closely to guarantee that critical equipment remains
functional and the system is fully intact. O&M expenditures allow the Company to maintain and
operate the electric system in the
most safe, reliable, and efficient
way possible. These expenditures
permit the Company to respond
when damage occurs from weather
or accidents and a host of other
issues that arise in this complex
system, all in service of keeping the
power flowing safely and efficiently
to customers.

O&M expenditures are a part of
every maintenance project, as these
projects all require manpower, administration, and supplies and equipment that don’t rise to the level
of capital items. As shown in Figure 13, both planned and failed asset maintenance comprise a large
percent of the Company’s required expenditures. Compliance is another important area, and includes
obligations such as joint use project work, environmental requirements, contractual work, required
training, relocation request work, and the like. Other factors include customer growth requirements,
repairing storm and weather damage, and operating this complex system.

Vegetation Management

Vegetation is a significant source of outages for utilities. At Avista, typically
about 8% of outages result from trees, tree limbs, or other vegetation
falling or growing into power lines, and the resulting impact is significant.
Since 2001, vegetation issues have led to over 1.3 million hours of
customer outages. In 2019 alone vegetation caused the loss of 109,000
customer service hours. Recent years have shown that vegetation issues
also create potentially explosive wildfire situations. Avista takes this issue
very seriously and has developed a robust vegetation management
program in response.

The Company manages vegetation across the rights-of way of 19,000 miles
of overhead electric distribution lines and 2,770 miles of 115 kV and 230 kV
transmission corridors.10 In recent years the Transmission Vegetation
10 From Avista Quick Facts, https://investor.avistacorp.com/static-files/a7342b27-72cc-44d4-b9a7-b62903e999df
Avista’s Distribution O&M Investments

Figure 13. Distribution O&M Expenditures 2009-2019

Figure 13. Distribution O&M Expenditures 2009-2019
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 23 of 28
Management Program was rolled into the Distribution Vegetation Management Program, so there is
now a single program under one business unit. This program utilizes a three-pronged proactive
approach to try to identify and address potential vegetation-related issues before they result in
outages for our customers:

• Routine Cycle Maintenance is planned on a five year cycle and is
focused on trimming practices that are tailored to the type of
landscape and species of trees along our rights of way, identifying
“problem trees” that require the most attention. This approach allows
Avista to maximize the efficiency of the work crews; they focus on
areas most likely to cause a problem, then customize work cycles for
trimming based upon tree and vegetation type and physical location.
For example, some species of tree can be allowed a fifteen foot
clearance (fast growing species), others (slow growers) can be allowed
within five feet of power lines. Another part of this routine work involves the targeted removal of
individual trees that Avista refers to as “cycle busters,” meaning they will grow quickly enough to
require an additional trim during the middle of the cycle interval, which is very inefficient and
expensive. Often the Company will replace a “cycle buster” tree with a tree species that will not
ever reach a height to pose reliability problems for the overhead feeder line.
• Risk Tree Mitigation targets individual trees that pose a hazard based on their potential to either fall
across or to grow into lines during the cycle interval. These trees are typically identified by certified
utility foresters or by others on the ground who spot dead, diseased and dying trees as they
perform work in the field. Once identified, the health of these individual trees is tracked to
determine whether they need to be removed and, if so, when this should occur. The cycle of
removal for these risk trees is “as needed,” based on the risks the individual trees pose as they age.
• Right of Way Clearing involves the physical removal of brush and undergrowth on the feeder right-
of-way using heavy mowing equipment and the selective
application of herbicides. This work is tailored to the
characteristics and needs of each area as needed. Avista
completes this work on approximately 1,200 – 1,500 circuit
miles each year,
generally during the
months of May
through October.
Performing this work
on a regular periodic
basis prevents the
undergrowth from
reaching the point
where a more
expensive complete
trimming and removal is needed to safely clear the feeder right of way.

Above: Before Vegetation
Management Work Begins
Left: After Work is Complete

Distribution
Upcoming
ProgramsAbove: Before
Vegetation Management
Work Begins
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 24 of 28

Padmount Inspection Program

The Padmount Distribution Facilities Inspection Program provides a ten-year physical inspection of
padmount transformers and junction enclosures associated with Avista’s underground distribution
system. Avista has approximately 36,000 padmount transformers and 12,500 junction enclosures
system wide. This program was initiated in response to a request from Avista’s insurance provider,
AEGIS, to programmatically
inspect underground
distribution
enclosures/cabinets to
ensure correct labeling. Building
upon this basic request, the Company developed a robust inspection program that will examine all of
the padmount transformers and junction enclosures across the system in order to gain an initial
assessment and determination of work to be done, followed by formal inspections on a ten year cycle.
The initial inspection will begin in the first quarter of 2020. This program will address three primary
concerns with these units: proper labeling, physical integrity/security and age. It is important to note
that these transformers are readily accessible to the public, with many located in yards, playgrounds,
commercial parking lots, on sidewalks, and other public places. Thus public safety is a significant
concern.

Correct labeling and markings of padmount transformers
is required by law and by internal Company standards.11
In 2013 the Company sampled 474 transformers and 120
junction enclosures and found significant failures in
several areas especially in decals, as shown in Figure 14.

The second focus of this program is
the physical security and integrity of
the cabinets and associated
mountings. Clearance violations
such as the boulders shown in the
photo on the left limit accessibility,
especially in an emergency
situation, but also for routine maintenance activities. These units sit on concrete pads to keep them off
11 WAC 296-24-95605 (http://lawfilesext.leg.wa.gov/law/wsr/2012/16/12-16-064.htm) provides direction for marking the exterior of padmount transformers
used in underground distribution applications. These warning markings are prescribed for the safety of the general public as well as utility crews who will
be working with the equipment. This code also provides direction for ensuring that the area around the padmount equipment is kept free from obstruction
so that the equipment can be accessed for maintenance or replacement. Additional markings are defined by Avista Utilities construction standards to aid
in location and identification of equipment by service crews.
Figure 14. Padmount Transformer Issues Identified
This program addresses
required labeling such as
the transformer decal
above and access issues
such as the boulders
blocking access to the
transformer on the left.
Distribution Upcoming Programs

Illegible / Missing
Decals
Clearance
Violations Failed Pads Failed Tamper
Resistance Bolt
Paint
Failure
Failure
Percentage 96%35%3%8% 8%
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 25 of 28
the ground and out of the elements as well as to keep them level
to prevent oil leakage. The survey found many of the pads had
settled over time and cracked or even broken open. Tamper-
resistant bolts are used to secure the box cover in place and to
prevent unauthorized access. The survey found that many of these
bolts were either stripped, broken off, or missing. Paint condition
is also a concern, as degradation to the paint can create rust and
corrosion, giving public or animals access to the electrical
equipment inside the enclosure and creating a potential safety risk
for both the equipment and the public.

The third element addressed by this program is the transformer age. About 4% of the padmount
transformers are 40 years of age or older, thus past their expected service life. But nearly 20% are 30
or more years of age, thus rapidly approaching end of life.

Wildfire Resiliency Program

Wildfire represents a significant risk for western utilities.
Avista is developing a comprehensive wildfire resiliency plan to
address this risk and to
support three strategic
goals: enhancing
emergency operations,
promoting public safety,
and safeguarding
Company assets. To
achieve these significant
goals, the Company is
focusing on three primary
areas:

1) Protect lives and property
2) Ensure emergency preparedness & align
operating practices with fire threat conditions
3) Protect Avista’s energy delivery infrastructure

The primary elements of this plan include:

• Enhanced Vegetation Management to reduce the likelihood of wildfire events through fuel
reduction treatments as well as including extensive associated data collection, identifying high
risk areas in Avista’s system. Also includes partnering with associated state and local entities,
Padmount Transformers

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 26 of 28
widening transmission rights-of-way, and public outreach to encourage removal of high risk
trees.

• Situational Awareness to provide more
information about the status of the
system including adding specialized
communications capability (SCADA) to
every substation to monitor and
control powerlines, developing a web-
based fire weather dashboard, and
adding distribution protection
technology.

• Grid Hardening and Dry Land Mode
which adds a non-reclosing protection
mechanism during dry weather high-
fire-danger conditions that prevents lines that trip out of service from reclosing without specific
intervention. It also includes putting eyes on a potentially dangerous situation to make sure it is
safe to place a line back in service, either with servicemen dispatched to the situation or with
SCADA information.12 First responders count on Avista’s ability to de-energize electric lines
during fire events, making this technology even more crucial to public safety. This element also
includes adding a specialized fire retardant mesh to transmission wood poles in high risk areas,
more in-depth aerial inspections, conversion of wood transmission poles to steel in high risk
areas, and replacing equipment in the distribution system associated with spark-ignition
potential.

• Operations and Emergency Response to combine the current programs related to wildfire into a
comprehensive and overarching effort with associated metrics and analytics. This piece will
include a more comprehensive Company focus on wildfire events and risk, provide specialized
training for first responders both inside and outside the Company, and agreements with
external fire personnel to investigate transmission line faults during fire season.

This comprehensive wildfire program is scheduled to take place over the next ten years and will
require new equipment such as the SCADA equipment mentioned earlier, software monitoring and
tracking systems, and extensive inspections of the entire system to identify vegetation related trouble
spots. It is estimated that this program will cost $242 million in capital, $43 million in O&M over the
next ten years. This investment will also include funds Avista provides to local efforts. The Company
will be partnering with fire districts, the U.S. Forest Service, the Bureau of Land Management, and
other related agencies as they work to protect infrastructure in their jurisdictions. This investment
should provide immense benefits in risk reduction and protection for Avista, its customers and
equipment.
12 Currently 33 of Avista’s 176 substations operate without SCADA and thus have no remote sensing, monitoring, or equipment control systems.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 27 of 28

Avista takes the service and safety of customers and employees very seriously. The Company’s
Distribution Team designs Capital and O&M programs that are robust, proactive, and designed to
ensure that the distribution system is as safe as it can possibly be while providing a level of service and
cost effectiveness that customers and regulators expect. As depicted in this report, each of these
programs has a specific goal and purpose in serving customers safely and successfully, including
inspecting and protecting existing infrastructure, thoughtful, measured replacement of end-of-life
assets, adding equipment to allow additional monitoring and control, providing additional service to
customers as requested, maintaining full compliance with all legal and regulatory standards, and
reacting to damage or repair as needed. These programs balance all of these needs while providing a
critical service to customers in a reliable, cost effective manner.

Wrap Up
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 1, Page 28 of 28
Avista Utilities
Substation Infrastructure Plan
2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 1 of 26

Table of Contents

Executive Summary ..................................................................................................................................... 2
Introduction ................................................................................................................................................ 4
Avista Substation Capital Investments ....................................................................................................... 8
Classification of Infrastructure Need by Investment Drivers ................................................................. 8
Overview of Currently Planned Capital Investments in Substations 2020 – 2024 ............................... 11
Planned Capital Investments ................................................................................................................ 13
Customer Requested ........................................................................................................................ 13
Mandatory & Compliance ................................................................................................................. 14
Failed Plant & Operations ................................................................................................................. 18
Asset Condition ................................................................................................................................. 19
Performance & Capacity ................................................................................................................... 20
Operations & Maintenance Expenditures ............................................................................................ 22
Summary ................................................................................................................................................... 23
Appendix A: Avista’s Substations .............................................................................................................. 23

Table of Figures

Figure 1. Total Substation Planned Capital Expenditures by Investment Driver .........................................................8
Figure 2. Substation Planned Capital Budget by Business Driver 2020 – 2024 ........................................................ 10
Figure 3. Planned Capital Substation-Related Expenditures by Investment Driver 2020-2024 ................................. 11
Figure 4. Historic Substation Capital Expenditures 2008 – 2019 .............................................................................. 11
Figure 5. Substation O&M Expenditures 2008-2019 ................................................................................................. 22
Figure 6. Primary Substation O&M Expenditures 2008 - 2019 .................................................................................. 22

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 2 of 26

The Substations group is heavily impacted by the same factors driving investments in all of the other
areas of the Company as well as utilities across the nation: continually increasing regulations from the
federal to the local level, aging infrastructure, increasing customer demands for reliability, changing
technology, and increasingly complex siting issues and construction permitting to name a few.

Substations and their associated equipment are critical to the integrity of the grid. The Federal Energy
Regulatory Commission (FERC)1 and the North American Electric Reliability Corporation (NERC)2 are
well aware of this and have a strong focus on regulating almost every detail of substation operating,
maintenance, processes, and planning procedures as well as equipment operation and protection, all
in the service of preserving the integrity of the interconnected system. Their mandates are heavily
enforced, backed by significant fines for non-compliance.

In addition to federal regulating bodies, the electric power industry must comply with literally
hundreds of national, state and local regulations. For example, utilities are governed by laws related to
federal lands or affecting unique interests, such as culturally significant sites, environmental issues, or
endangered species. The National Electrical Safety Code defines the
rules for installation of electrical gear, electrical protection, methods
and materials and even communications for all electric utilities. The
Occupational Safety and Health Administration (OSHA) regulates
safety standards. State and local authorities and regulators focus on
facility siting and zoning, safety regulations, environmental
considerations, and more; state regulatory commissions determine
revenue requirements, allocate costs, set service quality standards and
oversee the financial responsibilities of the utility. All of these
regulators and regulations have developed over time to ensure that
people and equipment stay safe and that the lights stay on.

These mandatory standards heavily inform Avista’s decision-making
processes and behaviors. They also help to ensure that the Company’s
system is reliable, resilient, and secure. However, decisions that were
once based on qualitative risk assessment under a voluntary framework are now made based on
deterministic criteria within standards required by law, with non-compliance resulting in substantial
financial penalties. This has resulted in changes which influence the Company’s capital spending
decisions and operating practices to a significant degree.

1 The Federal Energy Regulatory Commission (FERC) oversees all electricity transmission and wholesale marketing in the United States. FERC has
regulatory authority over both the reliability of Avista’s system and the commercial aspects of Avista’s wholesale uses of its transmission.
2 FERC has assigned reliability standard development and enforcement to the North American Electric Reliability Corporation (NERC). Its purpose is to
regulate, enforce, monitor and manage the physical and logical security of systems that manage the electrical power grids.
Executive Summary
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 3 of 26
At the same time, across the nation and specifically at Avista, thousands of assets are well past their
expected lifespans, including transformers, reactors, capacitors, conductor, and poles. The Company is
replacing these assets over time and as funding allows, but concurrently the traditional utility business
is undergoing significant changes that make
this work even more pressing and challenging.
Customers are increasingly demanding
“perfect power,” meaning zero service
interruptions, due to the sensitive nature of
their technology systems and changing
perceptions of inconvenience and disruption.
This in part drives the need for new devices to
detect and automatically manage outages.

To add even more complexity to this mix,
power system requirements are changing in
directions never anticipated when the system
was built, most of it in the 1950s and 1960s.
Interconnections to private parties for integration of new variable energy resources particularly wind
and solar, distributed generation, electric vehicles, smart grid technology, customer-requested
technologies, and more require significant capital investment to extend or reinforce the electric system
in order to provide for these non-traditional uses of the power grid. The Substations team is right at
the heart of these efforts. This report describes the
capital programs that impact the Substations group,
put in place to try to address these diverse needs in the
most effective, cost-conscious way possible while
achieving the multiple objectives described above.

Burke Substation
Cabinet Sub
Metro Sub
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 4 of 26

Avista Utilities serves nearly 400,000 electric customers in Washington and Idaho over an extensive
electric system that is designed, built, operated and maintained by the Company. This infrastructure
system consists of nearly
19,000 miles of electric
distribution lines,
approximately 2,750 miles of
high voltage transmission lines3
along with 176 substations and
their associated equipment
crossing 30,000 square miles
and bringing electric power to
over 1.6 million people in
Washington and Northern
Idaho.4 Avista currently has
176 substations, including 13
generation (step-up) substations, 21 transmission and switching substations, 31 transmission with
distribution substations, 109 distribution only (step-down) substations, and two substations that are
owned by other utilities but which contain Avista equipment.

All of the various kinds of substations are designed to handle different tasks. Generation substations
take the energy from the power plant and step it up to transmission level for long distance travel to
other substations. Transmission switching stations do not reduce the power
level to distribution level, instead the lines come in and go out at high voltage,
the electricity is just rerouted in different directions,
split onto other lines, or stepped up or down in
voltage, for example from 230 kilovolt (kV) to 115
kV. Transmission with distribution subs transform
high voltage (transmission) into distribution (sub-
transmission) level voltage and send it out onto
distribution feeders. Distribution-only subs may
route distribution-level power to various feeders or
transform sub-transmission to different power levels
to suit different customer needs. Each type of
substation serves a particular purpose in serving customers.

3 This includes 700 miles of 230 kV, 1550 miles of 115 kV, and 500 miles of co-owned (Colstrip) 500 kV lines.
4 Avista Quick Facts, https://investor.avistacorp.com/static-files/a7342b27-72cc-44d4-b9a7-b62903e999df
Introduction
Coeur d'Alene 19
Colville 12
Davenport 13
Kellogg-St. Maries 13
Lewiston-Clarkston 22
Othello 12
Palouse 26
Sandpoint 13
Spokane 45
Coyote Springs 1
176
Location of Substations
13 kV 4
24 kV 1
34 kV 1
115 kV 142
230 kV 14
Generation 14
176
Substation Count by Voltage
Distribution 109
Foreign 2
Generation 13
Switching 13
Transmission 8
Transmission w/Dist.31
176
Number of Substations
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 5 of 26
Avista must continually make new investments in this system in order to continue providing customers
with safe and reliable electric service, at a reasonable cost, with service levels that meet customer’s
expectations for quality and satisfaction, and that meet stringent national, regional, state, and local
regulatory requirements.

In order to meet all of these requirements, the Company develops specific capital programs. These
programs are developed through planning and engineering studies and analyses, as well as scheduled
upgrades or replacements identified in the operations districts and within engineering groups or to
replace equipment that has been damaged or failed. Capital projects undergo internal review by
multiple stakeholders who help ensure all system needs and alternatives have been identified and
addressed. If proposed projects are initially approved, they go through a formal review process
referred to as the Engineering Roundtable, a diverse group of engineering leaders5 who track project
requests, prioritize them, and establish committed construction package dates and required in-service
dates for projects. Once a project has passed this phase of evaluation, it moves to the Capital Planning
Group.

The Capital Planning Group (CPG) is a group of Avista Directors that represent capital intensive areas of
the Company. Committee members are directors from a variety of business units to add a depth of
perspective, though their role is to consider capital decisions from the perspective of overall Company
operations and strategic goals as well as spending guidance set by senior management and approved
by the Finance Committee of the Board of Directors. They develop a final budget that represents a
reasonable balance among competing needs required to maintain the performance of Avista’s systems,
as well as prudent management of the overall enterprise in the best interest of customers.

Though all of Avista’s assets play a role in providing the electricity that ultimately reaches consumers,
in this report this discussion is confined specifically to substation facilities. All of us have passed by
substations many times in the course of our travels, filled with complicated-looking electrical
equipment and surrounded by high fences and barbed wire. They are easy to overlook and ignore, but
they touch our lives every day, playing a critical role in providing the electricity we all depend upon.
Substations play the primary role in the safe and reliable operation of the electric system, in essence
providing the physical locations to monitor and manage the grid.

5 Eleven representatives are included in this group from: Transmission and Distribution Planning, Transmission, Distribution, and Substation Design,
System Protection, System Operations, Asset Management, Communications and Generation Engineering, and Transmission Services.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 6 of 26
Before electricity can travel into your home, it must first
pass through a substation. Substations are, in fact, the very
heart of the electrical system, performing the critical
functions necessary to get electricity from a generator to
the customer. They are the center of protection and
control of the electrical system, monitoring the voltage
levels and frequency of the grid to insure they are
sufficient, providing breakers to isolate faults, routing the
power to where it is needed, and switching transmission
and distribution lines in and out of service for maintenance
and to serve customer loads.

Substations are also connection points. One of the most
important and obvious connections is between the
generator and the customer. Electricity is created at the
generator, which passes it to a transmission substation
where it is stepped-up to the high voltage level required
for it to be conveyed long distance on transmission lines to
the load source. This high-voltage electricity cannot be
used in most homes and businesses. Voltage is like
pressure, and high-voltage electricity has too much
pressure to run everyday things. A residential customer’s
voltage need is only 120 volts. The voltage level of a
transmission line is typically 115,000 volts or more to
minimize line losses. This level is unusable for most end-
use applications. Trying to use power at that level for all
but extremely high-level industrial customers would be like
trying to fill water glass with a fire hose. To deal with this
challenge, the transmission line carries the electricity to a
substation. The substation takes the electricity provided by
the line and steps it down to the distribution level using a
transformer. After converting the electricity to a usable
level, the substation transfers the lower voltage electricity
to the distribution system. Thus, the substation is vital to
the functionality of the entire power system as the means
by which power can be delivered to the customer in a form
they can use.

Another substation function is splitting the power off in
different directions, sending it onto different transmission
or distribution lines for delivery to where it is needed.
Changing voltage from one level to
another

Controlling the flow of electricity in various
directions and onto various lines; splits the
electricity out onto various feeders

Providing circuit breakers to protect the
system from faults

Protecting the transmission system by
insuring proper voltage levels and
frequency

Regulating voltage to compensate for
changes due to fluctuating load,
unexpected equipment failures, etc.

Switching transmission and distribution
circuits into and out of the grid system for
maintenance or to meet other system
conditions

Measuring the electric power quantities
flowing in the circuits

Connecting communication signals to the
circuits

Eliminating surges from the system caused
by lightning or other electrical conditions

Connecting electric generation plants to
the grid

Correcting reactive power flows to insure
voltage is stable

Creating interconnections and controlling
the electricity flow between electric
systems of more than one utility

Data transmission and communications

General control and protection

Fault analysis and pinpointing the location
of a fault

Providing the ability to shed load in a
controlled fashion if demand exceeds
power supply

SUBSTATION FUNCTIONS
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 7 of 26
Substations also provide a place for interconnections between different utilities in the grid, enabling
them to buy and sell power to or from one another.

Substations are designed to provide switching, which is the connecting and disconnecting of
transmission and distribution lines or other components to and from the system. An example of this
function is switching the electricity from a line that is de-energized to another line or lines to keep the
power flowing to customers, which helps maintain system reliability. Switching is used if a line needs to
be de-energized for maintenance, due to a fault, to move power to a different location, or for new
construction.

One of the highest priorities in a substation is to detect and isolate failures in the transmission system
as quickly as possible. Short circuits or overloaded currents on a transmission line feeding a large
substation can leave thousands of people without electricity. To protect against such an event,
substations have specialized equipment to monitor, manage and protect the transmission system so
the power can continue to flow. Substation equipment can isolate a faulted area so the rest of the
system continues to function normally.

This report provides a summary overview of Avista’s substations and the way the Company manages
and invests in these critical assets and their associated equipment. Collectively these historic, current,
and planned investments allow Avista to effectively respond to customer needs and expectations,
provide service enhancements, meet regulatory and other mandatory obligations, replace equipment
that is damaged or fails, support electric operations, address
system performance and capacity issues, support the
interconnected grid, and replace infrastructure at the end of
its useful life based on asset condition. The investments
described in this plan are based on what we know about the
business today, including a range of precision in future cost
estimates, applicable laws, regulatory requirements, and the
capabilities of current technologies.

For more information
about substations, their
associated equipment,
functions, and a glossary
of terms, please see the
2019 Electric Substation
Infrastructure Plan
located on the Company’s
internal website6 or as a
hardcopy available upon
request.
6 On the Avenue under “Tools and Resources” then “Avista Infrastructure Plans.”
Above: Work at Cabinet Sub
Left: Inside Post Street Sub
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 8 of 26

Classification of Infrastructure Need by Investment Drivers

As a way to create more transparency around the particular needs being addressed with each capital
investment as well as simplify the organization and understanding of overall project plans, the
Company has developed “investment drivers” to classify its capital projects. These drivers are broad
categories that attempt to sort projects by
the need they are addressing, as described
below:

1. Customer Requested – This category is
primarily related to customer growth,
but also provides funding to enhance
customer service as requested. The
Company must build new or upgrade
existing substations in response to
changes in load or consumption patterns.
This category also includes funding related
to requested interconnections of third party resource developers such as the Lind Solar Project
and the Rattlesnake Flat Wind Project.

2. Mandatory & Compliance – The Company makes a large number of business decisions as a direct
result of compliance with laws, mandatory standards, safety codes, contracts, and agreements.
An example is control equipment required by NERC to preserve and monitor the reliability of the
interconnected grid or to replace equipment that is exceeding thermal limits, as substations are a
key part of maintaining system reliability.
Projects in this category are primarily driven
by external requirements that are largely
beyond the Company’s control, such as
building the Saddle Mountain Substation,
required to meet NERC grid stability
requirements, as well as construction of the
West Plains Substation and the
reinforcement of the Ninth and Central and
Westside Substations, again required by
NERC related to remediating system
reliability issues.

Figure 1. Total Substation Planned Capital Expenditures by
Investment Driver
Avista Substation Capital Investments
Installation of new autotransformer at Westside Sub
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 9 of 26
3. Failed Plant & Operations – This category sets aside funds which allow the Company to replace
failed equipment and support ongoing utility
operations as assets are damaged or no longer provide
adequate functionality. Often these expenditures are
the result of storm damage, but they can also be
required by other unexpected equipment failures,
animal or human-caused damage, and the like. In
Substations, Failed Plant and Operations dollars are
combined with funds for planned and unplanned failed
plant in the Substations Rebuilds Business Case, which
is held under the Asset Condition business driver.

4. Asset Condition – All assets have a defined
useful service life. This category provides funding
to replace equipment as needed so the system
can continue to function effectively. This may
include replacing parts as they wear out or when
items can no longer meet their required purpose,
as systems become obsolete and replacement
parts are no longer available, to remedy safety or
environmental issues, or if the condition of an
asset is such that it is no longer optimizing its own
performance or customer value. The Company
also proactively replaces critical equipment to
mitigate the risk of failure.

5. Customer Service Quality & Reliability – This category is for costs related to meeting customers’
expectations for quality of service and electric system reliability. Substations does not have any
specific dollars set aside under this category, as this is primarily a function of Distribution. An
example of this type of expenditure is Distribution’s programs to replace old style streetlights with
energy-efficient LED lights. Another example is Avista’s installation of smart meters to provide
customers the ability to manage their energy usage, among many other benefits.7

6. Performance & Capacity – Programs in this category ensure that the Company’s assets satisfy
business needs and meet performance standards, typically defined by Company experts or in line
with industry expectations. Some examples include adding redundant distribution feeders to
reduce the impact of outages on customers, replacing equipment that is not functioning at
nominal levels, or adding monitoring capability to enable viewing critical equipment in real time.
This category is also used to add new substations or upgrade existing stations to manage customer
7 Customer benefits include providing customers access to their energy usage to allow managing it and controlling costs, energy alerts, billing accuracy,
support for customer “smart home” technology, and more.
Post Street Sub receives a new transformer to replace one
that reached end-of-life

Post Street Sub receives a new transformer to replace one
that reached end-of-life
Animal-caused damage at Deer Park Substation
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 10 of 26
load growth/change. During this
budgeting cycle, funding has been set
aside to add new transmission lines
to the Mead, Colbert, and Milan
substations for service redundancy
and the resulting improvement in
customer reliability.8

Note that not all investment driver categories are utilized in all Avista’s business units. For example,
electric Distribution includes budgets in all six categories listed above; however, investments planned
for Substations during the upcoming five-year planning cycle do not include any specific projects in the
category of Customer Service Quality & Reliability or Failed Plant & Operations. It is also important to
note that some projects may resolve issues under more than
one investment driver category.

While projects are categorized by a principal investment driver,
a project that resolves multiple issues may be prioritized
differently than it would be if it fell fully under a
single investment driver category. For example, investments in
Substations related directly to service reliability for all
customers are generally
driven by mandatory
compliance requirements, so they can be found in the
“Mandatory & Compliance” driver even though the project may
also provide more dependable customer service. Though the
Substations team implements the T&D projects that impact
substations and associated apparatus, these expenditures are
typically dictated by Transmission and Distribution projects,
thus many of the Substation business cases are the same ones
listed in those reports.
8 These projects are under the “Transmission New Construction” subcategory of Performance and Capacity and are share with the Transmission Group.
Building the Opportunity Substation in Spokane to manage customer growth
Business Driver 2020 2021 2022 2023 2024 Five Year Total Five Year Ave.
Customer Requested $2,225,000 $0 $0 $0 $0 $2,225,000 $445,000
Mandatory & Compliance $10,000,000 $15,900,000 $5,300,000 $1,650,000 $24,000,000 $56,850,000 $11,370,000
Asset Condition $2,450,000 $1,670,000 $1,600,000 $2,900,000 $1,550,000 $10,170,000 $2,034,000
Performance & Capacity $500,000 $1,800,000 $1,000,000 $11,900,000 $14,150,000 $29,350,000 $5,870,000
Total $15,175,000 $19,370,000 $7,900,000 $16,450,000 $39,700,000 $98,595,000 $19,719,000
Rockford Substation

Work at the Kooskia
Substation

Figure 2.
Substation
Planned
Capital Budget
by Business
Driver 2020 –
2024Rockford
Substation

Work at the Kooskia
Substation
Figure 2. Substation Planned Capital Budget by Business Driver 2020 – 2024
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 11 of 26
Overview of Currently Planned Capital Investments in
Substations 2020 – 2024

Substation construction and maintenance
activities are heavily regulated by state,
regional and federal agencies that
implement compliance standards, safety
requirements, work activities, thermal
limits, and the like. These rules govern
when equipment must be replaced, how
it must be monitored and maintained,
operating characteristics and limits, and
even cyber and physical security.
Compliance with these mandatory
standards is not optional and drives a
number of the Company’s investment
decisions. This is clearly reflected in the
expenditures the Substations team expects during the upcoming budget cycle and into the future.

This focus on compliance makes sense, as substations are the key to a utility’s ability to serve
customers. Equipment must be replaced or upgraded as loads grow or load patterns change, when
equipment wears out or no longer functions to prescribed levels, to address potential outage or safety
issues, to deal with equipment that is exceeding its tolerances, and to maintain the high level of
reliability the Company and its customers expect. In addition, customers can request service that may
require a new substation or adding capacity to an existing station, such as a wind project, a new
subdivision, or a new manufacturing facility that require new or more robust substations.9
9 Misc. Equipment includes batteries, reclosers, fuses, switches, metering, voltage regulators, and technology equipment.
Figure 3. Planned Capital Substation-Related Expenditures by Investment Driver 2020-2024
Figure 4. Historic Substation Capital Expenditures 2008 – 2019 9
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 12 of 26
The Substations group is in the middle of all of these mandates and requirements, constantly
monitoring the health and effectiveness of their equipment,
rebuilding old substations to meet current standards or needs,
constructing new substations as needed to manage loads and
system stability, and adding equipment or replacing it as necessary.
These crews also manage the substation property, insuring fences
and gates are secure, installing security systems, and maintaining
the associated substation yard and buildings. This team also installs
and manages system protection
and communication equipment,
ensuring it is kept in working
order so the Company can keep
an eye on the operation of the
system as well as detect
equipment performance issues
or be alerted to unauthorized
intrusion.

As can be seen in Figure 4 above, rebuilding old substations (some built in the early 1900s) to replace
aging equipment has been a major driver in Substation expenditures. This is required in order to
handle growing demands as well as to stay in compliance with increasing numbers of stringent federal
regulations, which include requirements for more
monitoring, control and security measures, as well as
replacing aging or undersized transformers to maintain
reliability. These three requirements dominate Substations
capital expenditures.10

Over the
current five-
year planning
horizon,
Avista
expects to
spend nearly $100 million for substation-related capital
investments. Note that this figure includes some
Transmission projects, as these projects are planned by
Transmission but implemented by Substations.11

10 Note in Figure 5 the “Misc. Equipment” category includes batteries, communications equipment, fuses, grounds, meters, reclosers, regulators, relays,
and switches.
11 The sister Transmission Infrastructure to this report can be found on the Company’s internal website, the Avenue, under “Tools & Resources” in ‘Avista
Infrastructure Plans” for more information about Transmission capital expenditures.
Above: Break-in at Garden Springs Sub
Left: Security at Northeast Substation
Transient issues at the 3rd & Hatch Substation
Salvaging the old transformer at Benewah in 2010
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 13 of 26
Planned Capital Investments

Customer Requested

Responding quickly to customer requests is a requirement of providing utility service. Customer
requested activities are typically limited to the electric distribution system, but may be extended to
include substation infrastructure and dedicated high voltage transmission facilities. The Company must
also upgrade existing substations or build new ones in response to customer growth or at the request
of generation resource developers such as the one described below.12

Rattlesnake Flat Wind Project

Avista issued a request for proposal in June 2018 for additional renewable energy. An external
company, Clearway Energy Group, was selected to provide this resource. Clearway is developing a
wind power facility known as Rattlesnake Flat Wind, which is projected to provide Avista with
approximately 50 average megawatts of
renewable energy, or as much as 144 megawatts
of nameplate wind capacity, under a 20-year
power purchase agreement with deliveries
beginning in 2020. This project, including 90 wind
turbines and associated facilities, is located on
approximately 23,000 acres in Adams County,
Washington. This project requires significant
upgrades to Avista’s existing infrastructure in
order to allow this new generation to be added to
the power grid. The required work includes
rebuilding nearly 27 miles of 115 kV transmission
including distribution underbuild and optical
ground wire. It also necessitates a
new substation (Neilson) with
adequate protection, control and
communications equipment, as well
as upgrades to three existing
substations13 to handle the increased
system demands this project will
create. This business case is part of
the same Transmission business case.
12 Purchasing qualifying output from independent power producers and providing the transmission, substations, and other necessary equipment to allow
this projects to connect to the grid is required by law. http://app.leg.wa.gov/WAC/default.aspx?dispo=true&cite=480-107
13 The substations requiring capacity upgrades include Lind, Warden, and the Othello Switching Station as well as replacement of the circuit switcher at
Roxboro. The developer is responsible for a portion of the cost of this project.
Rattlesnake Flat Wind Turbine Design
Building the new Neilson Substation to add the Rattlesnake Flat Wind
generation to the power grid
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 14 of 26
Mandatory & Compliance

Avista operates in a complex regulatory and business framework and must adhere to national and
state laws, state and federal agency rules and regulations, and county and municipal ordinances which
drive much of the Company’s capital spending requirements as mentioned earlier. Compliance with
these laws and rules, as well as with contracts and settlement agreements, represent obligations that
are generally outside of Avista’s control. The types of investments that fall into this driver include the
obligation to relocate facilities to accommodate state, county and municipal infrastructure projects
(frequently transportation related) and compliance with environmental regulations. FERC and NERC
requirements for grid stability have a significant impact on the Substations group workload and
budgets as described below.

Saddle Mountain 230/115 kV Station

Avista’s System Planning group and related outside entity studies determined that the western portion
of the Avista’s existing system is not meeting NERC performance requirements during heavy load
scenarios. The Saddle Mountain project, undertaken in two phases, will allow Avista to continue
serving Company load in the Big
Bend Area near Othello while
eliminating the pressure Avista’s
load is putting on the Grant
County Public Utility District
system. This issue will be solved
by constructing a new 230/115
kV substation where the Walla
Walla – Wanapum 230 kV and
the Benton – Othello 115 kV
transmission lines cross. This
new sub will consist of a three-
terminal 230 kV double bus
double breaker configuration,14 a 250 MVA 230/115 kV auto-transformer,15 four 115 kV breakers,
rebuilding existing aging 115 kV transmission lines, and building ten miles of new 115 kV transmission.
This project will greatly improve the reliability of transmission in the area and rem n existing single
point of failure situation which could create widespread outages in case of a fault. It also mitigates
potential thermal overloading and voltage issues in this area. This business case is part of the same
Transmission business case.

14 A double bus double breaker bus configuration consists of two main buses, each normally energized and electrically connected to each other so that if
one is removed from service by a fault or for maintenance, the other breaker continues to function so there is no interruption to service.
15 An auto-transformer is used to adjust line voltages or hold them constant, and can step up or step down voltages in the 115 kV and 230 kV range, for
example, providing a 115 kV tap from a 230 kV line.
Saddle Mountain Substation under construction

Colstrip Transmission

Colstrip Transmission

Colstrip Transmission

Saddle Mountain Substation under construction

Colstrip Transmission

Colstrip Transmission

Colstrip Transmission

Saddle Mountain Substation under construction

Colstrip Transmission

Colstrip Transmission

Colstrip Transmission

Saddle Mountain Substation under construction

Colstrip Transmission

Colstrip Transmission

Colstrip Transmission

Saddle Mountain Substation under construction

Colstrip Transmission

Colstrip Transmission

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 15 of 26
Spokane Valley Transmission Reinforcement

This project reinforces transmission in the Spokane Valley area, spurred by load growth in the region as
well as compliance with the NERC TPL-001-4 Reliability Standard16 which requires each utility to ensure
that their system is robust enough to operate reliably
over a broad spectrum of system conditions and
under a wide range of possible contingencies. Avista
system studies identified this area as requiring
additional reinforcement in order to be in
compliance with the NERC standard about ten years
ago, and the Company has been working on it since
that time. This long term project required the
construction of a new switching substation (Irvin) off
of Trent Avenue. It also includes rebuilding 4.4 miles
of the Beacon-Boulder #2 115 kV transmission line,
building 1.75 miles of transmission for the new Irvin-
Opportunity 115 kV tap, construction 2.2 miles of 115 kV transmission from the new Irvin sub to the
existing Millwood sub, and installing circuit breakers to handle the upgrades changes at the
Opportunity Sub. These changes will not only address compliance issues, but will make the
transmission system in this urban area more stable and reliable, specifically for serving large industrial
customers. This business case is part of the same Transmission business case.

West Plains New 230 kV Substation

Planning studies of the Spokane area transmission system revealed specific transmission performance
issues which will occur within the next five to ten years, including an inadequate number of
transformers. These performance issues have a significant potential to exceed NERC reliability
standards, designed to prevent cascading outages and ensure the integrity of the interconnected
system especially around thermal or voltage limit issues.17 System studies identified at least seven
NERC thermal or voltage limit violations including:

• Inadequate 230/115 kV transformation provided by the four existing substations in the area,
especially in the case of system events. Existing transformers are reaching maximum thermal
capacity now and in time will exceed it.
• Related 115 kV transmission lines are running at 96% to 135% of their rated capacity during
specific contingency scenarios.18

16 NERC Standard TPL-001-4: http://www.nerc.com/files/tpl-001-4.pdf requires the Company to avoid load loss and have circuit breakers with sufficient
interrupting capability for faults.
17 NERC Reliability Guidelines, September 2018,
https://www.nerc.com/comm/PC_Reliability_Guidelines_DL/Reliability_Guideline_Methods_for_Establishing_IROLs.pdf. Non-compliance with NERC
directives can lead to fines of up to $1 million per day until the violation is rectified.
18 This includes the Northwest-Westside 115 kV, the Bell-Northeast Waikiki Tap 115 kV lines, and the lines from the Beacon and Westside substations.
Site of new Irvin Substation in Spokane Valley

North Lewiston Reactors help regulate the voltage and
reactive power in this area

Site of new Irvin Substation in Spokane Valley

North Lewiston Reactors help regulate the voltage and
reactive power in this area

Site of new Irvin Substation in Spokane Valley

North Lewiston Reactors help regulate the voltage and
reactive power in this area

Site of new Irvin Substation in Spokane Valley

North Lewiston Reactors help regulate the voltage and
reactive power in this area

Site of new Irvin Substation in Spokane Valley

North Lewiston Reactors help regulate the voltage and
reactive power in this area

Site of new Irvin Substation in Spokane Valley

North Lewiston Reactors help regulate the voltage and
reactive power in this area

Site of new Irvin Substation in Spokane Valley

North Lewiston Reactors help regulate the voltage and
reactive power in this area

Site of new Irvin Substation in Spokane Valley

North Lewiston Reactors help regulate the voltage and
reactive power in this area

Site of new Irvin Substation in Spokane Valley

Trent Avenue
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 16 of 26
These issues are expected to intensify with projected growth in this region. In addition, some of the
transmission lines in the Spokane area are radial lines, requiring manual intervention in order to
restore service to customers after a fault, with a total customer exposure of up to 31 miles. In order to
manage this situation and remain in compliance with NERC directives, the Company is planning to
construct a new 230 kV substation in the West Plains area. The Company selected this property at the
convergence of two major transmission lines to provide maximum value for this new substation. No
new transmission lines will need to be built; the existing lines along with this new substation will
address the transmission performance issues. This location also provides an opportunity to
interconnect with a 230 kV line owned by Bonneville Power Administration, strengthening Avista’s grid
and adding additional operating flexibility. The West Plains Substation is designed to mitigate all of the
identified system deficiencies, including adding 500 MVA of transformer capability and redundancy to
the transmission system in this area. This business case is part of the same Transmission business case.

Ninth & Central 230 kV Station & Transmission

The Spokane area transmission system is heavily dependent upon the Beacon Substation, which is
networked to the Bell Substation as well
as eight 115 kV transmission lines. In
order to reduce this dependency, create
redundancy, enhance customer
reliability, and remain in compliance
with mandatory standards, Avista is
planning on upgrading the
infrastructure of the Ninth & Central
Substation to provide a more robust
and dependable infrastructure for the
Spokane area. The Company is adding
new 230 kV infrastructure to
accommodate a 230/115 kV auto-transformer and associated circuit
breakers, and putting in place additional transformer capacity for the Spokane transmission system.
This project will also build eight miles of new transmission lines, utilizing existing 115 kV corridors in a
double circuit configuration in order to fortify
the Spokane area transmission system
without increasing the transmission footprint
through the area. This project significantly
strengthens the electric system in the
Spokane area, especially in the South Hill
region. This business case is part of the same
Transmission business case.

Ninth & Central transmission line

North Lewiston Reactors help regulate the voltage and
reactive power in this area

Ninth & Central transmission line

Work on the Ninth & Central Substation

North Lewiston Reactors help regulate
the voltage and reactive power in this
area

Work on the Ninth & Central Substation

North Lewiston Reactors help regulate
the voltage and reactive power in this
area

Work on the Ninth & Central Substation

North Lewiston Reactors help regulate
the voltage and reactive power in this
area

Work on the Ninth & Central Substation

North Lewiston Reactors help regulate
the voltage and reactive power in this
area

Work on the Ninth & Central Substation

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 17 of 26
Protection System Upgrade

NERC Reliability Standard PRC-002-219 defines the
disturbance monitoring and reporting requirements for
Bulk Electric System elements.20 This Standard requires
collecting and recording data needed to analyze
disturbances. The Standard requires 50% compliance with
these data requirements by 2020 and 100% compliance
by 2022. To achieve compliance, Avista is required to
upgrade fault recording capability at several substations
including: Beacon, Boulder, Rathdrum, Cabinet Gorge,
North Lewiston, Lolo, Pine Creek, Shawnee and Westside. This project will be ongoing until 2022.

Westside 230/115 kV Substation “Brownfield Rebuild”21

The Westside 230 kV Substation Rebuild is a major project made necessary because the existing
Westside #1 230/115 kV transformer exceeded its
applicable facility rating during heavy summer
loads, resulting in the cascading failure of the
Westside #2 230/115 kV transformer. This situation
created a compliance risk with NERC TPL-001-4, a
standard which has very specific requirements
around equipment failure that could result in
shedding customer load.22

Engineers determined that the existing old
transformers (one was manufactured in 1976 and
one in 1958) were underrated for their use and not
up to current design standards. These transformers will be replaced with 250 MVA23 rated
transformers designed for current performance and safety standards. Importantly, this replacement
will meet stringent NERC requirements related to critical equipment being operated beyond its ratings
and failing, which could ultimately impact the interconnected system.24 These types of transformers
are highly specialized, must be custom-ordered, and can take months to arrive. They weigh
approximately 170 tons (making transportation an issue) and have prices tags of approximately
19 NERC PRC-002-2 “Disturbance Monitoring & Reporting Requirements,” http://www.nerc.com/_layouts/PrintStandard.aspx?standardnumber=PRC-002-
2&title=Disturbance%20Monitoring%20and%20Reporting%20Requirements&jurisdiction=United%20States
20 NERC defines the Bulk Electric System as any transmission element operated at 100 kV or higher that has the potential to impact the grid.
21 A “Brownfield” project refers to a project that takes place on land that has been occupied by a “permanent” structure at some point, requiring
demolishing or renovating a prior structure, versus a “Greenfield” project that will be built in a place where nothing had been built before.
22 NERC TPL-001-4, http://www.nerc.com/files/tpl-001-4.pdf
23 MVA refers to the amount of power output a transformer is capable of delivering at a specified voltage under normal operating conditions without
exceeding internal temperature limitations. A 250 MVA transformer is a very large transformer.
24 “System Operating Limit Definition and Exceedance Clarification,” NERC,
https://www.nerc.com/pa/Stand/Prjct201403RvsnstoTOPandIROStndrds/2014_03_third_posting_white_paper_sol_exceedance_20141001_clean.pdf
New Westside #1 230/115 kV transformer being put into place

New Westside #1 230/115 kV transformer being put into place

New Westside #1 230/115 kV transformer being put into place

New Westside #1 230/115 kV transformer being put into place

New Westside #1 230/115 kV transformer being put into place

New Westside #1 230/115 kV transformer being put into place

New Westside #1 230/115 kV transformer being put into place

New Westside #1 230/115 kV transformer being put into place

New Westside #1 230/115 kV transformer being put into place

New Westside #1 230/115 kV transformer being put into place

New Westside #1 230/115 kV transformer being put into place

New Westside #1 230/115 kV transformer being put into place
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 18 of 26
$2,000,00025 so entail a
great deal of planning
and preparation as well
as installation time,
making this a multi-year
project.

Along with the
transformer change-
outs, numerous other
equipment
replacements are
required to have the capacity needed from this station. To maximize the value the construction time,
failing air switches and breakers at this substation will be replaced, the end-of-life protection
equipment will be updated and upgraded, oil containment provisions will be made, and site security
issues will be addressed. The 230 kV and 115 kV buses at the substation will be upgraded to a double
bus double breaker configuration to provide adequate redundancy. This project, started in 2016,
should be completed during the current budget cycle. This business case is part of the same
Transmission business case.

Failed Plant & Operations

While large-scale outages are vividly remembered by both Avista
employees and customers, the Company responds to thousands of
outage events each year that occur almost every day of the year. The
replacement of assets due to equipment failure or outage events,
however, is only one component of the investments required to
operate the electric system. In
addition to outage response, Avista’s
nominal operations involve
reconfiguration and replacement of
electric facilities under a variety of
circumstances. Causes of damage to
the system include weather events,
lightning, fire, snow and ice, downed
trees/vegetation, wildfires, human or animal caused damage, and equipment failure. Other failures
include the unanticipated loss of assets due to a range of factors including age and condition. Funding
in this category is split between Transmission and Distribution, but often it is the Substations group
that performs many of the repairs, replacements, and upgrades.
25 U.S. Department of Energy, “Large Power Transformers and the U.S. Electric Grid,” 2012,
https://www.wecc.biz/Reliability/2014_TEPPC_Transmission_CapCost_Report_B+V.pdf, page 7.
Above: Warden Switching Station
failed PT
Left: Circuit switch failure at
Gifford Sub
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 19 of 26
Asset Condition

Assets of every type will degrade with age, usage and other factors, and must be replaced or
substantially rebuilt at some point in order to ensure continuation of service. Across the utility industry
and likewise for Avista, the
replacement of assets based on
condition constitutes a substantial
portion of the infrastructure
investments made each year. At
Avista, asset replacement strategies
are “optimized” in the sense that a
given approach may not achieve the
overall lowest possible lifecycle cost,
but rather the lowest cost that allows
meeting a variety of important
performance objectives, such as
electric system reliability or the
efficient use of employee crews.

Because failure of some critical assets
is unacceptable, they must be replaced near the end of their
useful life even if they are still providing reliable service to proactively prevent
outages. In other instances it may be reasonable and economical to wait until an
asset fails before it is replaced, a strategy known as “run to failure.” The Company
sets aside funding to provide for swapping out old substation equipment as it
reaches the end of its useful life, no longer meets
performance requirements, becomes a safety hazard,
is creating outages, or is so critical to operations that it
must be replaced prior to failure. The Asset Condition
category is a major focus for the Substations group, as
they are continuously rebuilding, replacing, upgrading
and repairing equipment to keep the system operating
at optimal performance levels. Some of their specific
programs in this category are described below.

Failed cable at
Moscow City Sub

Failed cable at
Moscow City Sub

Switchyard equipment failure at Little Falls

Switchyard equipment failure at Little Falls

Switchyard equipment failure at Little Falls

Switchyard equipment failure at Little Falls

Switchyard equipment failure at Little Falls

Switchyard equipment failure at Little Falls

Switchyard equipment failure at Little Falls

Switchyard equipment failure at Little Falls

Switchyard equipment failure at Little Falls

Switchyard equipment failure at Little Falls

Switchyard equipment failure at Little Falls

Post Street Substation Wall

Post Street Substation Wall
South Othello circuit switch
interrupter failure

South Othello circuit switch
interrupter failure
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 20 of 26
Substations Rebuild Program

Investments in this program include updating old
equipment to meet new safety and construction
standards, installing communications systems
(often in response to NERC directives), and
replacing or upgrading other equipment such as
circuit breakers, reclosers, switches, capacitor
banks, transformers, and regulators. In addition,
supporting equipment like relays, meters,
batteries, panel housing, and fences must be
replaced or rebuilt periodically to ensure the full
functionality and safety of Avista’s substations.
Other projects in this category include rebuilding some of the Company’s older wood substations,
replacing or improving equipment at others, or increasing the capabilities of a substation due to
growth or load changes in the area. Please note that capital allocated for this program is shared
between Transmission, Substations, and Distribution though Transmission creates and manages this
program.

Performance & Capacity

Avista’s projects and programs grouped in this category of need include a range of investments that
address the capability of assets to meet defined performance standards, typically developed by the
Company, or to maintain or enhance the performance level of assets based on a demonstrated need or
analysis. Substations projects in this category are typically related to system reliability, as substations
are the primary provider of system protection. Projects may include replacing circuit breakers that are
not performing to optimum protection levels or adding automation that instantly responds to and
mitigates system issues. Other projects include adding redundancy to transmission and distribution
lines to provide substations with the ability to switch lines to continue service when a fault occurs. In
addition, this category incorporates customer growth-required substation equipment and upgrades.

Cabinet Gorge 230 kV Add Bus Isolating Breakers

The existing circuit breaker arrangement at the Cabinet
Gorge substation causes a fault to trip off all four of the
hydro units (about 260 megawatts), as well as trip both
230 kV lines and the primary 115 kV transmission line
into Sandpoint. In the past this type of fault was an
unusual occurrence so resolving the problem was not a
high priority, but recently the number of these outages Cabinet Gorge 230 kV Substation breakers
Work on the Lee & Reynolds Substation in 2018
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 21 of 26
has increased, resulting in seven NERC Event Reports so far
and driving the need to resolve this reliability issue as quickly
as possible. The Company plans to install two breakers to
separate the 230 kV bus at Cabinet from the generation step-
up transformers to isolate the impact of faults across the bus
and reduce the large scale impact currently experienced. Relay
protection will also be added. This business case is part of the
same Transmission business case.

Substation – New Distribution Station Capacity

Adding new substations for load growth and reliability is critical to the long term safe, dependable, and
cost-effective operation of the system. As load demands change and increase and customer
expectations related to reliability also continue to increase, incremental substation capacity is required
to serve those demands. Funding under this category is based on the historical experience of needing
to add approximately two new substations to the system per year or to rebuild/upgrade existing
substations to ensure that the system is growing at an adequate pace to maintain the expected level of
service and reliability.

During the upcoming five year budget cycle, this program will fund upgrades to Spokane area
substations to handle the increased load growth and add needed redundancy to the distribution
system there. These changes will improve operational flexibility, allowing loads to be shifted to other
lines in case of a fault or maintenance, maintaining continuous customer service through these types
of events. The capital allocated to this program is shared between Transmission, Substations, and
Distribution.

Transmission New Construction

Investments made under this
program support the addition of new
substations due to load growth in a
particular area or to reinforce existing
substations with new transmission
required for increased performance,
system stability, or customer service
reliability. Funding in this category is
also used to provide redundant feeds to radially-fed substations, reducing the potential for customer
outages. This program is managed through the joint efforts of Avista’s Transmission Design &
Engineering, Substations, Operations, and Transmission Planning groups, from which the requests for
upgrades or additions are initiated.
Cabinet Gorge 230 kV Substation breakers
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 22 of 26
Operations & Maintenance Expenditures

Avista’s Substations employees are
responsible for maintenance activities that
involve Generation, Distribution, and
Transmission assets. These employees are
crucial to maintaining the integral
equipment that transfers electricity to the
end customer. Over the past decade,
Substations has typically spent about $1.3
million per year26 on a huge variety of
operations and maintenance related tasks
including servicing power lines,
transformers, breakers, regulators and even
the fences and grounds under and around their substations. The highly specialized and sophisticated
equipment they maintain, repair, and install requires continual upkeep – checking the oil levels and
quality, ensuring that breakers work when they are needed, repairing damaged equipment, and
replacing blown fuses and dead batteries to name a few.

As an example, transformers are critical to grid operations and reliable power supply. Their failure can
pose a variety of unsafe conditions, lead to extended outages for customers, and impose
extraordinarily high costs on the utility for replacement. Therefore routine maintenance, diagnostic
testing, and insuring proper operation of this equipment is of paramount importance. Equipment must
be kept cool, leaks must be repaired, and equipment must be cleaned to protect against arcing. As can
be seen in Figure 6, there is a great deal of work to be done in maintaining the substations portion of
the power system.

Even beyond the major projects shown in Figure 6, there
are constant small projects that must be managed.
Substation buildings contain critical equipment that must
be kept cool in hot summer months (fans and HVAC
systems), wildlife guards are installed to reduce the
number of outages caused by birds and squirrels, weeds
must be kept at a minimum to avoid arcing. This group
also utilizes specialized equipment to monitor and test
equipment. One of the many ways they do this is with
infrared imaging to identify hot spots in transformers. All
of this work is in the service of preventing outages and
maintaining system stability.
26 This average has dropped to approximately a million dollars per year over the past five years as the Company reduces O&M expenditures. Note that the
required work does not go away, but is only postponed when budgets are reduced.
Figure 5. Substation O&M Expenditures 2008-2019
Figure 6. Primary Substation O&M Expenditures
2008 - 2019
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 23 of 26

Avista’s substations are the very heart of Avista’s electrical system, performing the essential functions
needed to provide power to customers. They serve a number of vital purposes. They are the focal point
for protection and control of the electrical system. They contain highly technical and specialized
equipment that monitors and maintains the voltage levels and frequency of the interconnected grid,
provide breakers to isolate faults, route power to where it is needed, switch transmission and
distribution lines in and out of service to serve loads or to perform maintenance, and transform power
to required voltage levels. Substations are the backbone of power stability and quality. They play the
primary role in the safe and reliable operation of the entire grid and are the means of getting power to
the customer.

As discussed throughout this report, substations are filled
with complex and sophisticated equipment, enabling the
utility to monitor and manage the electric system. Avista
has over 176 substations across a 30,000 square mile
service territory, each fulfilling a particular purpose.
Whether it is to step up the power from the power plant
to high voltage transmission level, re-route power lines,
manage power quality, connect to neighboring utilities, or
step down the power to distribution level, all of the Company’s substations play a central role in
protecting and maintaining the electrical system and getting the power to customers.

The Substations group is responsible for some of the most important equipment in the Company, both
for customer service and in protecting the integrity of the interconnected grid. They are intensely
focused on insuring that this equipment continues to perform reliably into the future. Avista’s
Substation Engineering team, in collaboration with the Generation Production and Substation shops,
oversees the design, testing, maintenance, repairs, rebuilds, and monitoring of all of the Company’s
substations and associated equipment. These critical connection points must be carefully managed to
preserve not only reliable electrical service to customers and to maintain compliance with national
regulations, but also to manage costs and provide safety for the public, employees, and the entire
Western Interconnection. At Avista, substation failure could potentially lead to a local or even regional
outage, with the very real possibility of costing millions of dollars and impacting millions of lives. The
Substation team takes on these responsibilities while managing to fixed capital budgets and limited
operations and maintenance allowances. About two Avista substations are built or rebuilt each year to
meet customer growth and system needs, but the future indicates that even more work will be
required. Changing customer reliability expectations, increasing state and federal regulations,
cybersecurity concerns, aging infrastructure, and limited manpower are having an impact already and
are likely to change the landscape of Avista’s substation management and required expenditures into
the future.
Summary
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 24 of 26

Spokane Substations

Airway Heights 115kV
Barker 115kV
Beacon 230kV
Boulder 230kV
Boulder Park 115 kV
Chester 115kV
Colbert 115kV
College & Walnut 115kV
Deer Park 115kV
East Farms 115kV
Fort Wright 115kV
Francis & Cedar 115kV
Garden Springs 115kV SS
Glenrose 115kV
Greenacres 115kV
Hallett & White 115kV
Indian Trail 115kV
Inland Empire Paper 115kV
Liberty Lake 115kV
Loon Lake 115kV
Lyons & Standard 115kV
Mead 115kV
Metro 115kV
Milan 115kV
Millwood 115kV
Nine Mile 115kV SS
Ninth & Central 115kV
Northeast 115kV
Northwest 115kV
Opportunity 115kV
Otis Orchards 115kV SS
Post St. 115kV
Ross Park 115kV
Silver Lake 115kV
Southeast 115kV
Spokane Ind. Park 115kV
Sunset 115kV
Third & Hatch 115kV
Waikiki 115kV
Westside 230kV
Colville Substations

Addy 115kV (BPA)
Arden 115kV
Chewelah 115kV
Colville 115kV
Gifford 115kV
Greenwood 115kV
Kettle Falls 115kV
Orin 115kV
Spirit 115kV
Valley 115kV
Davenport
Substations

Davenport 115kV
Devil's Gap 115kV SS
Ford 115kV
Harrington 115kV
Little Falls 115kV
Long Lake 115kV
Long Lake 115kV SS*
Odessa 115kV
Reardan 115kV
Stratford 115kV SS
Wilbur 115kV
Othello Substations

Lee & Reynolds 115kV
Lind 115kV
Marengo 115kV
Othello 115kV
Othello 115kV SS
Ritzville 115kV
Roxboro 115kV
South Othello 115kV
Sprague 115kV
Warden 115kV SS
Wanapum 230kV (GCPUD)
Washtucna 115kV
Coeur d’Alene
Substations

Appleway 115kV
Avondale 115kV
Blue Creek 115kV
CD'A 15th St 115kV
Dalton 115kV
Huetter 115kV
Idaho Road 115kV
Lakeview 230/13kV
Pleasant View 115kV
Post Falls 115kV
Prairie 115 kV
Ramsey Rd. 115kV SS
Rathdrum 230kV
Spirit Lake 115kV
Lewiston-Clarkston
Substations

Clearwater 115kV
Cottonwood 115kV
Craigmont 115kV
Critchfield 115kV
DryCreek 230kV
Dry Gulch 115kV
Grangeville 115kV
Holbrook 115kV
Kamiah 115kV
Kooskia 115kV
Kooskia 34kV
Lewiston Mill Rd. 115kV
Lolo 230kV
Nez Perce 115kV
N. Lewiston 230kV
Orofino 115kV
Pound Lane 115kV
S. Lewiston 115kV
Sweetwater 115kV
Tenth & Stewart 115kV
Weippe 115kV
Wickes 115kV
Appendix A: Avista’s Substations
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 25 of 26

Sandpoint
Substations

Blanchard 115kV
Bronx 115kV SS
Cabinet Const. 115kV
Cabinet 230kV
Clark Fork 115 kV
Noxon 230kV SS
Noxon Const. 230/13kV
Noxon 230 kV Reactor
Oden 115kV
Oldtown 115kV
Priest River 115kV
Sagle 115kV
Sandpoint 115kV
Fire retardant at Avondale Sub
Control room
at Beacon Sub
Post Street Sub
Lightning
arresters at
Lakeview
Substation
Upgrade work
at Westside
Generation
Substations

Noxon Rapids HED
Cabinet Gorge HED
Post Falls HED
Upper Falls HED
Monroe St. HED
Nine Mile HED
Long Lake HED
Little Falls HED
Kettle Falls GS
Kettle Falls CT
Northeast CT
Boulder Park GS
Rathdrum CT
Coyote Springs 2
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 2, Page 26 of 26
Avista Utilities
Transmission Infrastructure Plan
2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 1 of 20
Table of Contents

Executive Summary ........................................................................................................................................1
Introduction ..................................................................................................................................................3
Avista’s Transmission Capital Investments ......................................................................................................4
Classification of Infrastructure Need by Investment Drivers ..................................................................................4
Avista’s Transmission O&M Investments ........................................................................................................5
Conclusion .....................................................................................................................................................5

Table of Figures

Figure 1. Total Planned Capital Expenditures by Investment Driver 2020-2024 .......................................................................... 4
Figure 2. Historic Capital Expenditures by Investment Driver 2010-2019 .................................................................................... 4
Figure 3. Capital Budget by Investment Driver ............................................................................................................................. 5
Figure 4. Avista’s Transmission Spending Compared to National Levels .................................................................................... 5
Figure 5. Facilities Relocation Capital Expenditures .................................................................................................................... 5
Figure 6. Typical Transmission O&M Expenditures ..................................................................................................................... 5

Table of Tables

Table 1. Planned Capital Budget by Investment Driver ................................................................................................................ 5
Table 2. Planned Capital Budget for Customer Requested.......................................................................................................... 5
Table 3. Planned Capital Budget for Mandatory & Compliance ................................................................................................... 5
Table 4. Planned Capital Budget for Failed Plant & Operations ................................................................................................... 5
Table 5. Planned Capital Budget Based on Asset Condition ....................................................................................................... 5
Table 6. Planned Capital Budget Based on Performance & Capacity .......................................................................................... 5

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 2 of 20

Our nation’s electric utilities are facing times of unprecedented challenge when it comes to the forces
driving the need for new investment in transmission infrastructure, and Avista is no different. This
growing demand for new investment has significantly impacted the ability to fund all of the high-priority
needs for electric transmission which include:

➢ Aging Infrastructure. Thousands of transformers, reactors, capacitors, conductors, poles and
structures are well past their expected lifespans.1 Avista has transmission lines that are over 110 years
old. Though the Avista transmission group is replacing these lines as funding is available and changing
out wood structures with more resilient steel, the need continues to outpace the ability and funding
to complete all the work that must be done.

➢ Increasing Need for Capacity. Much of the U.S. power grid was built in the 1950s and 1960s with a 50-
year life expectancy, and, to add further tension, the more than 640,000 miles of high-voltage
transmission lines in the lower 48 states are at full capacity now while demand for use continues to
grow.2 Much of Avista’s system was built during the same time frame. This already strained system is
being significantly impacted by shifts in the loads served by the transmission system, including
transmission interconnections to private parties for integration of new variable energy resources,
particularly wind and solar. These types of interconnections require significant capital investment to
extend or reinforce the system in order to provide for these non-traditional uses of the power system
and add additional strain to an already constrained transmission grid.

➢ Growing Numbers of Federal and State Regulations. Power markets, already weakened by flat to
declining demand growth, are often caught in the middle of a conflict between federal and state
policies. Many states have pursued public policy goals with respect to renewable energy options,
energy efficiency and CO2 abatement. On the flip side, federal policy such as tax credits and the Public
Utility Regulatory Policies Act (PURPA) have led to a growing amount of zero and negative marginal
cost power being injected into power markets already suffering sluggish load growth. In addition,
allowed return on equity (ROE) has been consistently dropping throughout the industry since the
1980s, although the need for capital investment is increasing, creating tremendous tension. Though
regulators maintain close scrutiny over rates, they are “freely encouraging the development of
renewables and greater customer access to the grid, distribution channels, and equipment through
emerging technologies.”3 These technologies require expensive investments and infrastructure. The
cost of new infrastructure is continually increasing, so any significant new construction means higher
1 Robert Walton, “Aging Grids Drive $51B in Annual Utility Distribution Spending,” UtilityDive, July 25, 2018, https://www.utilitydive.com/news/aging-grids-
drive-51b-in-annual-utility-distribution-spending/528531/ and Energy.gov, https://www.energy.gov/articles/infographic-understanding-grid. The U.S.
Department of Energy (DOE) estimates that, nationwide, 70% of transformers are 25 years old or older, 60% of high voltage circuit breakers are more than 30
years old, and 70% of transmission lines are 25 years old or older and approaching or at the end of their useful life.
2 American Society of Civil Engineers, “2017 Infrastructure Report Card,” https://www.infrastructurereportcard.org/wp-content/uploads/2017/01/Energy-
Final.pdf
3 Earl Simpkins, Leslie Hoard, Suva Chakraborty, Daniel Wilderotter, “Utilities Preparing for Growth: Navigating Disruption By Linking Capabilities,”
November 20, 2015, https://www.strategyand.pwc.com/reports/utilities-preparing-for-growth
Executive Summary
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 3 of 20
rates for consumers. Utilities face significant risk of not recovering all their costs, much less an
adequate return, for new infrastructure investment, the need for which is beyond their control.4

➢ Siting, permitting and construction. Building required transmission lines has become more complex,
time-consuming and expensive due in part to increasing environmental and property requirements.
Landowners, public and private, seek more compensation for rights-of-way and access agreements
than in the past. Local, state, and federal permitting requirements cover issues such as endangered
species, historical and cultural resources, water quality, wildlife and more. Permitting can extend over
several years and typically includes conditions that limit how utilities construct or maintain these
assets as well as stringent requirements for site restoration. These requirements considerably
constrain the siting, construction and operation of new grid facilities.5

➢ Changing Issues and Technology. In addition to feeling its age, the integrated grid, designed to
accommodate very steady, very stable traditional resources, is now required to integrate non-
traditional and often unpredictable resources such as solar, wind, and distributed generation sources.
Smart grid technology including wide-area monitoring, protection, automation and control is also
predicted to have a significant impact on grid operations – and spending.6 At the same time, the grid is
facing cyber threats never imagined back in the 1950s and 1960s when most of the system was built.
According to a variety of studies across the United States including the Department of Energy, the
viability of the century old bulk power grid has been declining and is “nearing the end of its useful
life.”7 They note that depreciation is exceeding new investment, even with all of the large projects
being built nationwide. The grid is facing increasing digitization and other technologies that require
adapting and upgrading the existing system. Customers are requiring new services, increased levels of
reliability, flexibility, and choice that are beyond the experience of traditional power companies,
demands that not only create uncertainty, but add cost, demand, and complexity.

When it comes to the impact for customers, who must ultimately pay for these requirements and
investments, an exacerbating factor is Avista’s relatively stagnant load growth due to both declining use
per customer and lackluster economic growth in most of the region.8 This translates into nearly flat
revenues, which means that new capital investments must be covered by higher customer rates.
Historically, annual increases in customer loads produced new revenues that were often sufficient to
cover the costs for new investment and inflation without the need to increase customer rates. Now
utilities are pulled to economize and pushed to innovate, dealing with decreasing revenues and, at the
same time, expensive and revolutionary new technologies such as distributed generation, battery storage
technology, customer-requested technologies, and integrating intermittent renewable resources. This
report intends to illustrate the way Avista’s Transmission group is dealing with these challenges.
4 Earl Simpkins, Leslie Hoard, Suva Chakraborty, Daniel Wilderotter, “Utilities Preparing for Growth: Navigating Disruption By Linking Capabilities,”
November 20, 2015, https://www.strategyand.pwc.com/reports/utilities-preparing-for-growth
5 To illustrate this point, a transmission line proposed into Las Vegas was on hold for twenty years due to continuous siting opposition, including protecting the
habitat of two endangered species that were not considered endangered when the project was proposed. Holland & Hart, “Transmission Siting in the Western
United States,” page 10, https://www.hollandhart.com/articles/Transmission_Siting_White_Paper_Final.pdf
6 Julio Romero Aguero, “What Does the Future Hold for Utilities?” February 24, 2015, T&D World, https://www.tdworld.com/grid-
innovations/distribution/article/20965183/what-does-the-future-hold-for-utilities
7 U.S. Department of Energy, Energy Advisory Committee, “Keeping the Lights On In a New World,”
https://www.energy.gov/sites/prod/files/oeprod/DocumentsandMedia/adequacy_report_01-09-09.pdf
8 Avista’s service territory is experiencing about 1% growth, a rate that economists predict will continue for the next several years.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 4 of 20

Avista Utilities serves approximately 380,000 electric
customers in Washington and Idaho over an extensive
electric transmission system that is designed, built,
operated and maintained by the Company. This
infrastructure system consists of approximately 2,750
miles of high voltage transmission lines9 crossing
30,000 square miles and bringing electric power to
over 1.6 million people in Washington and Northern
Idaho.10 Avista must continually make new
investments in this system in order to continue
providing customers with safe and reliable electric service at a reasonable cost with service levels that
meet customer’s expectations for quality and satisfaction, and, at the same time, meet stringent
national, regional, state, and local regulatory requirements.

In order to meet all of these requirements, the Company creates specific capital programs. These
programs are developed through planning and engineering studies and analyses, as well as scheduled
upgrades or replacements identified in the operations districts, within engineering groups, or based upon
need. These projects undergo internal review by multiple stakeholders who help ensure that all system
needs and alternatives have been identified and addressed. If proposed projects are initially approved,
they go through a formal review process referred to as the Engineering Roundtable, a diverse group of
engineering leaders11 who track project requests, prioritize them, and establish committed construction
package dates and required in-service dates for projects. Once a project has passed this phase of
evaluation, it moves to the Capital Planning Group.

The Capital Planning Group (CPG) is a group of Avista Directors that represent capital intensive areas of
the Company. Committee members are directors from a variety of business units to add a depth of
perspective, though their role is to consider capital decisions from the perspective of overall Company
operations and strategic goals as well as spending guidance set by senior management and approved by
the Finance Committee of the Board of Directors. They develop a final budget that represents a
reasonable balance among competing needs in order to maintain the performance of Avista’s systems, as
well as prudent management of the overall enterprise in the best interest of customers.

The purpose of this report is to provide a comprehensive overview of the approved transmission system
programs, as well describe the need for capital investment, operations, and maintenance funding. But
more importantly, the goal is to explain the many forces that are driving these expenditures and how
Avista is attempting to balance these complex and competing needs.
9 This includes 700 miles of 230 kV, 1550 miles of 115 kV, and 500 miles of co-owned (Colstrip) 500 kV lines.
10 Statistics from “2018 Avista Quick Facts,” https://investor.avistacorp.com/static-files/a7342b27-72cc-44d4-b9a7-b62903e999df
11 Eleven representatives are included in this group from: Transmission and Distribution Planning, Transmission, Distribution, and Substation Design, System
Protection, System Operations, Asset Management, Communications and Generation Engineering, and Transmission Services.
Introduction
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 5 of 20

Classification of Infrastructure Need by Investment Drivers

As a way to create more clarity around the particular needs being addressed with each capital
investment as well as simplifying the organization and understanding of Avista’s overall project plans, the
Company has organized all capital
infrastructure investments by the
classification of need or “Investment
Driver.” The investments associated with
each investment driver are briefly
defined below, and in greater detail later
in this report.

Customer Requested – In the
Transmission business unit, this category
is primarily related to building new
facilities for connecting large
transmission-direct customers or to
enhance their service as requested. This
category is used, for example, to provide
for expenses related to the requested
interconnection of solar or wind projects,
which are typically owned by an
independent developer requesting
interconnection with the Company’s
transmission system.

Mandatory & Compliance – The
Company makes a large number of
business decisions as a direct result of
compliance with laws, mandatory
standards, safety codes, contracts, and
agreements. Examples include
transmission reinforcement projects or
control equipment required by NERC to
preserve the reliability of the interconnected grid or contract-required work on the Colstrip transmission
system that Avista co-owns with other utilities. These decisions are primarily driven by external
requirements that are largely beyond the Company’s control.

Avista’s Transmission Capital Investments

Figure 1. Total Planned Capital Expenditures by Investment Driver
2020-2024
Figure 2. Historic Capital Expenditures by Investment Driver 2010-2019
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 6 of 20
Failed Plant & Operations – This category sets aside funds to replace failed equipment as well as support
ongoing utility operations. Typically these expenditures are the result of storm damage but are also the
result of damage from vehicles accidents, animals, trees, etc.

Asset Condition – All assets have a defined
useful service life. This category provides
funding to replace equipment as needed so
the system can continue to function
effectively. This may include replacing parts
as they wear out or when items can no
longer meet their required
purpose, as systems become
obsolete and replacement
parts are no longer available,
to remedy safety or
environmental issues, or if the
condition of an asset is such
that it is no longer optimizing
its own performance or
customer value. The Company
also replaces critical equipment prior to failure in order to mitigate the risk
of failure and the resulting customer impacts.

Customer Service Quality & Reliability – This category is for expenses related to meeting customer
expectations for quality of service and reliability. Transmission does not have any dollars set aside under
this category, as it does not typically directly impact customers.

Performance & Capacity – Programs in this category ensure that assets satisfy business needs and meet
performance standards, typically defined by Company experts or in line with industry standards. Some
examples include adding new substations or transmission lines to meet customer growth or to provide
redundancy to reduce the potential for customer outages.

All of Avista’s capital expenditures are categorized into one of these drivers, though not all of the
investment driver categories are represented for each business unit. For example, investments planned
for electric transmission during the upcoming five year planning cycle do not include any projects in the
category of Customer Service Quality and Reliability. This is fairly common, since very few of Avista’s
customers receive direct transmission service. In addition, investments in electric transmission related
directly to service reliability for all customers are generally driven by mandatory compliance
requirements so can be found in the “Mandatory & Compliance” Driver. Note that not all of the
investment drivers will be used in all of Avista’s primary asset categories in every budgeting cycle, yet
they remain an efficient and effective way of categorizing expenditures in a clear and transparent fashion
that promotes better understanding of how and why the Company makes business decisions.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 7 of 20
Currently Planned Capital Investments in Transmission
2020 – 2024

For the next five-year planning
horizon, Avista expects to spend
about $143 million in capital dollars
for the Transmission side of the
business, allocated across five of the
investment drivers described above.
These programs are summarized by
investment driver below. Note that
Transmission and Substations are
connected by physical locations and
voltage and thus share several
business cases, which is noted in the
text below.

Increasing Capital Investments for Infrastructure Needs12

In recent years Avista has experienced an increasing demand for new and upgraded infrastructure
investment. The pattern of investments
made by the Company during this time
period are similar to that of the industry, as
shown in Figure 4. Utilities across the nation
are responding to the same issues
mentioned earlier: the demand to replace an
increasing amount of infrastructure that has
reached the end of its useful life, ever
increasing regulatory compliance
requirements, and the need for reliability
and technology investments necessary to
build the integrated energy services grid of
the future. Avista’s investments in electric
12 National data obtained from EEI: https://www.eia.gov/todayinenergy/detail.php?id=34892 (only available through 2017)
Figure 4. Avista’s Transmission Spending Compared to
National Levels 12

Table 3. Planned Capital Budget for Customer
RequestedFigure 5. Avista’s Transmission
spending compared to the national level 9
Figure 3. Capital Budget by Investment Driver
Table 1. Planned Capital Budget by Investment Driver
Business Driver 2020 2021 2022 2023 2024 5 Year Total 5 Year Average
Customer Requested $2,225,000 $0 $0 $0 $0 $2,225,000 $445,000
Mandatory & Compliance $10,550,000 $19,500,000 $1,900,000 $1,350,000 $9,000,000 $42,300,000 $8,460,000
Failed Plant & Operations $750,000 $750,000 $750,000 $750,000 $750,000 $3,750,000 $750,000
Asset Condition $10,309,120 $10,659,120 $17,309,120 $14,793,420 $13,443,420 $66,514,200 $13,302,840
Performance & Capacity $400,000 $300,000 $1,000,000 $11,900,000 $14,150,000 $27,750,000 $5,550,000
$24,234,120 $31,209,120 $20,959,120 $28,793,420 $37,343,420 $142,539,200 $28,507,840
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 8 of 20
transmission also reflect the Company’s adoption of asset management-based approaches for assessing
infrastructure needs and developing strategies and programs to optimize the lifecycle value of the
Company’s transmission system.

Customer Requested

Customer requested projects are triggered by non-Company applications for new transmission-level
connections, line extensions, transmission capacity, or system reinforcements. For example, the
Company may be obligated to construct a distribution substation with an associated transmission line
extension in order to meet the requested new load
requirements of an industrial or large commercial
customer, large subdivision or business park. Other
situations may involve a requested transmission
interconnection with a neighboring utility or a
customer-owned generation project. In the current
five year budget period, this category includes an
interconnection required to integrate Rattlesnake Flat
Wind Project, being built by an independent
developer.

Rattlesnake Flat Wind Integration

Avista issued a request for proposal in June 2018 for additional
renewable energy. An external company, Clearway Energy Group, was
selected to provide that energy. They are developing a wind power
facility known as Rattlesnake Flat Wind, which is projected to provide
Avista with approximately 50 average megawatts of renewable energy,
or as much as 144 megawatts of nameplate wind capacity, under a 20-
year power purchase agreement with deliveries beginning in 2020. This
project, including 90 wind turbines and associated facilities, is located
on approximately 23,000 acres in Adams County, Washington. This
project requires significant upgrades to Avista’s existing infrastructure,
including transmission line rebuilds, an additional new switching
station, and existing substation upgrades in order to handle the new generation. This new energy
resource benefits Avista customers in two primary ways: providing customers with additional renewable
energy and the required transmission upgrades enhance the strength and resiliency of the existing
infrastructure. This business case is part of the same Substations business case.
Table 2. Planned Capital Budget for Customer Requested
Customer Requested 2020 2021 2022 2023 2024 5 Year Total
Rattlesnake Flat Wind Integration $2,225,000 $0 $0 $0 $0 $2,225,000
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 9 of 20
Mandatory & Compliance

The investments in transmission infrastructure made under this category are investments driven typically
by compliance with laws, rules, and contract requirements that are external to the Company and outside
of Avista’s control. Many of these are the result of NERC Reliability Standards related to planning and
operations, where failure to comply may result in monetary penalties of up to $1 million per day per
infraction. In addition, imbedded within every transmission construction project are environmental
compliance costs. Other examples in this category include leases on tribal lands, contractual obligations,
and expenditures related to implementing safety standards. Other examples in the current budget cycle
of projects required by NERC mandates include the new Saddle Mountain and West Plains Reinforcement
Plan and upgrades to the Ninth and Central Substation, described below.

Saddle Mountain 230/115 kV Station

Avista System Planning and related outside entity studies
determined that the western portion of the Avista’s
existing system is not meeting NERC performance
requirements during heavy load scenarios. The Saddle
Mountain project, undertaken in two phases, will allow
Avista to continue serving Company load in the Big Bend
Area near Othello while eliminating pressure on the
Grant County Public Utility District system. This problem
will be solved by constructing a new 230/115 kV
substation where the Walla Walla–Wanapum 230 kV and
the Benton–Othello 115 kV transmission lines cross. This new sub will consist of a three-terminal 230 kV
double bus double breaker configuration, a 250 MVA13 230/115 kV auto-transformer, four 115 kV
terminals, rebuilding the existing associated aging 115 kV transmission lines, and building ten miles of
new 115 kV transmission. This project will greatly improve the reliability of transmission in the area and
13 MVA refers to the amount of power output a transformer is capable of delivering at a specified voltage under normal operating conditions without exceeding
internal temperature limitations. A 250 MVA transformer is a very large transformer.
Saddle Mountain Substation under construction

Colstrip Transmission

Colstrip Transmission

Colstrip Transmission

Saddle Mountain Substation under construction

Colstrip Transmission

Colstrip Transmission

Colstrip Transmission
Table 3. Planned Capital Budget for Mandatory & Compliance
Mandatory & Compliance 2020 2021 2022 2023 2024 5 Year Total 5 Year Average
Saddle Mountain 230/115kV Station (New) Phase 1 $3,300,000 $0 $0 $0 $0 $3,300,000 $660,000
Saddle Mountain 230/115kV Station (New) Phase 2 $300,000 $10,700,000 $0 $0 $0 $11,000,000 $2,200,000
Spokane Valley Transmission Reinforcement $300,000 $2,250,000 $0 $0 $0 $2,550,000 $510,000
Transmission Construction - Compliance $2,850,000 $3,500,000 $0 $1,200,000 $0 $7,550,000 $1,510,000
Transmission NERC Low-Risk Priority Lines Mitigation $2,800,000 $2,700,000 $1,000,000 $0 $0 $6,500,000 $1,300,000
West Plains New 230kV Substation $0 $100,000 $500,000 $0 $0 $600,000 $120,000
Ninth & Central Sub - New 230kV Transformation $0 $0 $150,000 $150,000 $9,000,000 $9,300,000 $1,860,000
Westside 230/115kV Station "Brownfield Rebuild" $500,000 $250,000 $250,000 $0 $0 $1,000,000 $200,000
Road Relocations $500,000 TBD TBD TBD TBD $500,000 $500,000
$10,550,000 $19,500,000 $1,900,000 $1,350,000 $9,000,000 $41,800,000 $8,460,000
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 10 of 20
remove the current single point of failure situation which could create widespread outages. It also
mitigates potential thermal overloading and voltage issues in this area. This business case is part of the
same Substations business case.

Spokane Valley Transmission Reinforcement

This project reinforces transmission in the Spokane
Valley area, spurred by load growth in the region as
well as compliance with the NERC TPL-001-4
Reliability Standard14 which requires each utility to
ensure that their system is robust enough to operate
reliably over a broad spectrum of system conditions
and under a wide range of possible contingencies.
Avista system studies identified this area as requiring
additional reinforcement in order to be in compliance with the NERC standard about ten years ago, and
the Company has been working on it since that time. This long term project requires the construction of a
new switching substation (Irvin) off of Trent Avenue. It also includes rebuilding 4.4 miles of the Beacon-
Boulder #2 115 kV transmission line, building 1.75 miles of transmission for the new Irvin-Opportunity
115 kV tap, constructing 2.2 miles of 115 kV transmission from the new Irvin sub to the existing Millwood
sub, and installing circuit breakers to handle the changes at the existing Opportunity Sub. This work will
not only address compliance issues, but will make the transmission system in this urban area more stable
and reliable, specifically for serving large industrial customers. This business case is part of the same
Substations business case.

Transmission Construction - Compliance

This program covers the transmission rebuild work, line reconductoring, and
new construction outlined in the Corrective Action Plan developed under
NERC Reliability Standard TPL-001-4.15 It has 8 requirements and 57 sub-
requirements related to planning and analysis, including the requirement for
robust system models to determine system stability, voltage levels and
system performance under various scenarios. This Standard also contains
spare equipment regulations, load loss requirements and mitigation, a
number of system protection requirements, and more. In addition, when
Avista’s system planning studies indicate any kind of problem that could arise
in the transmission system, it must be remedied within specific timeframes.
The Transmission Construction - Compliance Program provides funding to
mitigate any identified reliability issues in order to remain in compliance with NERC requirements.
14 NERC Standard TPL-001-4: http://www.nerc.com/files/tpl-001-4.pdf requires the Company to avoid load loss and have circuit breakers with sufficient
interrupting capability for faults.
15 NERC TPL-001-4: https://www.nerc.com/pa/Stand/TPL0014RD/Implementation%20Plan%20for%202010-11_TPL-001-4.pdf and
http://www.oasis.oati.com/PPW/PPWdocs/PacifiCorp''s_NERC_TPL-001-4_Standard_Overview_R1.pdf
Site of new Irvin Substation in Spokane Valley

North Lewiston Reactors help regulate the voltage and
reactive power in this area

Site of new Irvin Substation in Spokane Valley

North Lewiston Reactors help regulate the voltage and
reactive power in this area

Site of new Irvin Substation in Spokane Valley

North Lewiston Reactors help regulate the voltage and
reactive power in this area

Site of new Irvin Substation in Spokane Valley

North Lewiston Reactors help regulate the voltage and
reactive power in this area

Site of new Irvin Substation in Spokane Valley

North Lewiston Reactors help regulate the voltage and
reactive power in this area

Site of new Irvin Substation in Spokane Valley

North Lewiston Reactors help regulate the voltage and
reactive power in this area

Site of new Irvin Substation in Spokane Valley

North Lewiston Reactors help regulate the voltage and
reactive power in this area

Site of new Irvin Substation in Spokane Valley

North Lewiston Reactors help regulate the voltage and
reactive power in this area
Trent Avenue
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 11 of 20
Transmission – NERC Low Risk Priority Lines Mitigation

This program addresses mitigation
required on Avista's “Low Risk” 115
kV transmission lines and brings
these lines into compliance with
NERC requirements16 and National
Electric Safety Code (NESC)
minimum transmission line
clearance values.17 These code
minimums have also been adopted
into the State of Washington's
Administrative Code (WAC).18 “Low
risk” lines are those not connecting
Avista generation to primary load.
Investments made under this program provide funding to reconfigure insulator attachments, rebuild
existing transmission line structures, or remove earth from beneath transmission lines to mitigate
ratings/sag discrepancies found between the line designs and actual field conditions in order to provide
minimum clearance requirements for worker and public safety.

West Plains New 230 kV Substation

Planning studies of the Spokane area transmission system revealed specific transmission performance
issues which will occur within the next five to ten years. Note that these performance issues have a
significant potential to exceed NERC reliability standards, designed to prevent cascading outages and
ensure the integrity of the interconnected system.19 System studies identified at least seven NERC
thermal or voltage limit violations including:

• Inadequate 230/115 kV transformation provided by the four existing substations in the area,
especially in the case of system events. In addition, the existing transformers are reaching
maximum thermal capacity now and in time will exceed it.
• Related 115 kV transmission lines are running at 96% to 135% of their rated capacity during specific
contingency scenarios.20

These issues are expected to intensify with projected growth in this region. In addition, some of the
transmission lines in the Spokane area are radial lines, requiring manual intervention in order to restore
16 North American Electric Reliability Corporations (NERC) "NERC Alert" - Recommendation to Industry, "Consideration of Actual Field Conditions in
Determination of Facility Ratings," http://www.nerc.com/pa/rrm/bpsa/Pages/Facility-Ratings-Alert.aspx
17 National Electric Safety Code Electrical Safety Requirements, https://www.usbr.gov/ssle/safety/RSHS/sec12.pdf
18 Washington State Legislature WAC 296-46B-010: https://apps.leg.wa.gov/wac/default.aspx?cite=296-46B-010
19 NERC Reliability Guidelines, September 2018,
https://www.nerc.com/comm/PC_Reliability_Guidelines_DL/Reliability_Guideline_Methods_for_Establishing_IROLs.pdf
20 This includes the Northwest-Westside 115 kV, the Bell-Northeast Waikiki Tap 115 kV lines, and the lines from the Beacon and Westside substations.
Placing conductor using a helicopter (left) and by hand (right)

Placing conductor using a helicopter (left) and by hand (right)
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 12 of 20
service to customers after a fault, with a total customer exposure of up to 31 miles. In order to manage
this situation and remain in compliance with NERC directives, the Company is constructing a new 230 kV
substation in the West Plains area. This location provides also an opportunity to interconnect with
Bonneville Power Administration (BPA) to strengthen Avista’s grid and add additional operating
flexibility. The West Plains Substation is designed to mitigate all of the identified system deficiencies,
including adding 500 MVA of transformer capability and redundancy to the transmission system in this
area. This business case is part of the same Substations business case.

Ninth & Central 230 kV Station & Transmission

The Spokane area transmission system is heavily dependent upon the Beacon Substation, which is
networked to the Bell Substation as well as eight 115 kV transmission lines. In order to reduce this
dependency, create redundancy, enhance customer reliability, and remain in compliance with mandatory
standards, Avista is upgrading the infrastructure of the Ninth & Central Substation to take on more of this
load. The Company is adding new 230 kV infrastructure to accommodate a 230/115 kV auto-transformer
and associated circuit breakers, and putting in place additional transformer capacity for the Spokane
transmission system. This project will also build eight miles of new transmission lines, utilizing existing
115 kV corridors in a double circuit configuration in order to fortify the Spokane area transmission
system. This project significantly strengthens and adds resiliency to the electric system. It is scheduled to
begin in 2022. This business case is part of the same Substations business case.

Westside 230/115 kV Substation “Brownfield Rebuild”21

The Westside 230 kV Substation Rebuild is major project made necessary because the existing Westside
#1 230/115 kV transformer exceeded its applicable
facility rating during heavy summer loads, which led
to the cascading failure of the Westside #2 230/115
kV transformer. This situation created a compliance
risk with NERC TPL-001-4, a standard which defines
system planning performance and has very specific
requirements around equipment exceeding ratings as
well as shedding customer load.22 The previous
transformers were underrated for their use and not
up to current design standards. In addition, air
switches and breakers at this substation had
begun to fail, the protection equipment needed
to be updated and upgraded, oil containment provisions needed to be made, and site security issues had
to be addressed.

21 A “Brownfield” project refers to a project that takes place on land that has been occupied by a “permanent” structure at some point, requiring demolishing or
renovating a prior structure, versus a “Greenfield” project that will be built in a place where nothing had been built before.
22 NERC TPL-001-4, http://www.nerc.com/files/tpl-001-4.pdf
New Westside #1 230/115 kV transformer being placed
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 13 of 20
Engineers determined that the existing old transformers (one was manufactured in 1976 and one in
1958) must be replaced with 250 MVA rated transformers that meet current performance, efficiency,
and safety standards. In addition, the 230 kV and 115 kV buses at the substation will be upgraded to a
double bus double breaker configuration to provide adequate redundancy. Along with the transformer
change-outs, numerous other equipment replacements are required to have the capacity needed from
this station. This project, started in 2016, should be completed during the current budget cycle. This
business case is part of the same Substations business case.

Road Relocations

Avista is required to move its infrastructure in response to municipalities, counties, and state-level
agency projects to rebuild or realign roads, streets and highways, as well as other state, county, and city
infrastructure projects. This work must be performed at the Company’s expense.

While Avista may have some latitude to
negotiate the timing of the construction,
it has no choice with regard to removing
and relocating its infrastructure and
paying all of the associated costs. Avista
also works with the Departments of
Transportation in both states to renew
and maintain crossing and encroachment
permits, which at times also necessitates
the Company moving its infrastructure at
its own expense. This work may require
the Company to realign or modify existing
infrastructure to comply with state clear zone, conductor clearance, and other regulations regarding the
location of poles, guy wires, and overhead conductors. These costs are increasing over time as
jurisdictions in which Avista must perform the work are becoming more and more demanding in their
requirements, including calling for additional work as a condition of construction such as extensive
landscaping, which increases costs. As shown in Figure 5, these costs are also highly variable from year to
year and difficult to predict.

Failed Plant & Operations

Transmission investments in this category are primarily the
result of storm damage to the Company’s transmission
system or the funding needed for failed or damaged
equipment. When this happens, the Company must quickly
respond to replace the infrastructure in order to ensure
Figure 5. Facilities Relocation Capital Expenditures
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 14 of 20
the continuity of
service to
customers.
Common causes
of damage to the
system include
major wind
events, lightning,
fire, snow and ice,
downed
trees/vegetation,
wildfires, human
or animal caused damage (left), and equipment failure (above). Other
failures include the unanticipated loss of assets due to a range of
factors including age and condition. Planned pending for this category is shared between Distribution,
Substations, and Transmission. Transmission’s share of this spending is shown in Table 4.
Asset Condition

Investments in transmission infrastructure related to Asset Condition are required to replace assets
based on established asset management principles and strategies adopted by the Company, which are
designed to optimize the overall lifecycle value of the investment for customers. This category includes
rebuilds related to aging or end-of-life assets and upgrades related to design, safety, or construction
standards. It also includes specific technology upgrades related to interconnected system reliability and
cybersecurity. The Company closely monitors outages and replaces equipment that is either impacting
customer service or is likely to do so. Some equipment is so critical that it cannot be allowed to fail.
When this equipment reaches an age when it is close to or at the end of its useful life, the Company
preventively replaces it to maintain reliability and acceptable levels of service.
Failed Plant & Operations 2020 2021 2022 2023 2024
Transmission - Minor Rebuild: Storm $750,000 $750,000 $750,000 $750,000 $750,000
Table 5. Planned Capital Budget Based on Asset Condition
Table 4. Planned Capital Budget for Failed Plant & Operations
Asset Condition 2020 2021 2022 2023 2024 Five Year Total
Five Year
Average
SCADA - SOO and BuCC $2,100,000 $920,000 $700,000 $700,000 $700,000 $5,120,000 $1,024,000
Substation Rebuild Program $18,750,000 $18,250,000 $24,950,000 $25,050,000 $25,125,000 $112,125,000 $22,425,000
Transmission Major Rebuild - Asset Condition $7,550,000 $7,500,000 $14,000,000 $10,000,000 $10,000,000 $49,050,000 $9,810,000
Transmission - Minor Rebuild: Non-Storm $909,120 $1,659,120 $1,659,120 $1,843,420 $1,843,420 $7,914,200 $1,582,840
$29,309,120 $28,329,120 $41,309,120 $37,593,420 $37,668,420 $174,209,200 $34,841,840
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 15 of 20
SCADA – SOO and BuCC

Supervisory Control and Data Acquisition
(SCADA) and the System Operations Office
and Backup Control Center (BuCC) provide
the capabilities required to achieve
compliance with numerous reliability
standards and requirements.23 This business
case replaces and upgrades existing control
center telecommunications and computing
systems for these systems as they reach
the end of their useful lives, require
increased capacity, cannot be upgraded
due to outdated technology, or are necessitated by other requirements, including NERC reliability
standards, system growth, and external projects (e.g. Smart Grid). This type of work includes hardware,
software, and operating system replacement and upgrades. These control systems provide real-time
visibility, situational awareness, and control of Avista’s electric and gas systems and are critical to
Company operations. These expenditures prevent the degradation of these capabilities due to lack of
capacity, capability, or aging systems that would present increased safety and significant compliance risk.
These specialized systems are critical in ensuring continued operation and customer service. This
business case is shared and is part of the same Substations business case.

Substations Rebuild Program

Replacing and upgrading major substation
apparatus and equipment as it approaches end-
of-life or becomes obsolete is a routine part of
Avista’s maintenance strategy. Replacing this
equipment before it fails is necessary to
maintain the safe and reliable operations of the
transmission and distribution systems, and
substations are at the heart of these
interconnected systems. Investments in this
program include updating old equipment to
meet new safety and construction standards,
installing communications systems, and
replacing or upgrading other equipment such as
23 For the electrical system these include NERC standards BAL, COM, CIP, EOP, INT, PER, PRC, TOP, and VAR. BAL = Balancing Authority Control, COM
= Interpersonal Communications among business units within a utility, CIP = Critical Infrastructure Protection, EOP = Emergency Preparedness & Operations,
INT = Interchange Scheduling & Coordination, PER = Personnel Training Requirements, PRC = Protection & Control Systems, TOP = Transmission
Operations Requirements, and VAR = Voltage and Reactive capabilities. For more information about any of these requirements, please see:
https://www.nerc.com/pa/Stand/Pages/AllReliabilityStandards.aspx
Work at the Kooskia Substation

Work at the Kooskia Substation
Above: Post Street control panels
Right: Rathdrum Substation panel house
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 16 of 20
circuit breakers, reclosers, switches, capacitor banks, transformers, and regulators. In addition,
supporting equipment like relays, meters, batteries, panel housing, and fences must be replaced
periodically to ensure the full functionality and safety of Avista’s substations. Please note that capital
allocated for this program is shared between Transmission, Substations, and Distribution but the entire
amount is shown here as the Transmission function creates and manages this program.

Transmission Major Rebuild – Asset Condition

Investments made under this program rebuild existing transmission lines based
on overall asset condition. “Condition” is measured by useful life or the number
of condition-related outages. Factors such as operational issues, ease of access
during outages, and need
to add automation or
communications
equipment may be
included in the type of
spending in this category.
Replacing old and worn-
out poles and cross-arms
and other associated transmission equipment,
help guard against increasing risk for more failures
and outages. Transmission outages can have
significant consequences, as they tend to impact a large number of customers and have the potential to
start fires in dry areas. In addition to reliability issues, failure to properly invest builds a bow-wave of
needed investments in the future, thus this program is crucial to maintaining operations. It is split
between the 115 kV system and the 230 kV system.

Transmission Minor Rebuild – Non-Storm

Expenditures under this business case typically cover work found
during wood pole and aerial patrol inspections as well as
replacement of air switches that have malfunctioned, failed, or
reached end-of-life. During inspections, various issues are
discovered regarding the condition of assets. This can include
rotten poles, broken or split crossarms, broken conductor, guy or
ground wire missing or damaged, encroachments, and the like. At
times these issues are discovered based on outages. Transmission
engineers evaluate each situation and prioritize them based on
customer impact, safety and fire risks to allocate funding in this
category.
Failed Conductor

Work at the Kooskia
Substation
Working on the Benewah – Moscow 230 kV line
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 17 of 20
Performance & Capacity

These investments support additions of new substations or reinforcement of existing substations that
require supporting transmission upgrades or additions. Investments are typically requested by
Transmission Planning or Operations. Funding in this category can be used to increase reliability to
existing substations by providing redundant transmission feeds to radially-fed substations, reducing the
potential for customer outages. Another common example is an identified operational or equipment
issue that is leading to increasing outages or safety concerns. The issue that hits the “capacity” aspect of
this driver is customer load growth or load changes. Currently there are two Transmission programs in
the Performance and Capacity category in the upcoming budget cycle which will be described below.

Transmission New Construction

Investments made under this program support the addition of new
substations due to load growth in a particular area or to reinforce
existing substations which require new transmission. Funding in this
category is typically related to increased performance, system stability,
customer load growth, or service reliability. Funding in this category is
also used to provide redundant
transmission feeds to radially-
fed substations, reducing the
potential for customer
outages. This program is
managed through the joint
efforts of Avista’s Transmission
Design &
Engineering,
Substations,
Operations, and
Transmission Planning
groups, from which the
requests for upgrades or
additions are initiated.

Performance & Capacity 2020 2021 2022 2023 2024 Five Year Total
Five Year
Average
Cabinet Gorge 230kV Add Bus Isolating Breakers $100,000 $1,500,000 $0 $0 $0 $1,600,000 $320,000
Transmission New Construction $0 $0 $400,000 $11,250,000 $12,900,000 $24,550,000 $4,910,000
$100,000 $1,500,000 $400,000 $11,250,000 $12,900,000 $26,150,000 $5,230,000
Table 6. Planned Capital Budget Based on Performance & Capacity
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 18 of 20

Transmission O&M Expenditures

Avista typically spends about $13 million annually in
operations and maintenance work required to sustain
its electric transmission system. Unexpected
expenses are always a possibility, but the Company
has routine maintenance programs in place to insure
that those occurrences are as few as possible. All of
Transmission’s O&M programs play a role in ensuring
reliable service. Programs such as aerial and ground
patrols to identify potential problems, fire retardant
to protect poles from wildfire, foundation work to
maintain the integrity of structures, and vegetation management around lines and on associated roads
and trails to allow access for maintenance and repair all work to help prevent outages.

As can be seen in Figure 6, storms take a significant toll on transmission equipment, though these
expenditures can vary widely from year to year. Compliance related expenditures are also a major factor.
Compliance category requirements can include interconnection work with neighboring utilities, Columbia
Grid and Western Electricity Coordinating Council (WECC) regulations, and meeting requirements from
the North American Electric Reliability Corporation (NERC) that impact equipment maintenance
requirements, security measures, training, and planning among other elements. Compliance also includes
work related to the Colstrip transmission system as required by Avista’s contract with the other line
owners. Other Transmission O&M expenditures include performing aerial and ground inspections of
Avista’s transmission system, ensuring adequate vegetation management in all transmission rights-of-
way, installing, replacing, and maintaining air switches and other system control devices, and providing
the manpower and equipment for System Operations, System Planning, the Supervisory Control and Data
Acquisition (SCADA) and Energy Management Systems (EMS), System Protection, Reliability, and
Distribution Operations.

The Transmission group is closely involved with the Substation and Generation groups, as transmission
structures and equipment directly connect with both generating sources and the substations which direct
the power around the system. Thus some of the projects listed in this report are shared with other
business units within the Company (as noted where each business case is described above).

More details about the Transmission team, their work, equipment used, regulations, and a glossary of
terms are all available in the 2018 Transmission Infrastructure Report located on the Company’s
intercompany website24 or upon request.
24 Avista Avenue, “Tools & Resources” tab, “Avista Infrastructure Plans” heading as “Transmission Plan.”
Figure 6. Typical Transmission O&M Expenditures
Avista’s Transmission O&M Investments
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 19 of 20

Avista’s transmission infrastructure programs are
thoughtfully developed, analyzed, optimized, adjusted,
and re-analyzed as appropriate to ensure that Avista
delivers cost effective value for customers while meeting
all legal and mandatory requirements. As the Company
moves forward with new programs such as Wildfire
Resiliency, many of Transmission’s programs will be
impacted. For example, it is likely that new technology
including LIDAR,25 infrared imaging, drones, and virtual
inspections will create significant change for the current
inspection practices and may increase costs, but will also
provide a far more robust picture of the state of Avista’s
transmission system. The Wildfire Resiliency project is
also driving a change to the Company’s wood pole fire protection programs, which have used an effective
fire resistant paint for poles until now, but which will migrate toward a fire-resistant mesh system that
lasts far longer.

Avista’s Transmission is facing other long-term issues being felt by utilities across the nation. Aging
structures and equipment create increasing risk of failure and resulting impacts to customer reliability,
just as customers are demanding higher and higher levels of service. Determining the priority of
replacement is also a challenge, as Transmission competes for limited funding with other Company
business units facing their own aging equipment challenges and requirements. State and federal
regulations increase every year; sometimes hundreds of new regulations are introduced within a short
span of time, and compliance is required; it is not an option. Most of these
new regulations have an impact on the bottom line in one way or another,
and add ever-increasing levels of complexity to the way the Company
operates.

The Transmission team is dedicated to facing all of these challenges in the
most efficient, cost-effective, and thoughtful way possible, as demonstrated
by the programs described here. As these programs change and adapt to
whatever comes next, be it new regulations, state policies, failed equipment,
or even a pandemic, the focus of this group will remain unchanged. They will
continue to operate and manage Avista’s grid successfully and in the long-
term best interests of customers.
25 LIDAR is a surveying system that uses a laser to create 3-D images of landscapes, making it invaluable for identifying vegetation management issues.
Conclusion

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 3, Page 20 of 20
Avista Utilities
Natural Gas Infrastructure Plan
2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 1 of 25
Table of Contents
Executive Summary ..................................................................................................................................... 1
Introduction ................................................................................................................................................ 3
Avista’s Natural Gas Capital Investments ................................................................................................... 4
Classification of Infrastructure Need by Investment Drivers ................................................................. 4
Currently Planned Capital Investments in Natural Gas .......................................................................... 6
Customer Requested .......................................................................................................................... 6
Mandatory & Compliance ................................................................................................................... 7
Failed Plant & Operations ................................................................................................................. 12
Asset Condition ................................................................................................................................. 13
Performance & Capacity ................................................................................................................... 15
Avista’s Natural Gas O & M Investments .................................................................................................. 16
Wrap Up .................................................................................................................................................... 16
Appendix A: Natural Gas for Generation .................................................................................................. 16
Appendix B: Jackson Prairie Storage Facility............................................................................................. 16
Table of Figures
Figure 1. Avista Natural Gas Hookups ........................................................................................................................3
Figure 2. Avista Total Historic Actual Capital Spending by Investment Driver .............................................................4
Figure 3. Avista Projected Total Budget Gas Capital Expenditures by Investment Driver ...........................................4
Figure 4. Avista Gas Capital Budget by Investment Driver ..........................................................................................6
Figure 5. Avista Gas Capital Expenditures Based on Customer Requests & Growth .................................................6
Figure 6. Avista Gas Capital Expenditures Based on Mandatory & Compliance .........................................................7
Figure 7. Capital Expenditures Based on Failed Plant & Operations ........................................................................ 12
Figure 8. Avista Gas Capital Expenditures Based on Asset Condition ...................................................................... 13
Figure 9. Capital Expenditures Based on Performance & Capacity .......................................................................... 15
Figure 10. Historical Avista Gas Actual O&M Expenses 2009-2019 ......................................................................... 16
Table of Tables
Table 1. Avista Gas Planned Capital Expenditures by Driver ......................................................................................6
Table 2. Avista Gas Customer Requested / Growth Capital Expenditures .................................................................7
Table 3. Avista Gas Mandatory & Compliance Capital Expenditures ..........................................................................8
Table 4. Avista Natural Gas Failed Plant & Operations Capital Expenditures ........................................................... 13
Table 5. Avista Natural Gas Asset Condition Capital Expenditures .......................................................................... 14
Table 6. Avista Natural Gas Performance & Capacity Capital Expenditures ............................................................. 16
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 2 of 25
The Natural Gas group is facing a lot of changes in the next few years, many related to processes and
requirements, and many outside of the Company’s control. All of these changes will create direct
budget impacts.
This sector faces heavy scrutiny across a wide spectrum of environmental issues including air and
water quality and greenhouse gas emissions from the Environmental Protection Agency, the Federal
Energy Regulatory Commission, state agencies, state legislatures, and the public at large.
Safety and operations regulations are also evolving at the state and federal level. The United States
Department of Transportation’s Pipeline and Hazardous
Materials Safety Administration (PHMSA) establishes
national policy, sets and enforces standards, educates, and
conducts research to prevent incidents. Currently there are
discussions underway at both the PHMSA and at the
Washington Utilities and Transportation Commission to
clarify the definition of transmission versus distribution level
pipelines. Today transmission high pressure supply lines are
designated as those operating above 20% yield strength.1
Under this definition, Avista has 76 miles of transmission
pipe (the Kettle Falls system) and 270 miles of high pressure distribution (supply) pipe in Washington. If
this classification is changed, all 346 miles of the Company’s natural gas pipeline would have to be
operated as transmission. Transmission pipelines require a significantly higher level of maintenance,
integrity management, and inspections to operate. Thus this
change would impact Avista’s Capital and O&M budgets and
have a significant impact on technical and field resources as
well. The Company is awaiting a decision on this issue.
As another example, Avista is required to relocate facilities
to accommodate state, county and municipal infrastructure
projects, often transportation related, and which must be
done at the Company’s expense. The schedules for these
moves are not always provided with enough notice to be
included in Avista’s budgets. In addition, there are
increasing restoration requirements. In Oregon, for example, specialized
fill is required for trenches, and the entire roadway must sometimes be resurfaced rather than
restoring the asphalt directly over the trench itself as we do in most other districts. Extensive
1 Yield strength is an indication of the minimum level of internal stress a pipeline can experience and maintain integrity. https://sciencing.com/calculate-
smys-5332072.html
Clearwater Paper Gas Service
Executive Summary
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 3 of 25
landscaping, new sidewalks, a large number of traffic control measures, and the like are becoming
more commonplace when these requests are made, all of which hit Avista’s Natural Gas budget, often
unexpectedly, and without Avista’s choice or control.
Adding additional complexity, the gas business has been particularly hard hit by workforce issues. The
industry is experiencing challenges in attracting and retaining the experienced workforce needed for
gas construction work. As mentioned, this business requires
very specialized skills. Over the past few years, lower gas
prices led to the layoff of thousands of employees who have
moved on to other industries.2 Qualified workers are hard to
come by across the industry. Avista and its contractors are
facing this problem as well. Not only is it difficult to attract
workers to this business, it is difficult to keep them, and the
cost of doing so continues to rise. Increasing competency
requirements and regulatory obligations are also causing
workers to move to other types of construction activities
where these requirements don’t exist and the work is easier.
This report attempts to document the business investments
that are known and why they are important to serving customers and providing safe, reliable natural
gas service and infrastructure. It describes Avista’s work to manage through these issues by developing
Capital and O&M programs that meet customer and regulatory requirements while attempting to be as
cost effective and efficient as possible. The primary focus is always safety, as there is nothing more
important to the gas industry, and to Avista, than the safety of customers, employees, and the
communities served.
For more information about Avista’s natural gas business, the
issues facing the natural gas industry, the Company’s natural
gas safety and public outreach programs, and a glossary of
terms, please see the Avista’s Natural Gas Infrastructure Plan
2019, available on the Company’s internal website3 or by
request.
2 Since 2014 more than 440,000 jobs were lost in the oil and gas industry. Irina Slav, “Recovery? The Oil and Gas Industry is Hiring Again,” USA Today,
November 2, 2017, https://www.usatoday.com/story/money/energy/2017/11/02/recovery-oil-and-gas-industry-hiring-again/819773001/
3 Go to the Avenue, Tools and Resources tab, under “Avista Infrastructure Plans”
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 4 of 25
Avista owns and operates nearly 8,000 miles of
natural gas distribution mains serving about
350,000 customers across Washington, Idaho,
and Oregon.4 The natural gas Avista purchases
can be transported via six connected pipelines
on which the Company holds first contractual
transportation rights, with access to both U.S.
and Canadian supplies.5 In 2019 the Company
delivered about 345 million therms of retail
natural gas and over 504 million therms of
wholesale natural gas, generating revenues of
approximately $288 million dollars.6 Avista’s
electric generation mix is also heavily
dependent upon natural gas as a fuel. In a
typical year, the Company’s electricity portfolio is comprised of about 49% hydro, 35% natural gas-
fired, 9.5% coal, 4.5% wind, and 2% biomass generation.7 Natural gas is a significant part of Avista’s
business on both the electric and the gas side, allowing us to serve customers energy needs in diverse
and cost effective ways.
The Company has experienced steady
growth in natural gas customers,
though hookups were down in 2019
due to the expiration of the
Washington Line Excess Allowance
Program (LEAP). This program helped
customers receive an allowance to
help pay for connecting to Avista’s
natural gas system. The forecast over
this budgeting period indicates an
average of approximately 5,800
hookups per year going forward.
4 2019 Avista Quick Facts, https://www.myavista.com/about-us/our-company/quick-facts
5 Oregon Public Utility Commission UG-325, Direct Testimony of Scott L. Morris, page 3,
https://edocs.puc.state.or.us/efdocs/HTB/ug325htb154322.pdf. Note that typically approximately 25% of the Company’s supply comes from the U.S. with
the remaining 75% coming from Canadian sources.
6 From Avista’s 2019 Quick Facts. Note that electric revenues were approximately $800 million during the same time period.
7 Avista 2017 Electric IRP (the most current as of this printing), https://www.myavista.com/about-us/our-company/integrated-resource-planning, select
“Electric Integrated Resource Plan (PDF),” page 4-1. For more information about Avista’s natural gas generating resources, please see Appendix A.
Figure 1. Avista Natural Gas Hookups
Introduction
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 5 of 25

Classification of Infrastructure Need by Investment Drivers

As a way to create more clarity around the particular needs being addressed with each capital
investment, as well as simplifying the organization and understanding of Avista’s capital spending, the
Company has organized its capital infrastructure investments by the classification of need or
“Investment Driver.” The need for investments associated with each investment driver is briefly
defined below. Please note that all dollar figures shown in this report represent expenditures on a
system wide basis.

1. Customer Requested – This category is
set aside primarily for connecting new
customers or enhancing their service as
requested. Typical projects include
installing gas facilities in new housing or
commercial developments or moving
equipment at a customer’s request, for
instance if they are building a deck or
addition that conflicts with the current
location of their gas meter.

2. Mandatory & Compliance – This is a driver
related directly to compliance with laws,
regulations and agreements, areas for which
the Company has little or no discretion
in spending. This category also applies
to national safety codes and
regulations. Projects in the Mandatory
and Compliance category may include
the obligation to relocate facilities
based on road construction projects,
environmental compliance, and
replacement of pipeline protection
systems based on national code
requirements. Compliance
expenditures are often related to
safety. The Gas group’s laser focus on safety
and compliance leads this to be a primary
spending category.

Avista’s Natural Gas Capital Investments

Figure 3. Avista Projected Five Year Budget for Gas
Capital Expenditures by Investment Driver

Figure 2. Avista Total Historic Actual Capital
Spending by Investment Driver

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 6 of 25
3. Failed Plant & Operations – This category of spending
replaces failed equipment, typically related to storm
damage or the unexpected failures of capital assets. In Gas,
this funding is under a program called Non-Revenue, which
tends to be reactionary (unplanned) work such as
responding to leaks, damaged equipment, dig-ins, etc. The
forecasted budget levels for this category are based on
historical spend.

4. Asset Condition – This driver is focused on replacing assets
at the end of their useful service life. Avista uses an
analytical approach to asset replacement which includes asset criticality, inspections, and
optimization of life cycle costs. Gas pipeline condition (and associated equipment) is directly
related to customer and employee safety, so the equipment is carefully monitored and replaced
as necessary. Laws and regulations are also a factor. For example, regulator stations are required
by the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration
(PHMSA) to be kept in very specific condition.8 Federal Code also requires that Avista maintain an
active program related to asset condition, including evaluating risk related to gas facilities and
mitigating any such risks, such as unconventional or obsolete pipe, deteriorated pipe and
associated equipment, or corrosion issues.

5. Customer Service Quality & Reliability – This category of spending helps Avista meet customers’
expectations for quality of service and reliability. Programs in this category include the
Washington and Idaho advanced meter infrastructure (AMI) in the Distribution business unit
budget or customer facing technology programs implemented by Enterprise Technology. There
are no specific funds set aside in the gas business unit
for this category in the current budget cycle.

6. Performance & Capacity – This driver helps ensure
that assets satisfy business needs and meet
performance and reliability standards. In the gas
business, many of the projects in this category are
related to reinforcing gas service as customer loads
grow and change. The goal of these programs is to
ensure that customers have an adequate supply
of natural gas to keep them warm on the
coldest days through effectively managing the
gas delivery system. This category also includes
technology that allows monitoring and
controlling the system more proficiently for
safety and reliability.
8 DOT Code of Federal Regulations Title 49 Transportation 192.739, https://www.gpo.gov/fdsys/pkg/CFR-2017-title49-vol3/xml/CFR-2017-title49-vol3-
sec192-739.xml
Star Road City Gate
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 7 of 25
Currently Planned Capital Investments in Natural Gas
2020 – 2024

For the next five-year planning
horizon, Avista expects to spend
nearly $385 million in capital
dollars for the Natural Gas
business, allocated across five of
the six investment drivers
described above. Avista’s programs
for gas infrastructure investments
are summarized by investment
driver below.

Business Driver 2020 2021 2022 2023 2024 5 Year Total
Customer Requested $30,123,307 $25,855,402 $25,177,121 $25,009,773 $25,260,975 $131,426,578
Mandatory & Compliance $30,233,892 $30,758,892 $31,639,816 $32,068,645 $32,425,648 $157,126,893
Failed Plant & Operations $8,000,000 $8,000,000 $8,000,000 $8,000,000 $8,000,000 $40,000,000
Asset Condition $2,000,000 $2,200,000 $2,210,000 $2,220,000 $2,230,000 $10,860,000
Performance & Capacity $5,960,000 $6,650,000 $7,700,000 $3,700,000 $2,700,000 $26,710,000
Total $76,317,199 $73,464,294 $74,726,937 $70,998,418 $70,616,623 $366,123,471
Customer Requested9

Growth often refers to new service
connections, as in growth in the
number of customers, however,
these investments are primarily
beyond the control of the Company,
and as such they do not reflect a
plan or strategy on the part of
Avista. Responding quickly to
customer requests is a requirement
of providing utility service. This kind
of work may include hooking up
9 In 2018 these expenditures jumped due to the Company’s Advanced Metering Infrastructure (AMI) gas meter installations in Washington.
Figure 4. Avista Gas Capital Budget by Investment Driver

Table 1. Avista Natural Gas Planned Capital Expenditures by Driver
Figure 5. Avista Gas Capital Expenditures Based on Customer Requests & Growth 9

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 8 of 25
new customers or adding meters, regulators, and/or electronic transmitting devices to read meters.
The Gas Revenue classification specifically covers the addition of new customers.

Mandatory & Compliance

Avista operates within a complex
regulatory and business framework
and must adhere to state and federal
laws, agency rules and regulations,
and county, city, and municipal
ordinances. Compliance with these
rules, as well as contracts and
settlement agreements, represent
obligations that are generally required
by others and largely outside of
Avista’s control. The types of gas
investments that fall into this driver
include the obligation to relocate facilities to
accommodate
state, county and municipal infrastructure projects (frequently
transportation related) and compliance with pipeline safety and
environmental regulations. Regulations are increasing and becoming
progressively more expensive to implement,10 as indicated by the
increasing budget for this category.

In the natural gas business, the PHMSA requires pipeline operators to
identify and document as well as have adequate cathodic protection in
place for pipelines to protect against corrosion. Pipeline operators are
also required to identify and mitigate the highest risk areas of their
natural gas distribution systems11 and to remove any customer-
10 The jurisdictions in which Avista must perform the work are becoming increasingly demanding in their requirements, including calling for additional work
as a condition of construction, requiring excessive and extensive re-paving and/or landscaping, and even hiring additional flaggers, all of which increase
costs in both capital and O&M budgets.
11 For Avista, a high risk is the bending stress that occurs on Aldyl-A service pipe where it connects to a steel main pipe.
Figure 6. Avista Gas Capital Expenditures Based on Mandatory
& Compliance

Table 2. Avista Natural Gas Customer Requested / Growth Capital Expenditures

Customer Requested 2020 2021 2022 2023 2024
Gas ERT Minor Blanket $863,119 $812,907 $829,275 $851,543 $874,735
Gas Meters Minor Blanket $1,224,583 $1,078,078 $1,091,969 $1,118,911 $1,147,112
Gas Regulators Minor Blanket $483,208 $450,535 $450,184 $454,826 $459,891
Gas Revenue $27,552,397 $23,513,882 $22,805,693 $22,584,493 $22,779,238
Total $30,123,307 $25,855,402 $25,177,121 $25,009,773 $25,260,976
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 9 of 25
installed encroachments over pipelines. In addition, the Gas group must test meters to make sure they
are performing correctly and replace them if they do not. Another capital cost results from local
authority requests to relocate equipment residing on public easements, which must be done at the
Company’s expense. Note that a primary driver for gas related mandatory and compliance
expenditures is safety, as indicated by the projects below.

Cathodic Protection Program

The purpose of the Cathodic Protection (CP) program is to protect Avista’s buried steel pipe from the
effects of natural corrosion. Corrosion is the result of an electro-chemical reaction of a metal surface to
its environment (such as the air or water) which causes a loss of
metal from the surface, reducing the integrity of the pipeline. This
can be seen as rust. The mechanism of cathodic protection is to
make the pipeline part of an electric circuit by energizing the pipe
with direct current, often provided by a device called a rectifier. The
rectifier transforms the voltage level from the alternating current
that it receives from the incoming power line into direct current (DC)
that is used to electrify the pipe. The DC current is connected via a
cable to a “sacrificial” metal anode that is easier to corrode than the
pipe itself. This forced electrochemical process directs the corrosion
process to the sacrificial metal, which protects the pipeline itself
from corroding. In most cases the
pipe also has a high-dielectric strength special coating in conjunction
with the use of a CP system.

For this process to be effective, the circuit and power source must be
properly maintained. The U.S. Department of Transportation Pipeline
and Hazardous Materials Safety Administration requires that gas
pipelines installed after July of 1971 must have CP systems in place and
that the performance must be closely monitored and tested at least
An
o
d
e

Table 3. Avista Natural Gas Mandatory & Compliance Capital Expenditures

Mandatory & Compliance 2020 2021 2022 2023 2024
Cathodic Protection Program $715,000 $715,000 $715,000 $700,000 $700,000
Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
Isolated Steel Replacement Program $1,400,000 $1,400,000 $1,600,000 $1,600,000 $1,600,000
Overbuilt Pipe Replacement Program $400,000 $400,000 $400,000 $250,000 $0
Planned Meter Change Out Program $1,400,000 $1,200,000 $1,300,000 $1,300,000 $1,300,000
Replacement Street and Highway Program $3,000,000 $3,000,000 $3,000,000 $3,000,000 $3,000,000
Total $30,233,892 $30,758,892 $31,639,816 $32,068,645 $32,425,648
$23,318,892 $24,043,892 $24,624,816 $25,218,645 $25,825,648
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 10 of 25
once a year. If a rectifier is used, it must be checked six times a year.12 Failure of these systems is
especially difficult to predict or determine because most of the pipelines are buried underground so
deterioration is not immediately visible. Some of Avista’s CP systems have already exceeded their
useful life and thus have increasing risk of failure. These old systems must be replaced. Besides
compromising the corrosive protection for Avista’s infrastructure,
these aged systems create the potential for the Company to be at risk
of non-compliance as well as increase safety concerns for employees
and the public.

Gas Facility Replacement Program (GFRP) Aldyl-A Pipe
Replacement

The PHMSA requires pipeline operators to
identify and mitigate the highest risks in their
gas distribution systems. Over time the
industry discovered that the certain resins
used in Aldyl-A pipe may become brittle,
causing leaking and failure.13 It is the
Company’s position that this issue creates
unacceptable risk. Even above the mandatory
requirements, this program is designed to
protect public safety and property by proactively replacing all of this type of pipe existing within
Avista’s service territory.

The Gas Facility Replacement Program Aldyl-A Pipe Replacement replaces at-risk pipe sections over a
20 year time period starting with the highest risk areas. This work is done via a program endorsed by
the Washington Utilities and Transportation Commission.14 The Company identified approximately 737
miles of priority Aldyl-A main pipe (1¼” through 4” in size) manufactured prior to 1985 and about6,000
transition tees which need to be replaced. Transition tees connect the service lines to the main lines.
The Company used a risk consequence model to try to predict where leaks are most likely to occur,
then folded in information on customer density in these areas, specifically focusing on areas of
congregation such as schools, hospitals, and apartment complexes.

The replacement program began in 2012 and is estimated to be completed within twenty years. It
costs about $69 to $110 per foot depending upon conditions.15 For example, replacing pipeline under a
roadway requires mitigation such as repaving the street and replacing associated infrastructure like
12 U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, Cathodic Protection Requirements,
https://primis.phmsa.dot.gov/comm/FactSheets/FSCathodicProtection.htm
13 Aldyl-A pipe is a polyethylene pipe made by DuPont before 1984 and widely used throughout the gas industry. Over time it was discovered that this pipe
can become brittle and prone to leaking, which can create safety risks.
14 WUTC UG-14089 https://www.utc.wa.gov/_layouts/15/CasesPublicWebsite/GetDocument.ashx?docID=256&year=2014&docketNumber=140189
15 Before the Washington Utilities and Transportation Commission, Testimony of Don Kopczynski, page 12,
https://www.utc.wa.gov/_layouts/15/CasesPublicWebsite/GetDocument.ashx?docID=258&year=2014&docketNumber=14nk0189
A storm drain was placed on top of Avista gas
main, damaging the pipeline

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 11 of 25
trees and sidewalks, which is more expensive than work in a rural area. The Company makes every
attempt to minimize the impact of this work on the public and public infrastructure.16

Isolated Steel Replacement Program

The program identifies and documents cathodically isolated steel pipe sections, including cathodically
isolated steel risers,17 installed after July 31, 1971 with the goal of ensuring they are either adequately
protected against corrosion or are replaced.18

Avista protects all of the buried steel pipes in the system from corrosion using cathodic protection with
large, strategically placed anode beds. In order to protect the pipeline, this system relies on all of the
steel pipe in a section to be continuously connected together (electrically) to form one big electrical
circuit directly connected to the anode bed. Unfortunately some of these circuits of steel pipe have
been broken up with plastic pipe as pipelines have been replaced over time. A section of steel pipe that
is not directly connected (electrically) to the larger system is considered ‘isolated.’ The anodes cannot
protect this pipe because they aren’t electrically connected to it anymore, so it is no longer adequately
protected from corrosion. Federal and state regulations require at least 10% of the Company’s isolated
steel sections of pipeline be inspected each year. If these sections are not cathodically protected and
are thus at risk of corrosion, they must be replaced. With this program, the Company is replacing 10%
of the isolated steel risers and short sections of isolated steel main within one year of their discovery.
This work is stipulated in an agreement between Avista and the Washington Commission.19 Since the
company has agreed this is prudent in the Washington jurisdiction, we have also extended this plan
into our Idaho and Oregon jurisdictions.

Overbuilt Pipe Replacement Program

The Federal Code of Regulations20 requires utilities
to remove customer-installed encroachments or
“overbuilds” that interfere with or prohibit the
ability to safely operate the gas system. Typically an
overbuild situation occurs when a structure is
erected over the top of preexisting natural gas
facilities. These structures or barriers prevent
mandatory maintenance such as leak surveys, which
16 For a great summary of this program, see Michael B. Whitby and Dan Gigler, “Gas Facility Replacement Program,”
https://www.utc.wa.gov/regulatedIndustries/transportation/TransportationDocuments/Avista%20-%20Aldyl%20A%20Replacement%20Program.pdf
17 Risers are the part of the pipe that transitions the pipe from underground to the surface and, in some cases, from plastic to steel.
18 49 CFR 192.455 and 49 CFR 192.457 - External corrosion control for buried or submerged pipelines per United States Code.
https://www.gpo.gov/fdsys/granule/CFR-2010-title49-vol3/CFR-2010-title49-vol3-sec192-455 and https://www.gpo.gov/fdsys/pkg/CFR-2017-title49-
vol3/pdf/CFR-2017-title49-vol3-sec192-457.pdf
19 “Isolated Steel Settlement Agreement Report, Docket PG-100049,
https://www.utc.wa.gov/_layouts/15/CasesPublicWebsite/GetDocument.ashx?docID=66&year=2010&docketNumber=100049
20 This part of the Federal Code of Regulations prescribes minimum safety requirements for pipeline facilities and the transportation of natural gas. US
DOT 49 CFR, Part 192. https://www.law.cornell.edu/cfr/text/49/part-192
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 12 of 25
are typically performed by walking directly above the gas pipeline while operating the leak detection
equipment. Overbuilds also increase the Company’s operating costs due to the need to return to the
overbuild location multiple times to complete leak surveys and perform other maintenance tasks.

Buildings over a pipeline that are not properly vented also create
the possibility of natural gas leaking and accumulating inside the
structure, which creates additional safety hazards. Avista’s
Overbuilt Pipe Replacement Program is designed to identify and
remediate these kinds of issues. The work tends to be focused on
overbuilds in mobile home parks. Due to the dynamic nature of
these parks, they represent areas of high risk because the
dwellings can be easily sited over buried facilities. Mobile homes
are not the only structures built over pipelines. Sheds, patios, and
more can cause problems. When these situations arise, the
Company handles them on a case-by-case basis to protect the
interests of both Avista and other involved parties. This program funds the capital costs of relocating
facilities to ensure adequate access to the pipeline and to preserve customer safety.

Planned Meter Change Out (PMC) Program

Accuracy in measuring customer usage is critical to both the customer and the Company. To ensure
that meters are functioning correctly, Avista performs statistical meter sample testing based on
manufactured year, meter model and size. If analytics determine that
a “meter family” is no longer taking precise measurements, the entire
group of meters within that category are replaced. Conversely, if the
analytics determine that the meters are testing well, the sample size
for that group is reduced. This
analytics-based methodology makes
certain that problematic meters are
identified and replaced quickly while maximizing the efficiency and cost
effectiveness of the sampling process.21

Replacement Street and Highway Program

Virtually all of Avista’s pipelines are located in public utility easements
which are controlled by local jurisdictional franchise agreements. When
local authorities request relocation, Avista is mandated to do so and
usually at the Company’s expense. Unfortunately the expenditures in
21 This program ensures that the Company is in compliance with Oregon’s OAC 860-023-0015 “Testing Gas and Electric Meters” Tariff Rule #18
https://secure.sos.state.or.us/oard/viewSingleRule.action?ruleVrsnRsn=221169 and Idaho’s IDAPA 31.31.01.151 through .157 “Standards for Service”
https://adminrules.idaho.gov/rules/current/31/313101.pdf and Washington’s WAC Chapter 480-90-333 through -348 “Gas companies – Operations” Tariff
Rule #170 http://apps.leg.wa.gov/wac/default.aspx?cite=480-90
Gas Line Relocated for Road Work
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 13 of 25
this category are difficult to predict. Most often the impacted utilities (natural gas, electric, phone,
cable, etc.) are notified of projects requiring relocation in the spring after local budgets are developed.
Avista typically utilizes historical expenditures to estimate what might be required in this spending
category.

Failed Plant & Operations

Non-Revenue Program

This program covers assets that
have failed and/or which must be
exchanged in order to provide
continuity and adequacy of service
to customers. In addition to outage
response, typical work may involve
repair and replacement of facilities
under a variety of circumstances
such as dig-ins, damage repair or
other unplanned work that comes
up. This funding, called the Non-
Revenue Program, has approximately $8
million in funds set aside to cover this type of situation.

Funding for this type of work is very hard to predict, as it tends to be reactionary, such as relocations
requested by customers (other than roadway relocations), leak repairs, pipeline that is found to be too
shallow, or other such issues. If the work is large enough to warrant
significant capital expenditures, it is prioritized and ranked against
other Company capital projects, but smaller projects are funded
through this program.

Note that if customers request relocation of gas facilities, Avista is
bound by tariff language to do so at the customer’s expense. However,
if the Company sees such a relocation as the chance to improve or
update the gas system at the
same time, the additional costs are
charged to this category. Another common expenditure under
this program is the reduction in the number of single-service
taps off the supply main to serve a small group of customers
versus a full distribution tap. By reducing the number of stations,
Gas Meter Barrier

Table 6. Avista Gas
Failed Plant &
Operations Capital
ExpendituresGas
Meter Barrier

Table 6. Avista Gas
Failed Plant &
Operations Capital
ExpendituresGas
Figure 7. Capital Expenditures Based on Failed Plant & Operations
Gas Leak to be repaired

Gas Leak to be repaired

Gas Leak to be repaired

Gas Leak to be repaired
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 14 of 25
maintenance costs are lowered.22 Meter barricades also fall under this category. These are installed if
vehicles may get too close to existing meters in order to protect them from damage.23 This program
essentially covers unforeseen work the Company performs to satisfy customers and maintain the
safety, reliability and integrity of the system.

Asset Condition 24

Assets of every type will degrade
with age, usage, and other factors,
and must be replaced or substantially
rebuilt at some point in order to
ensure the reliable and acceptable
continuation of service as well as the
safety of the public and Avista
employees. The replacement of
assets based on condition is
essentially the practice of removing
them from service and replacing
them at the end of their useful life.
Across the utility industry and likewise for Avista, the replacement of assets based on condition
constitutes a substantial portion of the infrastructure investments made each year.

At Avista, the goal is to manage assets in a manner that optimizes their overall value over the lifecycle
of each particular asset class. Asset replacement strategies are “optimized” in the sense that a given
approach may not achieve the overall lowest possible lifecycle
cost, but rather the lowest cost that allows the Company to
meet a variety of important
performance objectives,
such as public safety or the
efficient use of employee
crews. Because failure of
critical assets is
unacceptable, they must be
replaced before the end of their useful life even though they are still
providing reliable service. In other instances it may be reasonable to
22 These small taps are called Single Service Farm Taps (SSFT), and many of Avista’s SSFTs are reaching the end of their service life at this time.
23 These barricades are required by federal mandates and greatly improve the safety of the system.
24 The large expenditures in 2018 are due to the installation of Advanced Metering Infrastructure (AMI) gas infrastructure in Washington.
Figure 8. Avista Gas Capital Expenditures Based on Asset Condition 23

Failed Plant & Operations 2020 2021 2022 2023 2024
Non-Revenue Program $8,000,000 $8,000,000 $8,000,000 $8,000,000 $8,000,000
Table 4. Avista Natural Gas Failed Plant & Operations Capital Expenditures

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 15 of 25
wait until an asset fails before it is replaced, a strategy known as “run to failure.” The Natural Gas
group programs in the Asset Condition driver category have the goal of replacing deteriorated steel
pipe, meters, and regulators as described below.

Deteriorated Steel Pipe Replacement Program

Multiple factors impact risk and the replacement of facilities including things like material failures,
environmental impacts, increased leak frequency, unconventional/obsolete pipe sizes, no protective
coating (bare steel) and/or problems with protective coating on pipe. This program is intended to
address and remedy these issues. Pipe is regularly inspected across
the service territory. When deteriorated pipe is identified, it is
ranked by risk factor. The Company believes that replacing
deteriorated pipe prior to failure in a planned manner will not only
increase the safety of the system and customers but is also more
cost effective than responding to unplanned emergency situations.
The Deteriorated Steel Pipe Replacement Program is designed to
specifically target and prioritize pipelines that may affect safety
and system reliability. Avista believes that systematically replacing
facilities on a planned basis reduces risk and increases the
efficiency and effectiveness of expenditures over time.

Encoder Receiver Transmitter (ERT) Replacement Program

An ERT or Encoder Receiver Transmitter is a device that automatically records gas usage then sends the
data to a remote data collector. These devices contain batteries. When these batteries fail, the
customer’s usage is not sent to the collector and on to the Company, so it is estimated and entered
From this….

… to this

Table 5. Avista Natural Gas Asset Condition Capital Expenditures

Asset Condition 2020 2021 2022 2023 2024
Deteriorated Steel Pipe Replacement Program $1,000,000 $1,000,000 $1,000,000 $1,000,000 $1,000,000
ERT Replacement Program $200,000 $200,000 $210,000 $220,000 $230,000
Regulator Station Replacement Program $800,000 $1,000,000 $1,000,000 $1,000,000 $1,000,000
Total $2,000,000 $2,200,000 $2,210,000 $2,220,000 $2,230,000
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 16 of 25
manually. Customers do not like to have their usage estimated due to the potential for billing errors
and subsequent true-up bills. Billing estimates often result in a high number of customer complaints.
The Company currently has about 106,000 ERT units in Oregon, meaning there
are a lot of batteries out there. The batteries are sealed inside the ERT for
protection against weather and other environmental elements. It has been
found to be more cost effective to replace the entire ERT rather than try to
open them, replace the battery, and adequately reseal them. The average
battery life is 16 years. The Company proposed a measured and levelized
approach to this battery issue, developing a systematic replacement
program of 7,000 ERTs per year beginning with the oldest units. This
program will be primarily focused in Oregon, as the replacement of the ERTs in Washington and Idaho
will take place under the Advanced Metering Infrastructure (AMI) program.

Regulator Station Replacement Program

Regulator stations reduce and regulate the pressure in gas pipes.
These stations and their associated equipment are critical to the
successful operation of the gas system and must be replaced
when they no longer meet standards or have reached the end of
their service life. At times they are at an age where replacement
equipment is no longer available. The maintenance and
operation of these stations is regulated by the Federal Code of
Regulations.25 Avista’s program is in full compliance with this
Code and further is designed to improve system operating performance, enhance safety, replace
inadequate or antiquated equipment that is no longer supported, and ensure the reliable operation of
metering and regulating equipment. The goal of this program is to replace the highest priority projects
every year, though new ones are being
continually added. 26

Performance & Capacity

Avista’s projects and programs grouped
in this category of need include a range
of investments that address the
capability of assets to meet defined
performance standards, typically
developed by the Company or based on
a demonstrated need. Avista is also
attentive to investment opportunities to
25 49 CFR 192.739 - Pressure limiting and regulating stations: Inspection and testing https://www.law.cornell.edu/cfr/text/49/192.739
26 Note that the increase in 2021 is due to the high pressure reinforcement program in Warden, described in this report on page 18.
Figure 9. Capital Expenditures Based on Performance & Capacity 25
Natural Gas Regulator Station

Table 5. Avista Gas Asset Condition
Capital ExpendituresNatural Gas
Regulator Station

Table 5. Avista Gas Asset Condition
Capital ExpendituresNatural Gas
Regulator Station

Table 5. Avista Gas Asset Condition
Capital ExpendituresNatural Gas
Regulator Station
Itron’s Natural Gas Encoder
Receiver Transmitter Device

Itron’s Natural Gas Encoder
Receiver Transmitter Device

Itron’s Natural Gas Encoder
Receiver Transmitter Device

Itron’s Natural Gas Encoder
Receiver Transmitter Device
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 17 of 25
improve the performance of the gas distribution system when supported by a study or analysis that
demonstrates the cost-effectiveness of the benefits achieved for
customers.

Natural Gas has many projects related to Performance and Capacity,
all of them are related to reinforcing the existing natural gas system
due to load growth or age-required replacement. During this budget
cycle, these types of reinforcements will likely occur in the
Washington cities of Cheney, Airway Heights, Pullman, and Warden,
and in the Sandpoint, Idaho area. This investment driver also funds
the placement of monitoring equipment at gate and regulator
stations to allow the Company to monitor what is happening in the
gas system in real-time.

The Gas Planning department routinely runs load studies on Avista’s
gas distribution system to identify areas of the system with insufficient capacity to serve existing firm
customer loads based on “design conditions,” which refers to the projected system demand for a
“coldest day on record” weather event. Avista attempts to ensure that the natural gas system is
adequate to serve customer load in extreme weather conditions when customers need service the
most. Identified deficient areas are given a priority level based on the severity of the risk associated
with insufficient system capacity. Below is more information about the Natural Gas programs that fall
into the Performance and Capacity category, most of them are related to upgrading the system to
ensure that customers have adequate service.

Airway Heights High Pressure (HP) Reinforcement Project

Airway Heights is the fastest growing area in Spokane County. The
Company’s capacity there is no longer sufficient to serve
customers, primarily for space heating, during severely cold winter
weather. This reinforcement project will install a new loop of
approximately 20,000 feet of high pressure gas main to serve this
area and reinforce the existing system.

Table 6. Avista Natural Gas Performance & Capacity Capital Expenditures

Performance & Capacity 2020 2021 2022 2023 2024
Airway Heights HP Reinforcement Project $50,000 $1,950,000 $0 $0 $0
Cheney HP Reinforcement $4,710,000 $3,100,000 $0 $0 $0
Intermediate Pressure Reinforcement Program $1,000,000 $1,300,000 $1,500,000 $1,000,000 $1,000,000
Pullman HP Reinforcement Project $0 $0 $100,000 $2,400,000 $0
Schweitzer Mtn Rd HP Reinforcement $0 $0 $0 $100,000 $1,500,000
Telemetry Program $200,000 $200,000 $200,000 $200,000 $200,000
Warden HP Reinforcement $0 $100,000 $5,900,000 $0 $0
Total $5,960,000 $6,650,000 $7,700,000 $3,700,000 $2,700,000
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 18 of 25
Cheney High Pressure (HP) Reinforcement Project

The existing pipeline system that serves the town of Cheney is no longer adequate to serve customer
demands on cold weather days. There are a couple of additional circumstances with this pipeline that
must be noted. It was built between 1957 and 1965 so was not designed to support the current
population of this area. In addition, a large industrial customer on this pipeline has submitted plans to
increase their gas requirements beyond what the current system can provide. The Cheney High
Pressure Reinforcement Project program will address these multiple concerns with one effective
solution.

Intermediate Pressure Reinforcement Program

There are continual changes in customer growth and load patterns throughout Avista’s intermediate
pressure (≤60 psig) pipeline system as, for example, new subdivisions are built or businesses open,
close, or expand. The Company has an obligation to serve firm customers by providing adequate
capacity every day, including the coldest days of the year. In order
to do this, the service territory and associated gas system is
constantly monitored to identify areas where new customers are
being added or where load patterns have changed. The Gas
Intermediate Pressure Reinforcement Program focuses on
maintaining adequate gas system capacity by upsizing existing gas
mains, looping supply lines to provide back-up service capability,
and other reinforcements or upgrades that may be needed to
provide dependable, reliable service to customers across the
service territory. Projects are evaluated and sorted by priority to
maximize the value of the funding in this program.

Pullman High Pressure (HP) Reinforcement Project

Load growth in the Pullman area has exceeded the capacity of the
existing Pullman Gate Station.27 The contracted capacity at this gate is 786,000 cubic feet per hour but
the projected need for design condition is 916,000 cubic feet per hour, which puts approximately 1,300
customers at risk of losing gas service when temperatures plunge. This project proposes installing a gas
main between the Moscow Gate Station and the Pullman Gate Station (approximately 3 miles of
pipeline) to balance the loads, create a more reliable looped system,28 to allow for projected area load
growth, and to make sure that no customers are at risk of losing gas service on cold winter days.

27 A gate station is the supply point into Avista’s system. It takes high pressure gas from a larger pipeline, reduces the pressure, and moves it onto a
distribution pipeline.
28 A looped system means that customers can be served from more than one pipeline so if a pipeline has a failure or is out of service for maintenance,
customers can be served from a different pipeline without experiencing an outage.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 19 of 25
Schweitzer Mountain Road High Pressure (HP) Reinforcement

Load growth in the Sandpoint area has exceeded the capacity of the existing gas distribution system,
and it gets very cold in Sandpoint, which causes additional strain to the gas system. Avista plans to
reinforce this system by installing 1.3 miles of 6” steel gas main
pipeline and an associated regulator station on Schweitzer
Mountain Road to alleviate this constraint.

Warden High Pressure Reinforcement

Warden, Washington, currently has two concerns associated
with capacity. The first is that the town is supplied with gas from
the fully-subscribed and capacity-constrained Moses Lake
Lateral29 (owned by Williams NWP). Secondly the high pressure
supply line coming into town has reached its capacity. As a result
of current capacity/supply constraints, industrial gas growth
opportunities are hampered within the Port of Warden Industrial
Park as well as other sites in the area. Grant County Economic Development Council and the Port of
Warden have contacted Avista several times related to different commercial ventures interested in the
Port site and are pressing for additional natural gas supply for the area. Schedule and timing are critical
aspects of this project. To address this supply problem, the Company plans to install a new gate station
and approximately 3.2 miles of 6” high pressure distribution pipeline.

Telemetry Program

Gas telemetry is equipment that remotely monitors system
pressures, volumes, and flows across the gas pipeline system.
It allows the Company to see what is happening at gate and
regulator stations, monitor large industrial customer usage
rates and interconnection points. Avista attempts to replace
this equipment at the end of its useful life or as it fails.
Another goal is to keep the technology current, as this
equipment is critical in identifying problem areas in the
pipeline such as a lack of pressure to serve customers or
other abnormal situations that must be corrected in order to
provide safe, reliable service. The current funding level adds
about five new telemetry sites and upgrades or replaces an
additional 15 sites per year based on the Company’s
experience and expectations.

29 Lateral pipelines deliver natural gas to or from the mainline and are typically between 6 and 16 inches in diameter.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 20 of 25

Avista monitors the gas system very closely to guarantee that critical equipment remains functional
and the system is fully intact. O&M expenditures allow the Company to maintain and operate the gas
system in the most safe, reliable, and efficient way possible. These expenditures permit the Company
to respond when damage occurs from weather, vehicles or dig-ins, maintain facilities, answer customer
requests for locating underground pipelines, read meters, and a host of other issues that arise in this
complex system, all for the purpose of keeping the natural gas safely and efficiently flowing to
customers and to power plants.

As might be expected, the largest
group of O&M expenditures are
related to maintaining and
repairing equipment. Assets are
replaced because they are
damaged by weather or storms,
but that is only one component of
the investments needed to keep
the gas system operating safely,
effectively, and efficiently.
Equipment wears out or quits
performing as intended and must
be replaced. In the natural gas realm,
equipment failures can have serious safety consequences. Adequate maintenance is critical.
Equipment failure can also lead to loss of supply, leaving customers without heat and power plants
without fuel to generate electricity. Leaking pipelines with a path of underground migration to
structures can cause gas explosions and serious property damage or even loss of life. Maintenance of
this system is even more important with older facilities, as is the case with much of Avista’s system.
Most of Avista’s natural gas pipeline was laid in the 1950s and 1960s. The oldest pipe was installed in
the 1930s.

Avista performs preventative maintenance or repair of mains, regulators,
meters and meter reading transmitters, regulator stations and gate stations.
Maintenance work in the natural gas area also includes monitoring and
adjusting pipeline pressure as needed to maintain reliability. It encompasses,
cathodic protection and other infrastructure work, construction, dispatch, gas
supply activities, truck and equipment expenses, and the field employees who
perform the repairs and maintain the system.

Avista’s Natural Gas O & M Investments

Figure 10. Historical Avista Gas Actual O&M Expenses 2009-2019
Pipeline Leak Detection
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 21 of 25
Additional tasks included in the O&M category include sustaining the property related to natural gas
equipment, maintaining the grounds around buildings and regulating stations, maintaining heating,
cooling, and electrical systems, providing adequate security, and general supplies. Large repairs and
maintenance tasks are performed by Company crews and are occasionally supplemented by
contractors.

Avista’s Natural Gas employee tasks are highly
varied and involve everything from technical
construction and maintenance activities to
customer service. They perform a significant
amount of regulatory-related work that
necessitates a large amount of documentation
required by the federal, state, local, and
Commission governance over gas operations.
Most importantly, their work is directly related
to the safety of lives and property. Specialized
training is required for these employees in
order to perform their work, especially related to the protection of the public. They receive extensive
education on gas system safety procedures, regulations,
and legal requirements.

Avista employees are dispatched to customer homes and
businesses to address safety concerns as well as being first
responders to make safe and/or repair damaged or leaking
gas facilities. Another operations function is leak-related
work such as responding to gas odor reports, surveying the
pipeline system to identify leaks, and performing the
repairs needed to fix them. If anyone calls Avista to report
that they smell gas, a gas serviceman is dispatched with a
service order to investigate the concern. Strict standards
are in place around the amount of time in which the
Company must respond to these kinds of orders. If a leak is
found, it is dealt with on a priority basis. The Company also responds to dig-ins related to natural gas
pipelines and other damage to stations, pipelines, and equipment created by vehicles, earth
movement, construction, etc.

Besides maintenance activities, customer service related expenditures are also a significant portion of
gas operations. Gas employees perform customer-requested maintenance, read meters, handle
general service calls, manage service turn off/on, and deal with collections when required. The gas
group also manages customer concerns about equipment, even lighting pilot lights for people who
need extra help. Avista’s Gas employees are also very engaged in community relations and in educating
the public about gas and safety.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 22 of 25

Avista takes the safety of customers and employees very seriously. The Company’s Natural Gas
business unit has a laser focus on this aspect of their work, and designs Capital and O&M programs
that are robust, proactive, and designed to ensure that the natural gas system is as safe as it can
possibly be while providing a level of service and cost effectiveness that customers and regulators
expect. As depicted in this report, each of these programs has a specific goal and purpose in serving
customers safely and effectively, inspecting and protecting the existing infrastructure, thoughtful,
measured replacement of end-of-life assets, adding equipment to allow additional monitoring and
control, providing additional service as requested, responding to location and relocation requests, and
reacting to damage or repair as needed. These programs keep the Company in full regulatory
compliance while balancing the need to provide service to customer even on the coldest days.
The Company believes these natural gas programs have been, and will continue to be, extremely
effective in providing the level of service customers request and expect.

For more information about Avista’s natural gas business, the issues facing the natural gas industry, the
Company’s natural gas safety and public outreach programs, and a glossary of terms, please see the
Avista’s Natural Gas Infrastructure Plan 2019, available on the Company’s internal website30 or by
request.

30 Go to the Avenue, Tools and Resources tab, under “Avista Infrastructure Plans”
Wrap Up

Installing natural gas
pipeline across the
Palouse
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 23 of 25

Besides directly serving natural gas customers across the
service territory, Avista has capitalized on the
opportunity to build power generation stations that
utilize this resource. Gas-fired power plants tend to be
less expensive to build than a comparable coal-fired or
hydroelectric plant31 and can be highly flexible in
operations. Natural gas plants can be built for use in
baseload, peaking or both, as they can be designed to
come online and adjust their output quickly. Currently
natural gas comprises about 35% of Avista’s electric
energy supply. The Company owns five natural gas
power plants capable of generating up to 547
megawatts, one of which is a baseload power plant,
Coyote Springs 2. The Company also has natural gas-fired plants specifically intended for peaking or
reserve capability. These facilities can be brought online and synchronized quickly to the grid, providing
the capability to make up the difference between base load and peak load as needed. Their generation
can be varied to meet changing load or system conditions. These plants are also used to provide
operating reserve margins,32 allowing them to respond as needed to changing conditions on the grid,
such as the unexpected loss of a generating unit or a transmission line. They are instrumental in
integrating intermittent wind and solar facilities, as they can respond instantly to changes in the output
from these resources.33

31 Energy Information Administration, https://www.eia.gov/todayinenergy/detail.php?id=26532
32 Reserve margin is extra capacity set aside (such as running a generator below its maximum potential output or keeping a unit in “ready mode” on
standby) in case of unexpected outages such as when a unit goes offline unexpectedly, a transmission line fails, loads differ from what was expected, etc.
33 For more details about Avista’s generation, please see the 2019 Generation Infrastructure Plan, available on the internal website or upon request.
Appendix A: Natural Gas for Generation

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 24 of 25

Avista owns 1/3 of the
Jackson Prairie Storage
Facility, which contains over
8.5 million dekatherms of
working gas capacity. It has
over 25 million cubic feet of
storage capacity and is the
largest natural gas storage
site in the Pacific Northwest.
Jackson Prairie holds 25% of
the entire Northwest’s peak-
day supply.34

Jackson Prairie consists of a
series of deep underground reservoirs, basically thick porous sandstone deposits that can hold large
volumes of natural gas. It has 104 wells, 45 of which are used for injection or withdrawal. Natural gas is
injected into pockets up to 2,000 feet deep, where layers of sediment and sand naturally cap the
deposits and keep it underground. This storage facility is a tremendous financial benefit for Avista
customers. Most utility customers receive their gas supply directly from a network of interstate
pipelines and local gas lines and must pay the going rate for their usage. A storage facility such as
Jackson Prairie allows Avista to purchase gas at the lowest price periods (typically summertime), store
it, and utilize it during the times when gas usage is peaking and prices are highest.

Jackson Prairie supplements the interstate gas pipeline supply during customer peak times and ensures
that there is adequate natural gas available to serve all customers at any time of day or year. It also
helps stabilize energy prices by reducing the need to purchase gas supply during high cost times,
reduces dependence upon a sometimes volatile gas market, and provides reliable, cost-effective
natural gas to meet customer needs. The stored gas at this facility can also be used to alleviate load
imbalances on associated pipelines that sometimes occur when there is a significant difference
between the gas that flows into and the gas that flows out of the pipeline. Jackson Prairie allows the
Company to occasionally take advantage of market conditions to sell gas stored at Jackson Prairie at a
premium and then refill it when prices are down. All of these capabilities directly benefit customers by
keeping gas prices low and relatively stable as well as directly offsetting expenses via profits made in
the gas marketplace.
34 For more information, see “Jackson Prairie Underground Natural Gas Storage Facility” from Puget Sound Energy,
https://pse.com/aboutpse/PseNewsroom/MediaKit/052_Jackson_Prairie.pdf
Appendix B: Jackson Prairie Storage Facility

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 4, Page 25 of 25
Avista Utilities Asset Management
Protocol for Managing Select Aldyl A Pipe in Avista
Utilities‟ Natural Gas System
May 2013
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 1 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 2

Protocol for Managing Select Aldyl A Pipe in Avista Utilities’
Natural Gas System

Executive Summary

Avista Utilities (Avista) protocol for managing select Aldyl A pipe proposes a twenty-
year program to systematically remove and replace select portions of the DuPont Aldyl A
medium density polyethylene pipe in its natural gas distribution system in the States of
Washington, Oregon and Idaho. None of the subject pipe is “high pressure main pipe,”
but rather, consists of distribution mains at maximum operating pressures of 60 psi and
pipe diameters ranging from 1¼ to 4 inches. Further, Avista notes that while there have
been concerns with the integrity of steel pipe in other parts of the country in recent years,
the steel pipe in its system, including steel service risers, is being managed to protect its
long-term reliability and performance and is outside the scope of this program.

In recent years, Avista experienced two incidents on its natural gas system that prompted
the Washington Utilities and Transportation Commission and the Company to better
understand the potential long-term reliability of Aldyl A pipe. Results of these
investigations, which were aided by new tools developed for Avista‟s Distribution
Integrity Management Plan, corroborated reports for similar Aldyl A piping around the
country as supporting the development of a protocol for the management of this gas
facility. The following report highlights the history of DuPont‟s Aldyl A natural gas pipe
and summarizes DuPont and Federal Agency communications that are relevant to this
proposed program. The report documents the Aldyl A pipe in Avista‟s natural gas
system and describes the analysis of the types of failures observed in this pipe, and the
evaluation of its expected long-term integrity. Finally, the report describes the results of
Avista‟s work to establish the framework for the proposed protocol for the management
of Aldyl A pipe in its natural gas system.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 2 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 3

Table of Contents
I. History of DuPont Aldyl A Piping Systems .......................................................................... 5
DuPont Introduces Natural Gas Polyethylene Pipe – 1965 .................................... 5
The Phenomenon of “Low Ductile Inner Wall” ..................................................... 5
DuPont Communicates Potential Issues to Aldyl A Customers ............................. 5
1982 Letter ...................................................................................................... 5
1986 Letter ...................................................................................................... 6
DuPont Substantially Improves Aldyl A Pipe ........................................................ 6
Common Classifications of Aldyl A Pipe ............................................................... 7
II. Federal Bulletins on Brittle-Like Cracking in Plastic Pipe ................................................. 8
National Transportation Safety Board .................................................................... 8
Objectives of the Board‟s Investigation .......................................................... 8
Phenomenon of Premature Brittle-Like Cracking ........................................... 9
Board Findings on the Three Identified Safety Issues .................................... 9
Pipeline and Hazardous Materials Safety Administration .................................... 12
1999 Bulletins ................................................................................................ 12
2002 Bulletin ................................................................................................. 12
2007 Bulletin ................................................................................................. 12
III. 2009 Distribution Integrity Management Program ........................................................... 12
Objectives and Approach ...................................................................................... 12
IV. 2011 Call to Action – Transportation Secretary LaHood ................................................. 13
V. Avista’s Experience with DuPont Aldyl A Piping Systems ............................................... 14
Spokane and Odessa Incidents .............................................................................. 14
Expert-Recommended Protocol for Managing Aldyl A Pipe in Relation to
Reported Soil Conditions .............................................................................. 15
Evaluation of Leak Survey Records .............................................................. 16
Pipe Replacement Projects in 2011 ............................................................... 16
Avista Distribution Integrity Management Program ............................................ 16
VI. Analyzing Modes of Failure in Avista’s Aldyl A Pipe ....................................................... 17
Towers and Caps ........................................................................................... 18
Rock Contact and Squeeze-Off ..................................................................... 19
Services Tapped from Steel Mains ................................................................ 20
Avista‟s Aldyl A Services ............................................................................. 21
Understanding the Significance of Leaks in Aldyl A Pipe ................................... 21
Frequency and Potential Consequence .......................................................... 21
The Complication of Brittle Cracking in Aldyl A Pipe ................................. 22
VII. Reliability Modeling of Avista’s Aldyl A Piping ................................................................ 22
Availability Workbench Software ........................................................................ 22
Reliability Forecasting .......................................................................................... 23
Forecasting the Reliability of Aldyl A Piping ...................................................... 23
Forecasting Results ............................................................................................... 24
Forecast Piping Failures ................................................................................ 24
Dependability of Forecasting Future Failures ............................................... 24
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 3 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 4

Understanding the Significance of Cumulative Failure Curves .................... 25
Prudent Failure Management ........................................................................ 25
Priority Aldyl A Piping ................................................................................. 26
VIII. Formulation of a Management Program for Priority Aldyl A Pipe ................................. 26
Priority Aldyl A Piping in Avista‟s System .......................................................... 27
IX. Other Aldyl A Pipe Replacement Programs ....................................................................... 28
Aldyl A Pipe in the Pacific Northwest .................................................................. 28
Established and Emerging Programs for Aldyl A Pipe Replacement................... 28
Developments of Interest ...................................................................................... 29
X. Designing Avista’s Replacement Protocol for its Priority Aldyl A Pipe .......................... 30
Systematic Replacement Program ........................................................................ 30
Time Horizon ................................................................................................ 30
Prudent Management of Potential Risk ......................................................... 30
Prioritizing the Work ..................................................................................... 31
Twenty-Year Proposal ................................................................................... 31
Initial Optimization ....................................................................................... 32
Responsive Replacement Program ....................................................................... 33
Dr. Palermo‟s Assessment of the Proposed Protocol for Managing ..................... 33
Avista‟s Priority Aldyl A Piping........................................................................... 33
XI. Application of Avista’s Washington State Study Results to Aldyl A Pipe in the States of
Oregon and Idaho ................................................................................................................. 34
XII. Resource Requirements and Expected Cost ....................................................................... 34
Staffing .................................................................................................................. 34
Capital Costs ......................................................................................................... 35

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 4 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 5

History of DuPont Aldyl A Piping Systems

Modern polyethylene pipe products are corrosion-free, lightweight, cost-effective,
highly-reliable, and can be installed quickly and efficiently. For these reasons, it has for
decades been the „standard for the industry‟ and is the predominant choice used in natural
gas distribution systems. As with any revolutionary product line, polyethylene piping
systems have undergone continuous and rigorous testing and product improvement. Such
is the case with DuPont‟s Aldyl A piping systems, as very briefly summarized below.
DuPont Introduces Natural Gas Polyethylene Pipe – 1965

Along with other manufacturers, DuPont began to use polyethylene resin to produce
plastic piping for a variety of purposes. The resin was produced from ethylene molecules
combined together in repeating patterns to form larger molecules called „polymers‟,
hence the name „polyethylene.‟ DuPont‟s product designed specifically for use in the
natural gas industry was marketed under the name “Aldyl A.” The initial resin used in
production of Aldyl A pipe, Alathon 5040, was manufactured from 1965 to 1970.
DuPont changed the resin in 1970 to improve Aldyl A‟s resistance to rupture during
pressure testing. This improved formulation, known as Alathon 5043, was the primary
resin used in DuPont‟s Aldyl A pipe from 1970 until 1984.
The Phenomenon of “Low Ductile Inner Wall”

Shortly after changing its polyethylene resin in 1970, DuPont detected a manufacturing
issue highlighted during laboratory testing of Aldyl A pipe. DuPont learned that its
manufacturing process was resulting in some of the pipe having a property described as
“low ductile inner wall.” “Ductility” is the ability of a material to withstand forces that
alter its shape without it losing strength or breaking. A „highly-ductile‟ material can be
bent, flexed, pressed or stretched without cracking or losing strength because, unlike
brittle materials, it can redistribute the forces of stress concentration. Low Ductile Inner
Wall, or as it often appears “LDIW,” results when the inner surface of the Aldyl A pipe
becomes brittle, promoting the formation of cracks and premature failure. In early 1972,
DuPont changed its manufacturing process to eliminate this phenomenon, but estimated
that 30 – 40% of the pipe it produced in 1970, 1971 and early 1972 was affected,
primarily in pipe diameters from 1¼ inches to 4 inches.
DuPont Communicates Potential Issues to Aldyl A Customers
1982 Letter

In 1982, DuPont sent a letter to its natural gas customers, noting that two of its gas utility
customers had reported a low frequency of leaks in Aldyl A pipe manufactured prior to
1973. These leaks were reported as “slits” occurring where the pipe was in “point contact
with rocks.” DuPont noted these two utilities had increased the frequency of leak surveys
where rock may have been part of the backfill around the pipe, and encouraged other
Aldyl A customers to consider the same. This letter was the genesis of what would
become a continuing focus on the pipe vintage known as “pre-1973 Aldyl A.”
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 5 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 6

1986 Letter

DuPont‟s second letter to its Aldyl A pipe customers was sent in 1986, focusing again on
pre-1973 Aldyl A pipe. The letter focused on results of newly-developed (elevated
temperature) testing methods that allowed DuPont to more-accurately estimate the
longevity of this vintage pipe, in diameters of 1¼ inches and larger. Test results showed
that „Aldyl A pipe manufactured prior to 1973 had certain limitations that were not
previously-shown by then-available, state-of-the-art testing methods.‟ The limitations
were described as a reduction in pipe service life caused by: 1) “rock impingement” or
pressure from rock points directly on the pipe (as mentioned in their 1982 letter), and 2)
the use of squeeze-off practices. The term “squeeze-off” refers to the current and long-
standing construction practice of mechanically pressing in polyethylene pipe walls to
temporarily stop the flow of gas during work on a line that is in service. DuPont further
noted that average ground temperature surrounding the pipe, in the ranges of 60 to 70
degrees (F), had a major bearing on its ultimate expected service life. Finally, DuPont
recommended that operators should reinforce the pipe, using clamps that surround the
pipe at squeeze points, in order to extend the life of its Pre-1973 Aldyl A.
DuPont Substantially Improves Aldyl A Pipe

DuPont made a significant change to its Aldyl A resin formulation in 1984. The
improved resin, known as Alathon 5046-C, was marketed as “Improved Aldyl A”, and
significantly improved the performance of Aldyl A pipe in its resistance to „Slow Crack
Growth‟ and overall long-term integrity. Slow Crack Growth, or as it‟s often
abbreviated, SCG, describes the progression of a crack that begins with „crack initiation‟
or the formation of a crack in the inner wall of the pipe. The crack then progresses
through the pipe wall, usually over period of many years, until it finally breaks through
the outer surface of the pipe, resulting in failure.

Again, in 1988, DuPont announced another advance in its Aldyl A pipe resin with the
introduction of Alathon 5046-U. This change in resin formulation increased the
resistance of the pipe to slow crack growth by another order of magnitude. In addition,
because of the high „molecular efficiency‟ of this new resin, its density was also reduced,
which allowed for much greater ductility in the pipe. This product, the last of the DuPont
Aldyl A materials that Avista would install, was also marketed as Improved Aldyl A. A
summary of DuPont Aldyl A pipe produced between 1966 and 1992 is presented below
in Table 1. Information includes the year of manufacture, resin formulation, relative
resistance to slow crack growth (stress rupture testing at 80° C / 120 psig for accelerated
life testing), and summary notes.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 6 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 7

Table 1. DuPont Aldyl A Pipe 1965 - 1992

Years of
Manufacture Resin
Rupture
Resistance* Notes

1965 - 1970 Alathon 5040

Initial Product Marketed as “Aldyl A”

1970 - 1972 Alathon 5043 10 hours Resin Improvement and Low Ductile Inner Wall

1970 - 1984 Alathon 5043 100 hours Resin Improvement

1984 - 1988 Alathon 5046-C 1000 hours Resin Improvement-- Sold as “Improved Aldyl A”

1988 - 1992 Alathon 5046-U 10,000 hours Resin Improvement --“Improved Aldyl A”

*Illustrates the order of magnitude difference found from accelerated life testing of resins

Common Classifications of Aldyl A Pipe

Based on the characteristics of the different vintages of Aldyl A pipe, there would emerge
over time, (from DuPont‟s 1982 letter going forward), three age-groupings recognized by
the manufacturer, natural gas industry, and regulators as relevant in the reliability
management of this pipe.

Pre-1973 Aldyl A – Pipe manufactured through 1972, from the first two resin
formulations, and including pipe having low ductile inner wall.

Pre-1984 Aldyl A – Aldyl A pipe manufactured from Alathon 5043 resin, but only that
pipe manufactured after 1972 and through 1983.

1984 and Later Aldyl A – Pipe manufactured from the improved Alathon 5046-C and
5046-U resins.

Aldyl A Service Pipe - Small-diameter (less than 1¼ inches) Aldyl A service piping is
often treated or managed differently than larger-diameter Aldyl A pipe of the same
vintage. This is because the small-diameter pipe has been assessed by industry experts as
being more resistant to brittle-like cracking than larger-diameter pipe due to its greater
flexibility. Further, small-diameter Aldyl A pipe has been confirmed as being free of the
Low Ductile Inner Wall properties present in late 1970 through early 1972 vintage
piping.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 7 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 8

Federal Bulletins on Brittle-Like Cracking in Plastic Pipe

National Transportation Safety Board

In April 1998, twelve years after DuPont‟s second letter to customers, the National
Transportation Safety Board (Board) published a comprehensive safety bulletin
describing their investigation of natural gas pipeline accidents involving polyethylene
pipe that had cracked in a “brittle-like” manner. The bulletin focused primarily on
accidents related to an early plastic pipe manufactured by Century Utility Products
(Century), produced from Union Carbide resin. In its review, findings, and in its Safety
Recommendations, however, the Board concluded that in addition to the Century pipe,
much of the polyethylene pipe produced for gas service from the 1960s through the early
1980s may be susceptible to brittle cracking and premature failure, further noting that
vulnerability of this material to premature failure could represent a serious potential
hazard to public safety.

The Board‟s bulletin represented a seminal work on the vulnerability of early plastic pipe
to brittle-like cracking because it analyzed and integrated – for the first time – reports
from the technical literature, manufacturers‟ communications, industry expert opinions,
the experience of pipeline operators and regulators‟ accident reports. Because the
bulletin provided a clear understanding of the drivers of failure in older polyethylene
pipe, we have included a fairly detailed synopsis in this report.
Objectives of the Board’s Investigation

Following the Board‟s investigation of over a dozen serious incidents, it undertook an
effort to evaluate whether the existing pipeline accident data was sufficient for assessing
the long-term performance of plastic piping. The office of Research and Special
Programs Administration of the National Transportation Safety Board compiled the
relevant accident data, but found it to be insufficient for this purpose. Lacking adequate
data for the larger assessment, the Board instead focused on estimating the likely
frequency of brittle-like cracking, focusing on published technical literature, industry
expertise, and work with several gas system operators. From this review, the Board
launched a special investigation with the objectives to address three safety issues related
to polyethylene gas service pipe:

1. Vulnerability of plastic piping to brittle-like cracking
2. Adequacy of available guidance to pipeline operators regarding installation
and protection of plastic pipe tapped to steel mains
3. Performance monitoring as a possible way to detect unacceptable performance
in piping systems

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 8 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 9

Phenomenon of Premature Brittle-Like Cracking

The Board‟s survey suggested that early plastic piping may be “susceptible to premature
brittle-like cracking under conditions of stress intensification.” The term „stress
intensification‟ refers to localized pressure on the pipe wall created by such conditions as
rock contact or significant bending of the pipe. The phenomenon of brittle-like cracking
was characterized by the failure processes described above, beginning with the initiation
of cracks on the inner wall of the pipe at the pressure or stress point, followed by slow
crack growth that progressed under normal pipeline operating pressures (much lower than
the pressure required to rupture the pipe). The process culminated with the crack
reaching the outside wall of the pipe, showing up as a very tight, slit-like opening on the
surface, running generally parallel with the length of the pipe. Premature brittle-like
cracking was believed, at the time of the Board‟s safety bulletin, to require relatively high
and localized stress on the pipe resulting from sharp or excessive bending, soil settling,
rock “impingement” (point or contact pressure on the pipe) , improperly installed fittings,
and dents or gouges to the pipe surface. The term „brittle-like cracking‟ was used to
describe this failure process because the pipe showed no signs of being bulged or
deformed where the cracks occurred.
Board Findings on the Three Identified Safety Issues
Issue 1: Vulnerability of Plastic Piping to Brittle Cracking

Long-Term Strength of Early Pipe was Overrated - In the early 1960s the industry
had very little long-term experience with plastic pipe, and consequently, developed
laboratory testing procedures to forecast the expected service life of piping. Early testing
results suggested that polyethylene pipe would exhibit a relatively constant, or „straight
line‟ gradual decline in strength over time. These tests and underlying assumptions were
subsequently incorporated as standards for the industry and in related federal
requirements.

As the industry gained experience, however, the straight-line assumptions of these early
procedures began to be challenged through the development of new testing methods,
where pipe strength was assessed under conditions of elevated temperature (such as the
testing referenced in DuPont‟s 1986 letter to customers). Results of the elevated-
temperature testing showed that the decline in strength of early plastic pipe was not
gradual or linear as had been assumed, but instead, began to accelerate or drop below the
straight line, especially after twelve years. The Board concluded that the early testing
procedures may have overrated the strength and resistance to brittle-like cracking of the
polyethylene pipe manufactured for the gas industry from the 1960s through the early
1980s.

Long-Term Ductility was Overrated - Another important assumption about early
plastic pipe, based on short-term testing, was that it would retain its ductile properties
long term. The assumption of long-term ductility had important safety ramifications
since it allowed plastic pipe systems to be designed to withstand stresses generated
primarily by internal pressure and to give less consideration to the impacts of external
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 9 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 10

stresses such as bending. Unfortunately, the early testing methods did not properly
identify the evidence of the “ductile to brittle” transition that was occurring early in the
life of the pipe. Consequently, the tests did not distinguish pipe failures resulting from a
loss in ductility. The Board noted that this loss of ductility was also observed in the older
piping of several manufacturers, those other than Century Utility Products.

Pipeline Operators had Insufficient Notification - The Board noted that premature
brittle-like cracking was a complex phenomenon that had not been systematically
communicated to the industry, and hence, had not been fully-appreciated by pipeline
operators. The Board recognized pipe manufacturers as commonly offering technical and
safety assistance to operators, and occasionally, formal reports on their materials. But,
because the information on the potential weakness of their products was also mixed with
information publicizing its best performance characteristics, the message was not clear.
The Board also noted that the Federal Government had not provided relevant information
to gas system operators, and concluded that operators had insufficient notification that
much of their early polyethylene pipe may have been susceptible to premature brittle-like
cracking. Finally, the Board went on to recommend that the polyethylene pipe
manufacturers‟ organization, the Plastics Pipe Institute, advise its members to notify
pipeline operators if any of their materials indicate poor resistance to brittle-like failure.
Issue 2: Adequacy of Guidance for Connecting Plastic Pipe to Steel Mains

Critical Understanding of Stress on Pipe - The Board observed that the premature
transition of plastic piping from a ductile to a brittle state appeared to have little
observable adverse impact on the serviceability of plastic pipe, except where the pipe was
subjected to external stresses, such as excessive bending, earth settlement, dents or
gouges to the pipe surface, and improper installation of fittings, etc. Of those sources of
stress, a key factor identified in the Board‟s bulletin was earth settlement, but particularly
in cases where plastic piping was connected to more rigidly anchored fittings, such as
steel main pipe. Because the physical properties of plastic and steel respond differently
under the same conditions, such as to temperature change and ground settlement, the
slight movements of each type of pipe in the ground will be different. This difference in
movement can result in significant stress at the point of connection between the plastic
and steel piping.

Much of the Guidance to Operators was Insufficient or Ambiguous - In addition to
pipeline operators having insufficient guidance on the overall issue of the vulnerability of
plastic pipe to brittle cracking, as noted above, the Board also observed that much of the
available guidance to operators on how to limit stress on the pipe during installation was
inadequate or ambiguous. This was particularly the case with the stress associated with
the tapping of plastic service piping to steel mains, where the Board concluded that many
of those connections may have been installed without adequate protection from external
stress. The Board went on to identify several instances where safety requirements did not
fully incorporate safety recommendations, resulting in ambiguity for pipeline installers
and regulators. Other highlights of the Board‟s findings were the many cases where the
applicable regulations applying to pipeline installation lacked any performance
measurement criteria. Noting that the Office of Pipeline Safety considered many of its
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 10 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 11

safety regulations to be performance-oriented requirements, the Board rebutted this in
stating that “many are no more than general statements of required actions that do not
establish any criteria against which the adequacy of the actions taken can be evaluated.”
A particular example was the regulation that “requires gas service lines to be installed so
as to minimize anticipated piping strain and external loading,” and yet it contained no
performance measurement criteria for establishing compliance. Finally, the Board went
on to note cases where the inadequacy of pipe manufacturers‟ instructions also
contributed to the lack of a clear understanding of methods to limit stress on plastic pipe
during installation.
Issue 3: Monitoring of Plastic Pipe to Determine Unacceptable Performance

The Board‟s final objective was focused on performance monitoring of pipeline systems
as the key to effectively managing the vulnerable piping types identified in the bulletin.
In this discussion, the Board focused on the accident in Waterloo, Iowa in 19941, in
highlighting the very real challenges of designing effective pipeline monitoring
programs. The Board stated that before the accident, the pipeline operator had developed
a limited capability to monitor and analyze the condition of its system. It concluded
however, that the systems the operator had developed for tracking, identifying, and
statistically treating plastic piping failures did not permit an effective analysis of system
failures and leak history, noting that their methods of handling of pipe data masked the
high failure rates of the subject Century pipe. While the operator did re-evaluate its
monitoring data after the accident, and subsequently identified the high failure rates of
Century Pipe, the Board opined that the problem could have been detected earlier (before
the accident) if the data had been properly analyzed in the first place. Finally, the Board
concluded that an effective monitoring program would have allowed the operator to
implement a pipe replacement program that might have prevented the accident.

In the second case, the Board noted that while the operator had added capabilities to its
pipe-monitoring protocols, it had still not chosen parameters needed to provide adequate
analysis of its plastic piping system failures and leak history. The bulletin went on to
note examples of the many types of additional parameters needed to enable the effective
tracking, identifying, and properly describing system failures and leak history.

The Board concluded that in light of the key findings in its bulletin, that gas system
operators may need to be advised once again of the importance of complying with
Federal requirements for piping system surveillance and analyses. Regarding the
monitoring of older piping, the Board identified the necessity to analyze factors such as
piping manufacturer, installation date, pipe diameter, operating pressure, leak history,
geographical location, modes of failure, location of failure, etc. Finally, the Board noted
that an effective monitoring program would require the evaluation of pipe material and
installation practices to provide a basis for the planned and timely replacement of piping
that indicates unacceptable performance.

1 In October, 1994, a natural gas leak and explosion at Midwest Gas Company in Waterloo, Iowa, resulted
in 6 fatalities and 7 injuries. The cause of the incident was identified as the failure of a ½ inch diameter
service pipe cracking in a brittle-like manner at a connection to a steel main.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 11 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 12

Pipeline and Hazardous Materials Safety Administration
1999 Bulletins

The first two of several advisory bulletins related to the Board‟s 1998 Safety Bulletin
(above), were published by the Office of Pipeline Safety, now known as the Pipeline and
Hazardous Materials Safety Administration (Administration), in March 1999. The
bulletins, which were issued as advisories to pipeline owners and operators, provided an
abstract of the findings of the Board‟s 1998 investigation and advised that much of the
plastic pipe manufactured from the 1960s through the early 1980s may be susceptible to
brittle-like cracking. The advisories concluded with the recommendation to owners and
operators to identify all pre-1982 plastic pipe installations, analyze leak histories,
evaluate potential stresses to pipe, and to develop appropriate remedial actions, including
pipe replacement, to mitigate any risks to public safety.
2002 Bulletin

This bulletin, as with the prior advisories, reiterated to natural gas pipeline owners and
operators the susceptibility of older plastic pipe to premature brittle-like cracking. But,
for the first time, this advisory specifically named DuPont‟s pre-1973 Aldyl A pipe (low
ductile inner wall) as being susceptible to brittle cracking. The bulletin also depicted
several environmental and installation conditions that could lead to premature, brittle-like
cracking failure of the subject pipe, and described recommended practices to aid
operators in identifying and managing brittle-like cracking problems.
2007 Bulletin

This bulletin, again, served to review and recap the findings of the prior bulletins,
advising natural gas system operators to review the earlier statements. In addition, the
advisory recapped results of the ongoing effort of the American Gas Association to
identify trends in the performance of older plastic pipe. The advisory reported that the
data, at that point, could not assess failure rates of individual plastic pipe materials, but
did support what was historically known about the susceptibility of older plastic piping to
brittle-like failure, including the addition of specific materials to the list, such as Delrin
insert tap tees.
2009 Distribution Integrity Management Program

The Administration published the final rule establishing integrity management
requirements for gas distribution pipeline operators in December 2009. Though the
effective date of the rule was February 2010, operators were given until August 2011 to
write and implement their Distribution Integrity Management Plan (DIMP).
Objectives and Approach

Among other objectives, the program was intended to overcome two key weaknesses in
pipeline safety management that were identified in the National Transportation Safety
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 12 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 13

Board‟s 1998 bulletin (above): 1) correct weaknesses in federal regulations, particularly
in the Office of Pipeline Safety, by establishing true measurement criteria for establishing
safety compliance, and 2) establish systematic protocols for pipeline data collection,
analysis, and interpretation, that helps ensure accurate integrity assessment and
appropriate remediation.

The concept of “Integrity Management” grew out of a demonstration project of the Office
of Pipeline Safety designed to test whether allowing operators the flexibility to allocate
safety resources through risk management was effective in improving pipeline safety and
reliability. Integrity management requires operators, such as natural gas distribution
companies, to write and implement Integrity Management Programs (IMPs) to assess,
evaluate, repair and validate the integrity of pipeline segments. The program contains the
following elements:
Knowledge
Identify Threats
Evaluate and Rank Risks
Identify and Implement Measures to Address Risks
Measure Performance, Monitor Results, and Evaluate Effectiveness
Periodically Evaluate and Improve Program
Report Results
The Integrity Management approach uses historical leak data and other facility
information, along with the input of subject-matter experts, to identify individual threats
to a gas system. These threats are then analyzed to predict the likelihood and
consequences of failure. Each threat is then ranked by priority, followed by the
development of a plan to reduce or remove those risks as deemed necessary.
2011 Call to Action – Transportation Secretary LaHood

Finally, in April 2011, U.S. Transportation Secretary LaHood issued a Call to Action to
all pipeline stakeholders in conjunction with the effective application of the Distribution
Integrity Management Program. The Call to Action was aimed at the more than 2.5
million miles of liquid and gas pipelines of both federal and state jurisdiction, including
transmission and distribution facilities, calling on owners and operators, the pipeline
industry, utility regulators and state and federal partners to:

Evaluate risks on pipeline systems;
Take appropriate actions to address those risks, and
Requalify subject pipeline systems as being fit for service.

The centerpiece of the Call to Action is the “Action Plan” of the Department of
Transportation and the Pipeline and Hazardous Materials Safety Administration. The
focus of the Action Plan is to accelerate the rehabilitation, repair, and replacement of
high-risk pipeline infrastructure, calling on pipeline operators and owners to take
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 13 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 14

“aggressive efforts… to review their pipelines and quickly repair and replace sections in
poor condition.” To buttress this Call to Action, Secretary LaHood has asked Congress
to increase maximum civil penalties for pipeline violations, to close regulatory loopholes,
strengthen risk-management requirements, add more inspectors, improve data reporting
and help identify potential pipeline safety risks early.
Avista’s Experience with DuPont Aldyl A Piping Systems

Avista has approximately 12,500 miles of natural gas piping in its service territories in
the States of Washington, Oregon and Idaho. Like dozens of other gas utilities, Avista
adopted plastic pipe as an excellent alternative to steel, and consequently, the broad
majority of Avista‟s pipe is polyethylene (about 8,500 miles) of various types, ages and
brands, including DuPont‟s Aldyl A.

Avista began installing DuPont Aldyl A in 1968 and discontinued its use in 1990 when
DuPont sold their production to Uponor. Of the various vintages and formulations of
Aldyl A pipe in its system, Avista has estimated quantities in the following amounts, in
diameters of ½” to 4”:

Pre-1973 Aldyl A (1965-1972 resins) 190 Miles
1973-1984 resins 960 Miles
1985-1990 resins 919 Miles

Avista noted the advisory bulletins of the Board and Administration in 1998, 1999 and
2002, but since it had no documented trends in the types of failures highlighted,
continued to manage its Aldyl A pipe according to established monitoring standards for
leak survey and sound operations practices.
Spokane and Odessa Incidents

In recent years, however, Avista experienced two natural gas incidents2 resulting in
injuries and property damage that signaled possible changes in leak patterns in its Aldyl
A piping. The first incident occurred in 2005 at a commercial site in Spokane. This
event involved the failure of 1976-vintage Aldyl A pipe caused by bending-stress
resulting from poor soil compaction around the pipe that was performed by a non-Avista
excavator in 1993. The post-incident investigation judged the resulting leak to be an
anomaly that could have been prevented with proper care by that 3rd party excavator.

The second incident, at a residence in the town of Odessa, Washington, in late 2008, was
determined to be the result of rock pressure on the 1981-vintage Aldyl A pipe that
occurred during the initial installation. Avista signed a settlement agreement with staff of
2 The Pipeline and Hazardous Materials Safety Administration defines a natural gas “incident” as a release
of gas that results in any of the following: a fatality or personal injury that requires in-patient
hospitalization; property damage of $50,000 or greater, or the loss of greater than 3 million cubic feet of
gas.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 14 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 15

the Washington Utilities and Transportation Commission as an outcome of the
investigation of this incident. Under terms of the agreement, which was subsequently
approved by the Commission, Avista increased the frequency of its residential leak
survey on pre-1984 resin (pre-1987 installed) Aldyl A natural gas mains in its
Washington jurisdiction, from once every five years to annually. In addition, whenever it
is excavating in the vicinity of Aldyl A natural gas mains in Washington, Avista will also
report on the soil conditions surrounding the pipe, and identify appropriate and
reasonable remedial measures, as necessary. Avista retained the consulting services of
Dr. Gene Palermo to help develop its approach for managing Aldyl A pipe, in relation to
the soil conditions reported.
Expert-Recommended Protocol for Managing Aldyl A Pipe in Relation to Reported
Soil Conditions

Dr. Palermo is a nationally-recognized expert on the plastic pipe used in natural gas
systems, and in particular, Aldyl A piping. He has worked in the plastic pipe industry for
over 35 years, which includes 19 years with the DuPont Corporation in its Aldyl A
natural gas pipe division.

Dr. Palermo also served as the Technical Director for the Plastics Pipe Institute from
1996 through 2003 and served on the Institute‟s Hydrostatic Stress Board for over 20
years. Dr. Palermo has served on a variety of gas industry committees, has trained gas
industry practitioners and regulators, and has received numerous awards of merit for his
outstanding individual contribution to the natural gas plastic-piping industry. He is the
only person to receive both the American Society of Testing and Materials - Award of
Merit, and the American Gas Association - Platinum Award of Merit. Dr. Palermo is
president of his consulting firm, Palermo Plastics Pipe Consulting.

Dr. Palermo reviewed the content of Avista‟s agreement with the Commission to become
familiar with its requirements, specifically with regard to managing Aldyl A piping found
in soils that would currently not meet standard criteria for bedding and backfill. Dr.
Palermo‟s review and expertise provided the basis for his recommended protocol for
management of Avista‟s Aldyl A piping found in rocky soils.

1. All Aldyl A pipe manufactured prior to 1984 should be evaluated for replacement
in the following manner:
a. If the pipe has Low Ductile Inner Wall properties, Avista should
immediately begin a prioritized pipe replacement program.
b. If the pipe is installed in soil with rocks larger than ¾ inch, Avista should
immediately begin a prioritized pipe replacement program.
c. If the pipe is installed in sandy soil or in soil with rocks up to ¾ inch in
size, the pipe should remain in service and normal leak surveys per DOT
Part 192 should be followed.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 15 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 16

2. All Aldyl A pipe manufactured during or after 1984 should also be evaluated.

a. If the pipe is installed in soil with rocks larger than ¾ inch in size, Avista
should evaluate the pipe and consider replacing it if they begin to
experience rock impingement failures, and should conduct leak surveys
more frequently than required by DOT Part 192, until replacement.
b. If this pipe is installed in sandy soil or in soil with rocks up to ¾” in size,
the pipe should remain in service and normal leak surveys should be
followed.
Evaluation of Leak Survey Records

Following the Odessa incident, Avista was also asked to review five years of leak survey
records in Washington State to look for possible emerging patterns in the health of its
Aldyl A piping system. Avista organized the leak survey information and then conducted
several evaluations, which were organized under three general objectives, listed below.

1. Analyze the modes or observed types of failures in Aldyl A pipe;
2. Forecast the expected long-term integrity of Aldyl A piping;
3. Identify potential patterns in the overall health of this piping to aid in the design
of a more-focused management protocol for Aldyl A pipe.

Avista used newly-available asset-management tools to conduct these assessments,
including its recently-implemented Distribution Integrity Management Program
(Integrity Management) approach for identifying and analyzing potential threats to its
natural gas system. This approach is suited for just such an analysis, having the
capability to determine potential patterns in the overall health of a piping system that
might not have been otherwise evident through conventional data review. The analysis
of the historic leak survey data, including the observation of several new Aldyl A
material failures and leaks, did point to the development of a possible trend.
Pipe Replacement Projects in 2011

Another outcome of this heightened focus on Aldyl A leaks was Avista‟s decision to
replace several thousand feet of its Aldyl A main in 2011. In Odessa, Avista increased
the frequency of leak surveys on its gas system to once per quarter and mobilized a pipe
replacement program that removed all of the pre-1984 Aldyl A main pipe from the gas
system in the town. During that project, which was conducted from June to December
2011, nearly 32,000 feet of Aldyl A main pipe were replaced. Other Aldyl A
replacement projects in 2011 removed an additional 7,000 feet of this priority pipe.
Together, these projects had a capital cost of approximately $2.7 million.

Avista Distribution Integrity Management Program
As described briefly above, the Integrity Management approach, now required by law,
begins with the aggregation of historical leak-survey data and other facility information
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 16 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 17

relevant to Avista‟s natural gas piping system. Then, in conjunction with the input of
subject matter experts, individual threats to Avista‟s gas system are identified. These
threats are analyzed to predict the likelihood and consequences of failure associated with
each threat, based on the specific operating environment, system makeup, and history of
Avista‟s natural gas system. Each threat is then ranked relative to all others to identify,
by priority, those with the greatest hazard potential. From that priority list, measures are
developed to reduce or remove those risks as deemed necessary. These mitigating
measures are often referred to as “accelerated actions” because they may be above and
beyond the minimum requirements of applicable federal and state codes. These
accelerated actions can range from increased frequency of maintenance and leak surveys
to full replacement programs for certain gas facilities. Finally, the mitigating measures
will be reviewed to evaluate their effectiveness in reducing threats to the gas system, and
the program will then be adjusted as necessary based on those outcomes.
Integrity Management requires the use of geographically-based analytical software to
complete many of the required program elements. Like many utilities, Avista is using the
Geographic Information System (GIS) platform developed and supported by
Environmental Systems Research, Inc. (ESRI), as the geographic and analytical engine
for conducting its gas system evaluations under the Integrity Management program.
ESRI is a pioneer and world leader in developing and supporting geographic software
products for a broad range of global business sectors, including utilities. Since Avista
had already created a comprehensive GIS layer, or database, for its gas facilities, it made
sense to add analytical capabilities to this platform in complying with the Integrity
Management program requirements.
Analyzing Modes of Failure in Avista’s Aldyl A Pipe

In tackling the first objective of the assessment of its Aldyl A piping, Avista aggregated
the gas leaks resulting from Aldyl A material failures found in its gas system in
Washington State from late 2005 through March 2011. The sample included 113
material failures that were evaluated and summarized by component to offer an
understanding of the specific failure modes for Aldyl A pipe. The „modes‟ or types of
material failures categorized are shown below in Figure 1.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 17 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 18

Figure 1. Modes or types of material failures documented in a sample of 113 leaks in
Avista’s Aldyl A piping in Washington State, December 2005 through March 2011.

Towers and Caps

The largest percentage of material failures in the sample occurred in Towers and Caps,
referring to failure of the service tapping tee itself, shown below in Figure 2. In these
cases, the pressure applied to the tee as the cap was tightened onto the body during initial
installation has resulted in slow crack growth and failure of the tower body, the cap, or
the Delrin® insert many years later. Additionally, the saddle fusion point of the tower to
the main pipe is another frequent point of failure in this assembly. The unavoidable
stresses created during standard installation (using factory recommended procedures)
have led to brittle cracking in these components many years later. This phenomenon
clearly demonstrates the susceptibility of certain resins of Aldyl A piping to tend to fail
by brittle cracking due to the slow crack growth initiated during installation.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 18 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 19

Figure 2. External features and internal components of a typical Aldyl A service tee, as
fused to Aldyl A main pipe.

Rock Contact and Squeeze-Off

The second-most common material failure observed in Avista‟s Aldyl A pipe was due to
localized, brittle cracking in Aldyl A mains that resulted from rock impingement – rock
pressure directly on the pipe, or places where „squeeze-off‟ was applied over the pipe‟s
service life. These failures are very typical for certain resins of Aldyl A main pipe,
having been consistently reported by other utilities since before the time of DuPont‟s
1986 letter. As described earlier, when these external stresses (rock impingement or
squeeze-off) cause the pipe to fail, it always begins with crack initiation on the inside
surface of the pipe wall, eventually resulting in slow crack growth that propagates toward
the outer wall of the pipe, and finally, through-wall failure. These failures generally
appear as short, tight cracks in the outer wall of the pipe that run either parallel, or
slightly off-parallel with the length of the pipe. A typical failure in Aldyl A main pipe,
showing a crack through the pipe wall as it appears on both the inner and outer surfaces,
is shown below in Figure 3.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 19 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 20

Figure 3. Typical brittle-like crack through the wall of Aldyl A pipe, resulting from rock
contact directly on the pipe.

Although the duration of the stress caused by rock contact with the pipe is very different
from that associated with squeeze-off, they both result the same pattern of crack initiation
and slow crack growth leading to failure of the pipe. Other sources of external stress that
can result in brittle failure of Aldyl A pipe, as mentioned earlier in the report, include
bending of the pipe, soil settlement, dents or gouges to the pipe, and improper installation
of fittings.
Services Tapped from Steel Mains

The third most-common failure in Avista‟s sample occurred where small diameter Aldyl
A service pipe is tapped from steel main pipe. In this application, a steel service tee is
welded to the steel main pipe and the small-diameter Aldyl A service pipe is then
connected to a mechanical transition fitting on the tee, as pictured below in Figure 4.

Figure 4. Typical polyethylene service tapped from a steel main.

It is at this transition point, between the rigid steel fitting and the more-flexible Aldyl A
service pipe, that brittle-like cracking has been observed. This failure mode in older
plastic pipe is well understood, and was one of the three study objectives reported by the
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 20 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 21

National Transportation Safety Board in its 1998 bulletin, summarized earlier in this
report.
Avista’s Aldyl A Services

Avista believes its Aldyl A service piping (apart from cracking at the connection with the
tee on steel main pipe) has no greater tendency to fail than its other polyethylene service
piping , and at this point in time, should not be managed differently than other plastic
service pipe (frequency of leak survey, etc.). Consequently, Avista is not planning to
systematically replace Aldyl A service pipe as it replaces main pipe and rehabilitates
service connections at steel tees. Avista is using the Integrity Management model,
however, to track and analyze service leaks going forward to determine if the reliability
of Aldyl A service piping changes in ways that warrant a different approach.

Understanding the Significance of Leaks in Aldyl A Pipe
Frequency and Potential Consequence

Analysis of the material failures of Aldyl A pipe provides the opportunity to put these
leaks into perspective with other types of leaks on Avista‟s natural gas system. As part of
the development of the Integrity Management Plan, five years of leak data were analyzed
for Avista‟s three-state service territory. The data included nearly 17,000 individual
leaks, which were categorized according to the underlying threats to the natural gas
system as required under Integrity Management. As a point of comparison of the
significance of leak types, the data included an excess of 2,000 leaks associated with the
failure of gas system equipment, such as valves, fittings and meters. But only 153 leaks
were identified as resulting from „material failures‟ of Aldyl A piping in the three states.
Looking simply at Aldyl A leaks as part of the aggregate of all system leaks, it could be
easy to conclude that Aldyl A pipe failures pose a limited potential for hazard relative to
the threat of other system leaks. In fact, while gas equipment leaks are more likely to
occur, their potential consequence is often minimal. A thorough understanding of this
difference is one of the most important requirements and outcomes of any effective
Integrity Management Plan analysis.

Review of the leak-history data shows the vast majority of equipment leaks as occurring
typically with shut-off valves and gas meters, located either above ground or in locations
that allow free-venting of gas to the atmosphere. Consequently, these types of leaks have
a low potential to result in an incident posing harm. Through public awareness programs,
people have become familiar with the odor of venting gas and tend to quickly call Avista
to make repairs; this is especially true if the venting gas can be associated with visible gas
valves or meters. By contrast, Aldyl A failures and the associated leaks occur almost
entirely underground, out of sight, often in populated areas, and occasionally in the
proximity of buildings that are not actually connected to the natural gas system. Without
visible facilities, natural gas may have an unexpected presence in the environment that
allows people to dismiss slight gas odors. This reduced awareness allows gas from these
undetected leaks to have the significant potential to migrate into buildings before it can
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 21 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 22

be identified and reported. This is especially true in winter when the ground is saturated,
frozen or snow covered, and in areas of full pavement and concrete finishes. Of the
roughly 2,000 equipment leaks reported in the five years of data reviewed, none resulted
in gas incidents. By comparison, two of the relatively-small number of Aldyl A material
failures resulted in gas migrating into buildings undetected, and upon accidental ignition,
resulted in harmful incidents.
The Complication of Brittle Cracking in Aldyl A Pipe

The common mode of failure for Aldyl A materials, brittle-like cracking, can also present
special problems compared with leaks in other gas piping, such as corrosion in steel gas
pipe. Corrosion leaks tend to begin with the failure of a very minute area in the pipe
wall, which then begins to release a very minute amount of natural gas. These leaks then
tend to progress very slowly and in a stable and somewhat predicable way over time.
These types of leaks, while never positive, are more likely to be detected by modern gas-
detection equipment when they are at a stage where the release of gas is relatively minor.
By contrast, leaks in Aldyl A piping tend to first appear as substantial (high gas volume)
leaks that appear in a very short time period. This is due to the nature of brittle cracking,
where the crack can progress very slowly from the inner wall of the pipe toward the outer
wall without any release of gas, until the pipe finally splits open, resulting in a substantial
failure. Additionally, unlike the prevention or even suspension of corrosion problems in
steel pipe through effective protection methods, there is no way to halt undetected
progress of slow crack growth in brittle Aldyl A pipe.
Reliability Modeling of Avista’s Aldyl A Piping

Avista‟s Asset Management Group performed reliability modeling for several classes of
its natural gas pipe in order to assess the long-term performance of its Aldyl A piping,
compared with steel pipe and newer-vintage plastic pipe. Reliability analysis comes from
the discipline of „reliability engineering‟ and is a foundational asset management tool that
provides a forecast or prediction of the future performance of a piece of equipment (pipe,
in this instance). The predicted asset performance then provides the basis for the
application of other asset management tools, allowing the development of the ultimate
maintenance or replacement strategies that optimize asset cost with any number of other
factors, such as availability for service or risk avoidance.

Availability Workbench Software

Avista developed reliability forecasts for its Aldyl A and other piping using Availability
Workbench™ software. This „off the shelf software‟ was introduced by Isograph, Ltd.,
the world‟s leader in reliability analysis software. Availability Workbench was first
introduced in 1988, and is used to support asset decision making in over 7,000 sites
around the world and across a range of industries, including Aerospace, Automotive,
Chemical, Defense, Electronics, Manufacturing, Mining, Oil and Gas, Power Generation,
Railways, and Utilities. Avista‟s version of the model was released in 2009.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 22 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 23

Reliability Forecasting

Availability Workbench has four modules, one of which, the Weibull module, is used to
create reliability forecasts (curves) for an asset. Reliability curves for gas piping are
generated from input data that include pipe inventory (type, brand, footage, location, soil
conditions, etc.), current age of piping, historic and current failure information and repair
data. Avista uses predominantly its own historical data for these inputs, but when they
must be estimated, they are vetted by subject matter experts within the company. The
model integrates pipe age and failure and repair data, and then by applying a
conventional Weibull-curve mathematical model, it produces probability curves that
represent the expected failure rates over time for each failure mode, such as the brittle-
like cracking associated with Aldyl A services tapped to steel mains. The reliability
curves represent how quickly the rest of the pipe is at risk of failing, shown as the
percentage of failures expected each year over time.

Forecasting the Reliability of Aldyl A Piping

The objective of Avista‟s reliability modeling was to forecast expected failures for
elements of Avista‟s Aldyl A piping system, compared with that of steel and latest-
generation polyethylene pipe. The observed Aldyl A failure modes, discussed above,
including leak data for other types of gas pipe in Avista‟s system, provided high-quality
leak and age information for the reliability modeling. Forecasting was performed for the
following pipe „classes‟ in Avista‟s system.

a. Aldyl A Main pipe of Pre-1984 manufacture (Alathon 5040 and 5043 resins,
including low ductile inner wall pipe)
b. Aldyl A Main pipe manufactured during 1984 and after (Alathon 5046-C and
5046-U resins)
c. Aldyl A Services Tapped to Steel Main (Bending Stress Services)
d. Steel Main pipe
e. Newer Polyethylene Main pipe (1990 and later)

To perform the modeling, the data for these pipe classes must be input as discrete
elements, which are described as follows:

Main Pipe - Analyzed using 50-foot segments as discrete modeling elements.

Services Tapped from Steel Mains - Avista identified 16,000 such services in its
system, also referred to as „bending stress tees.‟ For the reliability modeling, the
individual service is the discrete element.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 23 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 24

Forecasting Results
Forecast Piping Failures

Results of the forecast modeling, for the pipe classes evaluated, are represented as
„curves‟ showing the percentage of the amount of each pipe class that is projected to fail
in each year of the forecast time period. The resulting reliability curves are shown in the
graph below in Figure 5.

Figure 5. The expected failure rates for several classes of pipe in Avista’s system, as
forecast by Availability Workbench Modeling. The “Steel” curve is obscured by the
“Newer Polyethylene” curve, both of which are essentially flat lines.

The failure curves show dramatic differences in the expected life for the pipe classes
evaluated. The difference in expected life between the Aldyl A products as a group,
compared with that of steel and newer-generation plastic pipe, is particularly evident.
Striking also, are the expected performance differences among the classes of Aldyl A
pipe evaluated, providing some clear trends useful in designing remediation strategies.
Dependability of Forecasting Future Failures

The reliability forecast is essentially a mathematical calculation of the „chance‟ of future
failure and decisions of significant risk and financial magnitude are based, at least in part,
on that result. Importantly though, the forecast has a „real numbers‟ foundation in the
actual leak data, records of material failure and repair, and the relationship of those
events with time. For Aldyl A pipe, the model is using observed endpoints in the life of
the pipe resulting from a loss in ductility and slow crack growth, for example, and
integrating that with other data to forecast future expected failures. Comparatively, the
relatively rare observed failures in steel pipe and newer-generation plastic pipe are
0%
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1984 and later Aldyl A
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Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 24 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 25

reflected in their nearly-flat cumulative failure curves. The value of using proven
reliability forecasting approaches and widely-adopted software is derived from their
ubiquitous application across reliability-critical industries, and their continuous testing,
evaluation, and support. Finally, as Avista adds new data in coming years for pipe
failures of all material classes, including Aldyl A, it serves to increase the statistical
power of the forecast results.
Understanding the Significance of Cumulative Failure Curves

Although the failure curves for the different classes of pipe differ significantly over the
long term, as mentioned, the failure rates also appear to be very close to zero for the first
40 years for Aldyl A services tapped to steel main, and for 75 years for Pre-1984 Aldyl A
main pipe. Since the weighted average age for Aldyl A pipe in Avista‟s system is 32
years, it would appear that we might have ample time before the failure rate would start
to rise substantially for Pre-1984 Aldyl A main pipe. The failure curve estimates that
when the Pre-1984 Aldyl A main pipe is 80 years old that approximately three percent of
it will fail in that single year. Given that Avista has 335 miles of this vintage pipe in
Washington, that mileage equals about 35,000 discrete elements (50-ft sections) in the
forecast model. The three percent failure, then, translates to 1,050 leaks in that 80th year.
To put that failure rate into perspective, consider that Avista documented just 113 leaks
over the past five years in Washington state, two of which resulted in injury and property
incidents, and dozens more that were categorized as hazardous leaks3, timely repaired.
Since it is expected that the number of hazardous leaks and incidents would increase
proportionally with the increase in total leaks, then it‟s easy to imagine just how
unacceptable the pipe performance would be at an annual failure rate of three percent.
Prudent Failure Management

To carry this point further, if we “zoom-in” on the curves we can gauge the significance
of the change in failure rate that is expected ten years from today. At that point the
weighted average age of Aldyl A pipe in Avista‟s system will be 42 years, and the
expected failure rate for that year is just over one-tenth of one percent (0.12%), or 42
leaks in that year. The failure rate in that year, then, will have nearly doubled over the
average annual rate for the past five years (22.6). The critical point in this analysis is the
understanding that failures in buried natural gas piping can be prudently managed only
when they are occurring at very low rates. Otherwise new leaks in the system occur too
frequently to be detected by even annual leak surveys of the entire system, resulting in an
increase in the likelihood of hazardous leaks and the potential for harmful incidents.

3 The Pipeline and Hazardous Materials Safety Administration defines a “hazardous leak” as an
unintentional release of gas that represents an existing or probable hazard to persons or property and
requires immediate repair or continuous action until the conditions are no longer hazardous.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 25 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 26

Priority Aldyl A Piping

Every pipeline operator strives to install and maintain a safe, reliable and cost-effective
system. While the goal is complete system integrity, it is impossible to avoid having any
leaks, especially on large systems such as Avista‟s with over 12,000 miles of mains and
several hundred thousand services. Regulators and the industry acknowledge this reality
through the adoption of standardized leak-survey methodologies, and recognized pipe
remediation practices.

But, while leaks are inherent on a system, there are circumstances where the expected
reliability of a particular pipe begins to rise compared with that of other piping and
industry norms. We have demonstrated that such is the case for portions of the Aldyl A
pipe in Avista‟s system, and accordingly, we have determined these classes to be at-risk
of quickly approaching a level of reliability that is unacceptable and in need of proactive
remediation. It‟s for this reason that Avista refers to these pipe classes as “Priority Aldyl
A piping.”
Formulation of a Management Program for Priority Aldyl A Pipe

The timely application of Avista‟s Distribution Integrity Management approach to its
recent and ongoing leak analysis and its reliability modeling results, including Dr.
Palermo‟s review, and the experience gained in three priority pipe-replacement projects
in 2011, has prompted Avista to formulate a protocol for systematically managing its
Aldyl A pipe. The following categories are useful classifications for Avista‟s definition
of “priority Aldyl A pipe”4:

1. Aldyl A gas services tapped to steel main pipe
2. Pre-1973 Aldyl A main pipe
3. Pre-1984 Aldyl A main pipe

Avista has determined these classes of pipe are at risk of approaching unacceptable levels
of reliability without prompt attention. Accordingly, Avista believes the decision to
formulate a management program for its priority Aldyl A pipe is both timely and prudent,
and is consistent with results of our leak investigations, Integrity Management principles
and the recent Call to Action of Secretary LaHood. The decision is also consistent with
the prior federal bulletins on this subject and with the decisions of other similarly-situated
utilities that have implemented similar pipe-replacement programs. Finally, given the
significant amounts of priority Aldyl A pipe on Avista‟s system, commencing a protocol
now provides us greater opportunity to manage this facility in a prudent and cost-
effective manner.

4 Each class noted above is subject to material failures due to concentrated stresses such as rock
impingement, bending stresses, squeeze off, and failures of service towers and caps.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 26 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 27

Priority Aldyl A Piping in Avista’s System

Main Pipe - Avista has approximately 12,500 miles of natural gas main pipe in its
service territories in the States of Washington, Oregon and Idaho. Approximately
seventeen percent of this total, or 2,000 miles, is Aldyl A pipe of all classes and sizes.
Proportions of various classes of piping in Avista‟s system, including priority Aldyl A
pipe (pre-1973 and pre-1984 mains) is shown below in Figure 6.

Figure 6. Avista’s priority Aldyl A pipe, shown as a proportion of the different pipe
classes in Avista’s natural gas system (items 2 and 3 from the list above).

Gas Services - Avista has approximately 314,000 natural gas services, of which
approximately 16,000, or five percent, are Aldyl service pipe tapped to steel main pipe,
shown below in Figure 7 as priority Aldyl A services.

Other Aldyl A
1/2" -4"
1355 Mies
Priority Aldyl A, pre-
1984 main, 1 1/4" -4"
714 Miles
Other Polyethylene
1/2"-6"
6350 Miles
Steel
1/2" -20"
4065 Miles
Miles of Pipe Materials in Avista Natural Gas System
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 27 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 28

Figure 7. Avista’s priority Aldyl A gas services (tapped from steel mains), shown as a
proportion of Avista’s total gas services.

Other Aldyl A Pipe Replacement Programs
Aldyl A Pipe in the Pacific Northwest

Through general conversation with our colleagues in western gas utilities, Avista believes
it has a substantially greater proportion of Aldyl A pipe in its system than do our
neighboring Pacific Northwest gas utilities. The proportions of Aldyl A in Avista‟s
system (or of any other brand of early polyethylene pipe), however, is not a reflection of
the unique purchasing practices of Avista, since plastic pipe quickly became the standard
of the industry and the predominant pipe installed by utilities across the county. But, the
proportions of early plastic pipe in a system do tend to track with the amount of system
growth that gas utilities experienced during the 1970s and early 1980s. For Avista, this
was a time of particularly rapid expansion of its natural gas system (from the Spokane
metro area to outlying communities in its Washington and Idaho service territories), and
consequently, the proportion of early Aldyl A pipe in our system reflects this period of
expansion.

Established and Emerging Programs for Aldyl A Pipe Replacement

Two western utilities, Southwest Gas and Pacific Gas & Electric, have significant Aldyl
A pipe management programs either well underway or anticipated, which are very briefly
summarized below.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 28 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 29

Southwest Gas – Responding to a fatality incident in the early 1990s, Southwest Gas
entered into a settlement agreement with the Corporation Commission of Arizona to
conduct additional leak monitoring and pipeline remediation. By the late 1990s,
Southwest Gas had replaced 74 miles of Aldyl HD (high density) main pipe covered by
the agreement, and had replaced another 648 miles of Aldyl A pipe based on its leak
survey monitoring results. In 2005, Southwest Gas had another injury and property
incident on their system involving Aldyl A pipe, and implemented an additional pipe
replacement program in the vicinity of the incident. Southwest Gas has also worked
closely with staff of the Public Utilities Commission of Nevada in the monitoring and
replacement of what the Commission refers to as “aging” and “high risk” natural gas
pipe, including Aldyl A pipe.

Pacific Gas & Electric - After some very high-profile natural gas incidents in 2011 that
involved Aldyl A piping, Pacific Gas & Electric has announced plans to replace all the
Pre-1973 Aldyl A pipe in its system. The utility reportedly has 7,907 miles of Aldyl A
pipe of all classes in its system, which is about 19 percent of its gas system inventory. By
comparison, Avista‟s Aldyl A pipe stock is about 16 percent of its system. Pacific Gas &
Electric‟s planned replacement of its Pre-1973 Aldyl A pipe represents a massive effort
because the utility plans to remove and replace the 1,231 miles of pipe in a proposed
timeframe reported as in the range of three years, and at a cost said to exceed $1 billion,
but that has not yet been formalized. There is some question regarding the selection of
only pre-1973 Aldyl A for replacement in PG&E‟s system, since at least one recent high-
profile incident was reported on newer vintage (still pre-1984) Aldyl A.

Developments of Interest

US Congresswoman Jackie Speier of California has been raising the awareness of
Congress and Transportation Secretary, LaHood, in two separate actions. First, in May
2011, Speier sponsored House Resolution 22 entitled the “Pipeline Safety and
Community Empowerment Act of 2011.” The legislation provided for citizens being
able to easily access pipeline maps and safety-related information from pipeline owners,
prescribed certain changes in pipeline monitoring requirements, and called for the
addition of physical safety devices to existing pipelines. The bill is currently under
consideration by the House Committees on Transportation and Infrastructure, and Energy
and Commerce.

In October 2011, Speier wrote to Secretary LaHood calling on him to direct the Pipeline
and Hazardous Materials Safety Administration to “take immediate action to address the
long-known safety risks associated with pre-1973 Aldyl-A plastic pipe manufactured by
DuPont.” She went on to advocate for the removal of this pipe from use in the U.S., and
to commend Pacific Gas & Electric for its planned removal of all of its pre-1973 Aldyl A
pipe. Citing the DuPont letters to customers, federal safety bulletins, and the Waterloo
incident, she chided Congress for not taking action, and urged the Secretary to
immediately do so.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 29 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 30

Designing Avista’s Replacement Protocol for its Priority Aldyl A
Pipe

Avista modeled two different approaches to the replacement program, one that was
systematic, based on an established timeframe and one that was responsive to problem
areas as they were identified.

Systematic Replacement Program
Time Horizon

Determining the appropriate length of time over which to replace the Priority Aldyl A
pipe involves the optimization of several factors, including: 1) the overall urgency from
a reliability and safety perspective, both present and forecast; 2) potential consequences;
3) the impact of more intensive leak survey methods to better identify priority facilities in
need of replacement and in helping reduce the potential for harmful incidents; 4) the
ability to effectively prioritize specific projects to better ensure facilities in greatest need
are addressed earliest; 5) the availability of equipment and labor resources needed to
conduct the work, and the ability to coordinate the work with Avista‟s ongoing
construction programs; 6) program efficiency, and 7) the degree of rate pressure placed
on customers, both in absolute terms and in relation to other reliability and safety
investments required across the natural gas and electric business. Ultimately, Avista
must ensure that management and removal of its Aldyl A pipe is conducted in a way that
shields our customers from imprudent risk, while at the same protecting them from the
burden of unnecessary costs.
Prudent Management of Potential Risk

Avista believes it is important to establish for our customers and other stakeholders that
while there can never be „zero risk‟ associated with the program, the potential risk can be
prudently managed. On one hand, a replacement program carried out over a very short
timeframe cannot prevent the occurrence of all leaks forecast to occur over the course of
the program. But at the other extreme, it‟s clear that setting a replacement timeline that‟s
too lengthy would likely result in safety, reliability and financial consequences for our
customers and our business that could be regarded as imprudent. Avista believes the
timeline for the replacement program should optimize the factors mentioned above in a
way that reduces the risk associated with Aldyl A pipe to the range of „prudent risks‟
associated with the myriad other electric and gas facilities and practices that are used to
serve the energy needs of utility customers. Said differently, there is no possible way to
eliminate the risks associated with energy infrastructure, but there is a range of limited
risk that‟s deemed prudent in the conduct of our business. Avista‟s treatment of its Aldyl
A pipe will be managed to comport with these sound business practices.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 30 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 31

Prioritizing the Work

As important as the replacement timeline in prudently managing the reliability of
Avista‟s Aldyl A piping, is the ability of the Asset Management and Distribution
Integrity Management staff to partner in effectively prioritizing the pipe-replacement
activities in a way that minimizes the potential for hazardous leaks. Results of the
Availability Workbench modeling provide some support in prioritization but do not take
into account factors such as soil conditions or the proximity to buildings or people.
Obviously, a leak occurring in a vacant field will have little, if any, consequence and will
likely be detected and repaired during the next leak survey. By contrast, the potential
hazard of a leak increases with its proximity to people and structures, so replacing pipe
that has a high probability of leaking and is located in populated areas is first priority.

Avista‟s Integrity Management approach provides the analytical tools that integrate key
knowledge and information needed to effectively prioritize replacement activities based
on the potential hazard. In the prioritization process, each segment of Aldyl A pipe in
Avista‟s system is assigned a relative risk ranking, based on its age, material, soil
conditions, construction methods, and its maintenance and leak history. This information
is then loaded into Avista‟s GIS database containing the gas system maps. These maps
contain a “layer” of grid squares (50 feet per side) that correspond with sections of the
Aldyl A pipe. Each square is known as a “raster” and each raster contains all of the risk-
related information that was loaded into the GIS system, as associated with the Aldyl A
pipe, at that precise geographic location.

Next, the software integrates the historic leak information for Aldyl A pipe on Avista‟s
system with the risk data associated with each of the Aldyl A pipe segments, and predicts
the geographic areas (via the risk rasters) where Aldyl A pipe failures are expected to be
greatest. In the last step, the software integrates the results for expected failures with
information for each risk raster that identifies the potential consequence of a leak on that
segment (i.e. the proximity of that raster to buildings and people, and the population
density/sensitivity of those structures). The end result is a color-coding of the rasters that
provides a visual picture of where on the gas system that both the potential likelihood of a
leak, and the potential consequence of a leak, are greatest. This approach provides Avista
with a comprehensive and objective means of identifying Aldyl A pipe that has the
highest priority for replacement.
Twenty-Year Proposal

Avista modeled various time horizons for the replacement program, up to a timeline of 30
years, and determined a replacement horizon in the range of twenty years to represent an
optimum timeframe for removing and replacing its priority Aldyl A pipe. Shortening
the timeline was found to have increasing cost impacts to customers but with little
improvement in the numbers of expected facility failures. Lengthening the timeline past
twenty years, however, was found to result in a substantial increase in the number of
material failures expected. A replacement timeline of 25 years, for example, resulted in
more than a doubling of the number of leaks expected when compared with the twenty
year horizon. Under the twenty year replacement program, the number of material
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 31 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 32

failures each year is expected to increase slightly until 2017, at which time the
cumulative effect of priority piping replaced since 2012 begins to check the failure count
and then drive it toward zero over the remaining course of the program (Figure 8).

Figure 8. Expected numbers of material failures in Avista’s priority Aldyl A piping in
two cases: Replacement Case - piping replaced over a twenty year horizon in the
manner proposed by Avista in this report, and Base Case – assumed that priority
piping was not remediated under any program.

Importantly, Avista is not saying that experiencing an increase in leaks on our system is
“acceptable” per se, in particular, after having had two harmful incidents in the past few
years. What we are saying, however, is that by using the Integrity Management model to
prioritize work activities in the manner described above, Avista believes it can manage
the forecast Aldyl A leaks in a way that significantly reduces their potential occurrence in
areas that could result in harm. Under this approach, Avista believes it can prudently
manage the replacement of priority Aldyl A pipe with the goal to avoid harmful incidents
altogether, and at a reasonable rate impact for our customers.
Initial Optimization

Importantly, Avista‟s proposal for a 20-year replacement program represents an
optimization based on the information we have available today. Any number of factors
could change as the work proceeds over the first few years that could result in a „new‟
optimum time horizon. Avista will be collecting new leak survey and other information
each year, and will continue to use its Asset Management models to further refine
expected trends and potential consequences, making program adjustments as appropriate.

0
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Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 32 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 33

Responsive Replacement Program

Avista also modeled a very-different pipe replacement strategy to provide a further
measure of the efficacy of the systematic replacement program. This scenario, referred to
as the Responsive Case, was essentially a reactive approach where pipe remediation and
replacement activities would be driven by leak survey results and the magnitude of leak
consequences. Under this case, it‟s expected that pipe replacement activity would
commence at a lower level than in the systematic case, but would also vary significantly
from year to year, depending on patterns of detected leaks and their consequences.
Ultimately, however, the expected activity and spending levels would far exceed both the
annual and cumulative costs of the systematic approach. This is because pipe segments
are not replaced ahead of actual material failure (as happens in the structured case) and so
the resulting work activity more-generally follows the geometrically-increasing numbers
of material failures expected over time. This scenario was easily judged as failing to
provide an appropriate measure of prudence, including system safety, reliability, cost-
efficiency, or business risk. Without a prioritized replacement protocol in place Avista
would be resigned to replacing pipe in response to serious leaks and potential incidents,
after-the-fact, rather than with foresight. Such was the case with the Aldyl A
replacements Avista completed in 2011.

From a practical standpoint, Avista believes that by managing the replacement of its
priority Aldyl A pipe in a systematic way it can prudently manage potential risks and
impacts to its customers and other stakeholders, plan for and use construction resources
most efficiently, and plan more effectively for the capital and expense requirements
necessary for the effort. This is clearly the case when compared with a responsive
approach.

Dr. Palermo’s Assessment of the Proposed Protocol for Managing Avista’s
Priority Aldyl A Piping

Following Avista‟s Integrity Management evaluations of failure trends in its Aldyl A
piping, and the development of its proposed protocol, we invited Dr. Palermo to review
the completed protocol and to judge, from his expert perspective, the overall
effectiveness and adequacy of the program. Dr. Palermo completed his review in
February 2012, and judged Avista‟s protocol to be highly responsive and appropriate to
the management needs of the priority Aldyl A pipe in Avista‟s system. In particular, he
noted his support for Avista‟s priority focus on pre-1973 Aldyl A pipe, and on the plan to
remove and replace its pre-1984 Aldyl A mains. He further noted his agreement with
Avista‟s priority for remediating Aldyl A services tapped to steel main pipe, and to the
protocol of “managing in place” existing Aldyl A service piping between the mains and
meters. Finally, Dr. Palermo agreed with the proposed twenty-year replacement time
horizon for Avista‟s priority Aldyl A pipe, noting the reliability modeling results, and the
effectiveness of Avista‟s increased leak survey and application of Integrity Management
information, tools and analysis in prioritizing pipe replacement activities. Dr. Palermo
reviewed and approved this affirmation prior to the finalization of this report.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 33 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 34

Application of Avista’s Washington State Study Results to Aldyl A
Pipe in the States of Oregon and Idaho

Forty-six percent of Avista‟s Aldyl A main pipe is currently in service in the State of
Washington, and coincidentally, so are 46% of Avista‟s Aldyl A services tapped to steel
mains. Since Avista‟s leak survey study and subsequent modeling results are based on
Washington State data, then it follows that the expected results are most applicable to this
jurisdiction. The degree to which the reliability modeling results are applicable to
Avista‟s Aldyl A pipe in the States of Oregon and Idaho depend on factors such as the
age of the at-risk pipe and on the known similarity of conditions under which the pipe
was installed, including method (trenching or plowing), backfill material, compaction and
squeeze-off practices, soil conditions and ambient soil temperature, etc. Avista is aware
of at least some general differences among state jurisdictions, including more favorable
soil conditions in Oregon, newer pipe materials, and construction techniques potentially
more favorable to low-ductility pipe. A contributing complication, too, is the relatively
large amount of pipe of unknown age and material in services in Oregon. This territory
was acquired by Avista from a utility that did not have a consistent practice of mapping
services, and some existing maps were lost before the purchase. As a result, Avista is
conservatively managing this „unknown‟ pipe as if it was priority Aldyl A pipe, until the
time that these segments are verified by records review and possible field verification.

Most important to this discussion, however, is the fact that Avista is using its Integrity
Management model to integrate leak survey and other data to develop the priority pipe
replacement activities for each year of the program. Since comparable leak survey data
from priority Aldyl A pipe in Idaho and Oregon will be included in the prioritization
analysis, then regardless of any differences that do affect the expected reliability of the
Aldyl A pipe, that inherent reliability will be automatically integrated into the modeling,
ensuring that Avista is systematically replacing the pipe at greatest risk, regardless of the
jurisdiction. Finally, since the Medford and Grants Pass, Oregon, service territory offers
a 12-month construction season, Avista will be able to continuously mitigate priority
Aldyl A piping within that area when northern territories are effectively unable to
continue working.
Resource Requirements and Expected Cost
Staffing

Avista‟s proposed Aldyl A pipe replacement project represents a major undertaking, even
when spread over a twenty-year horizon. In addition to the scope of the effort, there‟s
added complexity in efficiently managing the project, since Avista‟s territory extends
from Bonners Ferry, Idaho to Ashland, Oregon, a distance of over 650 miles. Each year,
the deployment of equipment and inspection and construction personnel will have to be
adjusted across this service area in response to the sites identified for highest-priority
pipe replacement in any given year. Avista is planning to coordinate with contractors to
manage much of this construction, and since this project represents a long-term
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 34 of 35
Protocol for Managing Aldyl A Natural Gas Pipe - Avista Utilities Asset Management May 2013 35

construction commitment, it is expected that the pool of contractors bidding for this work
will be substantial, resulting in advantageous pricing and flexibility of field labor.

Though much of the physical construction will be accomplished through the use of
contractors, there will still be a need to increase Avista‟s internal staffing to manage the
flow of information, quality assurance, mapping, and related project documentation.
Quality assurance is a critical project element that Avista will rigorously control.
Effective remediation of Avista‟s priority Aldyl A pipe is a critically-important corporate
objective, and we must continually ensure that sound inspection, training and auditing
delivers the results we expect. Finally, the pipe replacement activities themselves will
often have disruptive effects on our customers and others. Avista will carefully
coordinate customer and community communications and notifications in an effort to
minimize the effects of any disruptions.
Capital Costs

Avista‟s analysis and planning effort is projecting capital costs just over $10 million
annually from the year 2013 – 2032. Actual costs will vary somewhat depending on the
prioritization of piping to be replaced each year, among other factors, and the calculated
amounts will also be subject to an estimated 2.3% annual inflation. Avista is planning to
spend approximately $5 million in capital on this program in 2012, allowing for effective
planning with contractors, hiring Avista staff, and developing a solid project management
foundation for years 2013 and beyond.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 5, Page 35 of 35
Avista
Study of Aldyl-A Mainline Pipe Leaks
2018 Update
ISSUE DATE: April 2018
Report Prepared By:
Scott Gloyna
Report Approved for Issue By:
Gordon Mains
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 1 of 23
Executive Summary
The scope of this study was to review and update the analysis of Aldyl-A pipe conducted in 2013
based upon leaks and replacements through the end of 2017. The original study developed
failure distributions that described the likelihood of leaks occurring on the Aldyl-A pipe installed by
Avista for natural gas distribution and to evaluate multiple replacement scenarios. Based upon the
original study and additional internal analyses, Avista selected the 20-year replacement program.
The original study identified rocky soil as the soil type most likely to have Aldyl-A mainline pipe
leaks. Utilizing soil type specific Weibull distributions, and updated pipe information from the end
of 2017 the number of leaks predicted when no proactive replacements are conducted over the
next 70 years on Aldyl-A mainline pipe is 12,335 and the cumulative replacement costs is $3
billion.
After updating the model with leaks and replacements from 2013-2018 the expected number or
leaks for the remaining period (2018-2088) reduced from 26,792 to 12,335 due to the large
amount of the worst pipe already replaced. If the 20-year replacement program where all Aldyl-A
pipe is removed continues there is a slight reduction in the expected number of leaks, 255 in the
original study and 246 in the updated model.
According to the table below the baseline scenario remains more cost effective when compared
to the replacement strategies, but it should be considered that current cost forecasts are based
on cost of replacement and effects per leak. Safety risks were also incorporated into the study
and while no individual segment of pipe exceeded the supplied thresholds in either scenario the
cumulative risk was above the stated thresholds. This results in the projected number of
catastrophic events drop from 258 to 5 events over the next 70 years by replacing the Aldyl-A
pipe.
While Avista's 20-year structured replacement program has proven to reduce the highest risk in
the early years of the program, the continuation of this structured replacement program is both
necessary and prudent to mitigating the remaining risks within the system, and to achieving
Avista's goal of operating and maintaining a safe and reliable natural gas distribution system.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 2 of 23

Results of Aldyl-A Mainline Pipe Leak and Replacement Study
Scenario
Leaks from
2018 through
2088
IRR
Levelized Gr.
Mar.
Requirement*
Lev ROE* NPV equity*
Baseline with effects –
2013 26792 9.21% $16,417 $0 $0
20 Year Replacement
with effects - 2013 255 6.04% $23,229 $6,513 $93,490
Baseline with effects –
2018 12,335 18.04% $10,785 $0 $0
20 Year Replacement
with effects - 2018 246 3.87% $36,147 $12,214 $177,848
*In Thousands

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 3 of 23
Contents
1 INTRODUCTION ...................................................................................................... 6
2 METHOD ............................................................................................................... 6
3 ASSUMPTIONS ....................................................................................................... 7
4 MAINLINE ALDYL-A PIPE ......................................................................................... 8
4.1 Analysis ................................................................................................................. 8
4.2 Maintenance Cost Forecast .................................................................................... 11
4.3 20 Year Replacement Scenario Update .................................................................... 13
5 CONCLUSION ....................................................................................................... 19
6 FUTURE DATA COLLECTION ................................................................................... 19
APPENDIX A – MAINLINE ALDYL-A PIPE ANNUAL EXPENSES PER YEAR BASED ON AVISTA REVENUE
REPLACEMENT CALCULATOR ................................................................................. 21

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 4 of 23

Disclaimer

© 2018 ARMS Reliability LLC
THIS PUBLICATION IS PROTECTED BY COPYRIGHT LAW AND UNLESS OTHERWISE SPECIFIED IS FOR YOUR
INTERNAL BUSINESS USE ONLY. NO PART OF THIS PUBLICATION MAY BE REPRODUCED OR
DISTRIBUTED OUTSIDE BY ANY PROCESS, ELECTRONIC OR OTHERWISE, WITHOUT THE SPECIFIC WRITTEN
PERMISSION OF ARMS RELIABILITY

Although every effort has been made by ARMS Reliability Engineers LLC to ensure the
accuracy and completeness of this document and reported results, no warranty, express
or implied is made by ARMS Reliability Engineers LLC as to the accuracy or completeness
of the documentation or reported results. Any decisions made as a result of the
information in this report are at the sole discretion of the reader

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 5 of 23
1 INTRODUCTION
This report has been developed to provide the results of an analysis carried out on the Aldyl-A
pipe installed by Avista for natural gas distribution. The scope of the study was to review and
update the failure distributions, leak rates and replacement costs originally developed in the
original 2013 study.
2 METHOD
During the first phase of this study all available historical data on the Aldyl-A pipe was collected.
This included GIS segment, installation year, soil type, leak history, replacement history, location,
and length. The various sources of this data were combined in Excel and used to calculate the
following:
• The age of the pipe when each of the leaks occurred
• The age of the pipe at capital replacement
• The length of pipe replaced
• The age of the pipe not yet replaced
• The length of the pipe not yet replaced
For the mainline Aldyl-A pipe the data was separated by GIS locations and imported into the
Availability Workbench software where Weibull distributions could be developed. Each location
had an associated age, soil type, and length. The Weibull distribution was selected, as it is able
to provide risk predictions with small samples and can describe infant mortality, chance failure,
and wear-out failure behaviors. For two soil types, Control Density Fill (CDF) and
Concrete/Grout, a Weibayes distribution had to be used because the numbers of failure events
was insufficient for a standard Weibull analysis. For these two soil types the shape factor was set
to four to reflect a wear-out failure behavior.
Two models were run for the Mainline Aldyl-A replacement, a baseline scenario with no proactive
pipe replacement and a model where all of the Aldyl-A pipe is replaced over a 20-year timeframe.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 6 of 23
3 ASSUMPTIONS
The assumptions made during the study were as follows:
1. All models are simulated over a 75 year lifetime
2. A three foot section of pipe is replaced when a leak occurs. This number was included as the
location quantity in AWB
3. Only 1.25” OD and greater pipe was considered
4. Soil Types of 0, unknown, or blank was assumed of rocky type
5. All Aldyl-A pipe installed between 1984 and 1987 was manufactured before 1984
6. Pipe of unknown install year was installed in 1970
7. All replacements that were done in 2011 and 2012 were in rocky soil
8. Call out time for corrective replacements includes 1.75 hours of travel time
9. All maintenance costs are included as equipment
10. The PF interval for leak inspections is zero
11. The shape factor, Beta of 4 was used for Concrete/Grout and CDF Soil types
12. Each Exposed Pipe Report for the Davenport and Talent replacement projects reports on an equal
length of pipe.
13. Baseline models do not consider any planned capital replacement.
14. Planned replacement of Aldyl-A Mainline pipe costs $357 per three feet in Washington and Idaho
and $360 per three feet in Oregon.
15. Unplanned replacement of Aldyl-A Mainline pipe costs $5,071 per three-foot section.
16. Consequences for a Catastrophic Event, Injury with lost time and injury without lost time are applied
per Avista standard practice.
17. Safety thresholds were incorporated with the following severity levels
a. Catastrophic Event: Once per 50 years
b. Craft Injury, WITH Lost Time/Light Duty: Once per year
c. Craft Injury, NO Lost Time: Four events per year
18. A different type of pipe is used to replace failed Aldyl-A pipe and as such a second failure of the
same length cannot occur in the lifetime.
19. Cost escalations are 2.3% per year.
20. Effects escalation is 10% per year.
21. Revenue Requirement Calculation Assumptions
a. 75 Year project life
b. Capital Class 2 (Generation T & D)
c. Gas: 20% ID, 35% OR, 45% WA

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 7 of 23
4 MAINLINE ALDYL -A PIPE
4.1 Analysis
As an example, the failure rate curve based on the Weibull distribution developed for Aldyl-A
Mainline pipe installed in rocky soil is shown in Figure 1. This curve has the following
parameters:
η = 2,548,000 hours or 290 years (63.2% of the installed pipe will generate a leak
prior to reaching this age)
β = 3.945 (indicating a predictable end of life)

Figure 1: Failure rate curve for Aldyl-A Mainline pipe installed in rocky soil.

Table 1 below shows the change in the failure distributions when the leaks and proactive
replacements from 2013 to the end of 2017 were incorporated. While Rocky soil still has the
shortest life with an eta value of 290 years, the main change is that the eta values have increased
while the beta values have decreased. The result is that on average, the pipe is lasting longer
than the original model predicted, but there is less confidence on when it will fail. This is largely
due to the large amount of pipe being replaced proactively. The proactive replacement both is
Rocky Failure Rate
0 37668 75336 1.13E+05 1.5067E+05 1.8834E+05 2.2601E+05 2.6368E+05 3.0134E+05 3.3901E+05 3.7668E+05
Time
0
5.6124E-10
1.1225E-09
1.6837E-09
2.245E-09
2.8062E-09
3.3675E-09
3.9287E-09
4.4899E-09
5.0512E-09
5.6124E-09
Fa
i
l
u
r
e

R
a
t
e
Regionalised rate
Distribution rate
P0: 0%
B20: 1742444.8
B15: 1607913.64
B10: 1440638.97
e: 2.09254414E-05
r: 0.992112898
g: 0
b: 3.945
h: 2548000
Median rank
2-parameterWeibull
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 8 of 23
removing the pipe with the worst failure rates and incorporates a large amount of un-failed pipe
into the Weibull analysis.

Soil Type Eta 2013 (Years) Beta 2013 Eta 2018 (Years) Beta 2018
Clay/Bentonite 473.52 3.40 627.85 3.18
Concrete/Grout 317.24 4 387.21 4
Control Density Fill (CDF) 308.68 4 347.49 4
Loam 311.53 3.95 425.91 3.55
Other 711.19 2.84 1,386.99 2.44
Rocky 221.92 4.36 290.87 3.95
Sand 274.89 4.32 340.98 4.02
Table 1: Weibull Parameters by Soil Type for 2013 study and 2018 study

Using the distribution shown in Figure 1, along with the distributions generated for the other soil
types identified in the study and knowing the length of Aldyl-A pipe installed in each soil type that
is yet to be replaced, the expected number of leaks in Aldyl-A if the replacement program is
stopped was calculated over a ten-year period. The predicted number of leaks on Aldyl-A pipe for
the next 10 years with no proactive replacement program is shown in Figure 2.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 9 of 23

Figure 2: Predicted number of leaks per year in Aldyl-A mainline pipe for next 10 years.

Note: The prediction shown above in Figure 2 and in Figure 3 and Figure 4 assume that repairs
are only carried out when a leak occurs. The effect of capital replacement on this profile is not
considered as part of the baseline.
If the replacement program were to stop the frequency of leaks for the next 10 years ranges from
17 to 53 and the average number of leaks per year is 32. The uneven increase in leak frequency
is most likely due to both pipe of different ages failing, and the actual pipe lengths considered.
It should be noted that the 2013 study predicted an average of 52 leaks per year during the same
period. This reduction is caused by the proactive replacement of pipe that has been occurring.
As the pipe continues to age the number of leaks is predicted to continue to increase in the
baseline scenario. This can be seen in the 70-year leak prediction for Aldyl-A mainline pipe in
Figure 3. The model predicts that the leaks will increase from an average of 36 leaks per year
over the next 10 years to an average of 174 leaks per year over a 70-year period.
0
10
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2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
Le
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Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 10 of 23

Figure 3: Predicted number of leaks per year in Aldyl-A mainline pipe from 2018 through 2088.
4.2 Maintenance Cost Forecast
By considering all the Aldyl-A mainline pipe installed which has not yet been replaced, a financial
forecast can be made based on the number of leaks expected. If an unplanned replacement
costs $5,071 is applied to repair each leak, the maintenance budget dedicated to leak repairs can
also be determined. The updated baseline maintenance cost forecast is provided in more detail
in the following sections of this report.
The total costs, which includes the maintenance costs and effects, is shown in Figure 4 and
Appendix A
0
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Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 11 of 23

Figure 4: Forecasted unplanned total costs of leaks on Aldyl-A mainline pipe through 2088 per 2018
analysis.
$
$50
$100
$150
$200
$250
20
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20
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Aldyl-A Mainline Unplanned Replacement Cost
Forecast -2018 Update
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 12 of 23
4.3 20 Year Replacement Scenario Update
Avista has previously chosen to replace the Aldy-A mainline pipe over 20 years. To ensure that
potential changes in pipe failure rates and costs are taken into account, the results from the 20-
year replacement scenario has been updated with pipe replaced from 2013 through then end of
2017 either as part of the replacement program or in response to leaks.
In addition to updated pipe segments, the cost associated with replacement were also updated
with current numbers. Capital replacements are assumed to cost $357 per three feet in
Washington and Idaho and $360 per three feet in Oregon. These numbers are up from $243.42 in
Washington and Idaho and $183.15 in Oregon. Unplanned replacements of leaks are assumed to
cost $5,071 per three feet, up from $3,346. The costs were adjusted for inflation and for the
additional restoration costs not normally associated with the work (i.e. paving, traffic control, and
etc. that get generically billed monthly). Further assumptions are made for the consequence
costs, the LCC model and the Revenue Requirement calculator which are standard Avista
assumptions and processes and will not be covered in this discussion.
Leaks and capital replacements are not returned to service after repair/replacement to reflect
replacing the failed Aldyl-A pipe with a different type of pipe.
Leaks or failures identified through inspection are handled as unplanned replacements with
associated costs and consequences. This is reflective of the inspection method which provides
no indication of a deteriorating condition, only an indication of a failure or a leak.
The 2018 update of the 20-year replacement program shows a reduction in leaks of 12,079 over
from 2018 through 2088 when compared to the updated baseline and an increase of one leak
when compared to the original 2013 results. The change in the predictions of the 20-year
replacement program is within standard modeling error and could be a result of incorporating the
planned replacements that have taken place into the failure rate analysis.
The leak profile comparison can be seen in Figure 5.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 13 of 23

Figure 5: Comparison between Aldyl-A 2018 Baseline, 2018 20 Year Replacement Program and the
2013 20 Year Replacement Program model results.

To show the impact that the replacement program has already had and what can be expected for
the remainder of the planned replacements, the total number of leaks over a from 2018 through
2088 are shown below in Table 2. As can be seen, the number of expected leaks if there is no
planned replacement program has dropped significantly, while the expected number of leaks with
the replacement program has remain basically unchanged.

0
20
40
60
80
100
120
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
Le
a
k
s
Year
2018 Baseline Vs 2018 20 Year Replacement
Program Vs 2013 20 Year Replacement Program
2018 Baseline Model Leaks 2018 20 year replacement Leaks
2013 20 year replacement Leaks
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 14 of 23

Study Year Scenario Total
2013 Baseline 26,792
20 Year Replacement
Program 255
2018 Baseline 12,335
20 Year Replacement
Program 246
Table 2: Leaks results for Aldyl-A mainline pipe from 2018 through 2088 for 2013 and 2018 studies

To be able to effectively compare the scenarios the results from the RCM and LCC studies were
compiled and analyzed in Avista’s Replacement Revenue Requirement model. The annual
expenditures from this analysis are recorded in Appendix A.
Figure 6 shows the updated cumulative cost comparison of replacing Aldyl-A mainline pipe
proactively vs performing replacements as leaks occur. As can be seen, the replacement
scenario has significant early life costs when compared to the baseline. After the replacement
projects are completed the cost associated with the Aldyl-A pipe is negligible while the baseline
maintenance expenditures continue to increase with the increasing number of leaks. Total lifetime
expenditures for the baseline surpass the replacement program in 43 years (2061), this is
significantly longer than the original study predicted (2049) but that is due to the large amount of
pipe that has already been replaced.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 15 of 23

Figure 6: Cumulative Cost Comparison of Aldyl-A mainline Replacement Scenario

Scenario Leaks
from
2018
through
2088
IRR Levelized Gr.
Mar.
Requirement*
Lev ROE* NPV equity*
Baseline with effects -
2013 26,792 9.21% $16,417 $0 $0
20 Year Replacement
with effects - 2013 255 6.04% $23,229 $6,513 $93,490
Baseline with effects -
2018 12,335 18.04% $10,785 $0 $0
20 Year Replacement
with effects - 2018 246 3.87% $36,147 $12,214 $177,848
* In thousands
Table 3: Mainline Aldyl-A Replacement Revenue Requirement Analysis Summary
$
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
$4,000
$4,500
0 3 6 9 12 15 18 21 24 27 30 33 36 39 42 45 48 51 54 57 60 63 66 69 72
Cu
m
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l
a
t
i
v
e

C
o
s
t

P
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o
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s
Mi
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s
Year
Baseline 2018 20 Year Replacement - 2018
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 16 of 23

The Aldyl-A Mainline Replacement Revenue Requirement Analysis summary in Table 3 shows
that the replacement program is slightly less cost effective than it was in 2013. This is due to the
replacement of the worst pipe taking place early in the replacement programs scope. This trend
can be expected to continue and should be taken as an indication that the program is meeting its
goal of reducing the overall risk of leaks from the Aldyl-A pipe. The option of not replacing the
pipe is still more cost effective over though 2088, given the assumptions of the Revenue
Requirement model, but it should be noted that as the pipe continues to age the cost and
associated risk of leaks increases significantly.
Safety risks and criticality were also considered as part of the study update. It is understood that
each failure event (leak) does not always result in an injury and this is incorporated as a
percentage of events that result per Avista standard modeling guidelines. The severities used are
shown in Table 4 below.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 17 of 23

Effect Severity % of Failures Where Effect
Occurs
Catastrophic event 50 Years 1.82%
Craft injury, WITH Lost
Time/Light Duty 1 Year 0.11%
Craft injury, NO Lost Time 3 Months 0.29%
Table 4: Effect Safety Severity and Redundancy Factor

With these assumptions the Safety Criticality was calculated for each segment of pipe in both the
baseline and 20-year replacement scenarios. With the pipe that is currently installed, no individual
segment exceeded the risk thresholds, but the cumulative risk did exceed the threshold for
catastrophic events. The proactive replacement strategy has a significant effect on the overall
risk, reducing the expected number of Catastrophic events from 246 to 4 over the next 70 years.
It should be noted that slight changes in the percentage of failure events where the effect would
occur can have large impacts on the final criticality.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 18 of 23
5 CONCLUSION
This study builds upon the 2013 study which showed that soil type was a major contributor to
failure rates for Aldy-A pipe. While the basic findings which indicate Rocky soil has the highest
likelihood of failure have remained unchanged (see Table 1), the new analysis has shown that the
proactive replacements have had a positive effect on failure rates by increasing the characteristic
life (eta) of the pipe by an average of 169.7 years. This increase does come with reduced
certainty of exactly when failure will happen with the beta value reducing by an average of 0.25
for all soil types.
The 2013 study predicted a total of 26,792 leaks on Aldyl-A mainline pipe from 2018 through
2088 years without any form of a proactive replacement program. Based upon the proactive
replacements that have occurred, the number of leaks predicted over the same period has
reduced to 12,335 with 246 catastrophic events if the proactive replacement were to not continue.
With the current replacement of all Aldyl-A pipe by 2035, the number of predicted leaks from 2018
to program completion reduces slightly, moving from 255 to 246 leaks of which 4 have the
potential to be catastrophic events.
The Avista Revenue Requirement Calculator shows that it is less costly to maintain the current
system rather than proactively replacing all Aldyl-A mainline pipe, but it should be considered that
current cost forecasts are based on cost of replacement and effects per leak.
While Avista's 20-year structured replacement program has proven to reduce the highest risk in
the early years of the program, the continuation of this structured replacement program is both
necessary and prudent to mitigating the remaining risks within the system, and to achieving
Avista's goal of operating and maintaining a safe and reliable natural gas distribution system.
6 FUTURE DATA COLLECTION
Future data collection focused on better documentation of failures to easily attribute these to
Aldyl-A pipe would make it possible to refine the Weibull sets and improve accuracy of model
predictions. A better understanding of how soil type affect failures will allow for targeted
replacement based upon likelihood of failure. Also, further refinement of per occurrence cost for
both planned and unplanned replacements and the associated effects will produce improvement
in cost forecasting.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 19 of 23

The below Availability Workbench models and excel files have been included in the attachment:
Aldyl-A_Mainline_20YrReplace_2018.awb
Aldyl-A_Mainline_Baseline_2018.awb
2018 Aldyl-A Model Update_Revenue_Requirement.xlsm

For any further information regarding this report please contact:

Scott Gloyna
ARMS Reliability Engineers
Phone: [phone]
Email: [e-mail]

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 20 of 23
APPENDIX A – MAINLINE ALDYL-A PI PE ANNUAL EXPENSES PER
YEAR BASED ON AVISTA REV ENUE REPLACEMENT CAL CULATOR
Year Baseline Model -
2013
20-Year Replacement –
2013
Baseline Model -
2018
20-Year Replacement -
2018
2018 $2,768,005 $17,358,435 $1,496,379 $61,501,245
2019 $1,660,312 $18,218,004 $2,623,336 $62,981,210
2020 $1,730,966 $17,973,699 $2,019,458 $64,442,060
2021 $3,499,201 $18,985,577 $1,234,137 $66,193,994
2022 $4,925,618 $19,501,977 $1,809,645 $67,881,054
2023 $4,880,447 $19,365,478 $1,838,287 $68,810,857
2024 $4,747,529 $19,606,495 $1,916,764 $70,036,504
2025 $5,123,168 $21,534,237 $3,981,535 $71,706,793
2026 $4,519,919 $21,076,111 $3,193,069 $73,034,193
2027 $6,249,062 $20,547,201 $3,650,847 $73,867,356
2028 $5,886,914 $21,629,593 $4,044,537 $75,643,774
2029 $8,341,754 $24,204,686 $2,556,338 $64,905,140
2030 $8,130,556 $21,657,261 $6,015,527 $60,997,106
2031 $7,091,184 $21,951,619 $5,887,637 $44,702,636
2032 $8,308,972 $22,528,242 $5,905,559 $28,442,059
2033 $11,558,254 $23,920,821 $4,407,520 $28,700,776
2034 $8,624,054 $54 $5,313,572 $29,052,089
2035 $14,231,303 $148 $5,343,060 $24,851,075
2036 $9,286,458 $92 $6,046,922 $
2037 $10,436,924 $66 $7,949,943 $
2038 $14,639,935 $127 $7,956,556 $
2039 $14,902,569 $112 $10,841,251 $
2040 $18,513,248 $99 $11,109,812 $
2041 $16,612,017 $109 $10,118,637 $
2042 $24,180,445 $197 $10,270,586 $
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 21 of 23
2043 $21,360,174 $194 $8,890,772 $
2044 $21,464,664 $186 $11,664,990 $
2045 $28,159,708 $175 $13,566,634 $
2046 $28,103,552 $192 $12,774,871 $
2047 $34,714,096 $253 $16,018,269 $
2048 $32,353,197 $246 $17,532,703 $
2049 $32,105,620 $201 $20,300,245 $
2050 $39,925,133 $289 $16,626,309 $
2051 $40,815,099 $331 $18,643,501 $
2052 $45,896,431 $408 $19,450,184 $
2053 $45,768,912 $326 $18,670,971 $
2054 $50,456,902 $349 $21,387,078 $
2055 $51,042,099 $369 $24,146,643 $
2056 $57,321,609 $340 $28,499,248 $
2057 $62,998,111 $399 $31,547,188 $
2058 $66,025,281 $397 $29,368,841 $
2059 $69,912,764 $369 $24,958,750 $
2060 $72,925,486 $445 $30,384,694 $
2061 $82,840,530 $558 $34,807,376 $
2062 $79,252,603 $425 $43,078,035 $
2063 $97,983,309 $619 $46,629,474 $
2064 $97,760,020 $613 $50,857,240 $
2065 $106,183,812 $613 $51,715,346 $
2066 $109,769,824 $666 $49,439,082 $
2067 $126,136,597 $762 $55,282,848 $
2068 $133,596,627 $802 $59,044,319 $
2069 $133,736,191 $853 $60,283,820 $
2070 $141,958,882 $762 $61,148,120 $
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 22 of 23
2071 $155,150,583 $976 $69,908,026 $
2072 $133,517,706 $772 $72,768,143 $
2073 $170,774,975 $1,063 $65,650,856 $
2074 $189,628,157 $1,051 $74,271,741 $
2075 $210,917,084 $1,322 $90,000,418 $
2076 $208,313,915 $1,054 $90,030,087 $
2077 $223,209,649 $1,244 $106,772,575 $
2078 $246,975,709 $1,449 $110,098,227 $
2079 $240,213,479 $1,516 $109,421,453 $
2080 $245,517,144 $1,516 $124,549,809 $
2081 $277,541,496 $1,748 $119,758,689 $
2082 $303,475,254 $1,780 $129,447,210 $
2083 $309,803,301 $1,978 $135,555,922 $
2084 $349,869,383 $2,326 $147,872,500 $
2085 $389,165,746 $2,388 $159,836,970 $
2086 $386,439,169 $2,187 $179,133,673 $
2087 $381,916,092 $2,237 $179,508,246 $
2088 $439,216,355 $2,535 $196,880,391 $

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 6, Page 23 of 23
Avista Utilities
Fleet Infrastructure Plan
2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 1 of 51
Thanks & Acknowledgements

Greg Loew – Photographs, Guidance, Information, Expertise & Leadership
Ken Lagerquist – Expertise and Information
Matthew Potter – Expertise and Information
Ken Copenhaver – Editing and Production

Lisa La Bolle – Editor and Author, Research, Drafting, Figures, Graphics, Production
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 2 of 51
Table of Contents
Thanks & Acknowledgements ...................................................................................................................... i
Introduction ................................................................................................................................................ 2
Fleet Management ...................................................................................................................................... 4
Data and Analytics ...................................................................................................................................... 9
Managing Costs ......................................................................................................................................... 17
Avista’s Fleet ............................................................................................................................................. 21
Avista’s Fleet Investments ........................................................................................................................ 33
Summary ................................................................................................................................................... 39
Appendix A: Assigned Vehicle Decision Matrix ........................................................................................ 40
Appendix B: Vehicle Use Policy ................................................................................................................. 41
Appendix C: Vehicle Classes ...................................................................................................................... 45
Appendix D: Fleet Glossary of Terms ........................................................................................................ 46

Table of Figures

Figure 1. Utilimarc’s Estimated Replacement Costs ...................................................................................................9
Figure 2. Avista’s Fleet Demographics For Recommended Replacement ................................................................ 10
Figure 3. Avista Total Fleet Costs ............................................................................................................................. 11
Figure 4. Costs for Parts Over Time .......................................................................................................................... 11
Figure 5. Avista Vehicles and Miles Per Gallon ......................................................................................................... 12
Figure 6. U.S. Gasoline & Diesel Prices Over Time .................................................................................................. 13
Figure 7. Fleet as Part of Avista Capital Budget ........................................................................................................ 16
Figure 8. Fleet Average Operating Costs Per Year ................................................................................................... 17
Figure 9. Fleet Primary Vehicles Operating Costs .................................................................................................... 18
Figure 10. Avista’s Complete Fleet Inventory (2020) ................................................................................................ 21
Figure 11. Avista’s Fleet Non-Vehicle Inventory ........................................................................................................ 22
Figure 12. Avista’s Vehicle Inventory ........................................................................................................................ 22
Figure 13. Fleet Related Expense Cost Trends (U.S.) .............................................................................................. 33
Figure 14. Fleet Budget and Actual Clearing Account Related Expenditures ............................................................ 33
Figure 15. Fleet O&M Clearing Account Historic Expenditures ................................................................................. 34
Figure 16. Fleet Capital Spending 2005-2019 ........................................................................................................... 34
Figure 18. Fleet Historic Capital Spending Since 2005 ............................................................................................. 35
Figure 17. Fleet Capital Budget as Part of Avista Total Capital Budget .................................................................... 35
Figure 19. Fleet Historic Capital Purchase Dollars By Location ................................................................................ 36
Figure 20. Fleet Capital Actuals and Budget ............................................................................................................. 36
Figure 21. Fleet Historic Primary Capital Expenditure Categories ............................................................................ 37
Figure 22. Utilimarc Recommended Replacements .................................................................................................. 37
Figure 23. Maintenance Costs Under Various Budget Scenarios ............................................................................. 38
Figure 24. Number of Units Past Recommended Lifecycle Under Various Budget Scenarios .................................. 38
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 3 of 51

Often the most visible representation of Avista to customers are the trucks they see on the road and in
their neighborhoods, bringing people and equipment needed to fix a problem or maintain equipment.
In fact, a 2018 Avista brand study found that customers are most likely to see and identify with Avista
via their bill (69%) and/or the Company’s vehicles
(65%).1 These vehicles and associated gear are an
essential part addressing customer needs and
performing the work required to be an effective
and efficient electric and gas utility. This report is
focused on Avista’s Fleet Management group,
those who provide and manage the vehicles and
related equipment that play a central role in
serving customers.

Avista’s Fleet Management team is responsible
for mission critical assets that have a direct and
significant impact on achieving corporate
objectives to provide good service to customers. Utility fleet management requires significant
expertise in managing diverse and often geographically dispersed, complex, specialized and
sophisticated assets. These fleet assets are wide ranging in type and nature, and can include pickup
trucks, service trucks, excavation equipment, backhoes, boom trucks, and a variety of portable and
specialty equipment. At Avista, Fleet’s area of responsibility also includes motor pools of shared
vehicles for corporate staff as well as specialized wheeled equipment
such as air compressors, welders, and generators for field crews.

Avista’s Fleet Group performs
maintenance, repairs, fueling,
purchasing and retiring of all these
assets, as well as a variety of other
tasks intended to uphold the safety
and dependability of the Company’s
vehicles and equipment. They also
perform complex and sophisticated
work designed to manage the entirety of the fleet and
maximize its value, availability, and service levels.

1 2018 Avista Brand Study,
https://avistacorp.sharepoint.com/:p:/s/SP/surveyresults/EeEzUOReBexJuJV_gFZ_AFUB8P14pMSE20MVoajcUJkbSg?rtime=2-Y98T0910g, Slide 16. It
should be noted that bills are an unpleasant association whereas vehicles are typically a pleasant association.
Introduction
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 4 of 51
Avista’s Fleet is very metrics focused. Using sophisticated asset management techniques, these
employees determine the appropriate lifecycle and amount of work needed to deliver readiness of
equipment for the least cost. They model costs and
benefits in order to maximize asset value. They
also use a complex industry model that compares
Avista’s assets and their performance with those
of other utilities across the U.S. This allows Fleet to
pinpoint problem areas before they can cause a
loss in service, determine if Avista is on track with
industry performance standards, and provides
information to make rapid and effective changes in
their management techniques as needed. This
technology helps the Fleet group deliver the most
effective fleet management possible. The team has a philosophy of continuous improvement in both
managing their resources and in providing everything Avista crews need to quickly and efficiently
address any kind of condition in the electric and gas systems. They are keenly aware that the faster the
Company can address problems, the better it is for customers, and that the vehicles and equipment
they manage are key to a rapid and effective response to issues and providing top level customer
service.

Fleet is also faced with the realities affecting
fleet operators nationwide: increasing
replacement costs for vehicles and equipment,
volatile fuel costs, budgetary pressures to
reduce costs, increasing regulatory burdens
related to issues like emissions, alternative
fuels, use of electric vehicles, more
sophisticated technology systems both in the
vehicles themselves and for use in managing
the fleet, and much more. This report
attempts to explain the work done by Avista’s
dedicated Fleet team, their methods and
priorities, tools and techniques, and the wide
range of equipment under their area of
responsibility. It defines the ways in which this
group is meeting the challenges faced by the
Company and by their peers. It further
describes their spending and budgets and the
ways they manage expenditures to get the
most value for the dollars they are allocated.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 5 of 51

The basic goal of Fleet Management at Avista is to manage all the assets under their control in a
manner that is sustainable and cost-effective while ensuring that the vehicles and equipment needed
to perform the work of the utility are available when needed.

In order to maximize safety, reliability and responsiveness to meet
customer needs including emergency outage restoration, vehicles and
equipment should be in optimal working condition. At Avista, 80% of the
maintenance is performed in-house. The Company believes that having
expertise available at primary work sites rather than depending upon
outside expertise helps control the cost and timeline of the work.2 The work
can get done when it needs to be done, rather than waiting on someone
else’s schedule. It also helps to ensure that safety remains a top priority
when working on these assets and as part of their functionality. Most importantly, Fleet believes that
one of their primary missions is to provide high availability levels, which specifically benefits Avista
customers. Avista maintenance shops currently provide an availability of around 95%.3 Their focus
provides the vehicles and equipment needed to quickly respond to customer requirements as well as
efficiently manage routine work
and maintenance and system
events such as outages and
equipment failure or damage.
When customers need Avista to
resolve an issue, the Company
wants to be there, as quickly as
possible and fully prepared for
whatever may be encountered.

This management strategy also
benefits Avista employees. Work
crews can spend hours at a time in
their vehicles. Crews are most
effective and efficient if the tools
and equipment they need are
right at hand. They value having
2 Outsourcing maintenance for utility vehicles is quite expensive. In Avista’s experience this typically costs between $75 and $125 per hour, as compared
to the total loaded labor cost for an Avista Journeyman Garage position at around $67 per hour (per Avista Human Resources data).
3 In the industry, typically new equipment is available 92–98% of the time, older equipment is usually available 80-85% of the time. Source: Lori Sullivan,
“3 Ways to Ensure Availability of Equipment,” May 3, 2016, https://www.fleetio.com/blog/3-ways-to-ensure-availability-of-equipment. Note that Avista’s
average unit age is almost exactly the same as the utility industry average unit age.
Fleet Management
Fleet Shop Locations
Mission Campus
Dollar Road
Clarkston
Coeur d’Alene
Colville
Pullman
Sandpoint
Avista crews work to free a customer vehicle that snagged distribution lines. They
use a digger derrick (left) to hold the lines up and a bucket truck (right) to place the
lineman into position.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 6 of 51
work vehicles that perform exactly as they want and expect. In effect, the trucks and the crews operate
as a unit. These vehicles are mobile work platforms that allow Avista crews to operate and maintain
the electric and gas systems. Having a reliable,
properly outfitted vehicle allows them the flexibility
of handling almost any type of task that may arise
during their working day or in emergency situations.

Properly maintained equipment also contributes to a
safe work environment. A poorly maintained vehicle
can fail at critical moments, potentially causing
accidents and putting lives in jeopardy.4 Avista
addresses potential fleet safety risks in three primary
ways: appropriate preventative maintenance on all Company vehicles and equipment, repairing
identified issues as quickly as possible, and requiring employees to walk all the way around a vehicle to
inspect it (and any specialized equipment associated with it) before it is driven or used. Many of
Avista’s Fleet vehicles also include specialized accessories like aerial platforms, diggers, cable spools,
etc. which are also regularly inspected by specially trained personnel to ensure safe working order.

Fleet also strives to provide clean, high quality vehicles. As mentioned earlier, Avista’s vehicles are
often the most powerful and visible positive symbols of Avista seen by customers. These vehicles are
ambassadors. Just as a dilapidated customer service center can turn customers away and make them
doubt the integrity of Company spending, clean professional-looking vehicles instill confidence in
Avista’s ability to handle any kind of situation. When a big Avista line truck rolls down the street while
customers are experiencing an outage, it is
reassuring to see a fully loaded
professional rig with a crew fully capable
of restoring the power quickly.

The Nuts and Bolts of
Managing a Diverse Fleet

So how does a small group of employees
manage such a large and diverse group of
assets? At Avista, Fleet mechanics and
servicemen provide nearly all the
mechanical and automotive related
services equipment, and keep that equipment
4 In fact, motor vehicle crashes are the leading cause of work-related deaths in the U.S. Source: “Motor Vehicle Safety at Work,” National Institute for
Occupational Safety and Health, https://www.cdc.gov/niosh/motorvehicle/default.html. According to the National Highway Transportation Safety
Administration, 20% of those accidents are due to poor maintenance of the vehicle. Carlos Berdejo, “Importance of Car Maintenance To Help Avoid Car
Accidents,” SAGAS Insurance Pros, https://sagazpro.com/blog/2017/9/18/importance-of-car-maintenance-to-help-avoid-car-accidents
Specialized equipment needed to set a pole – a backhoe, a
service truck, and a digger derrick.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 7 of 51
functioning as expected. These experts are available every weekday from 6:30 a.m. until midnight to
provide crews with adequate equipment, and to keep that equipment functioning as expected. This
extended availability ensures that the vehicles needed for each day’s work are ready to go when the
crews require them. After hours, crews have access to an emergency phone number to get whatever
help is needed. There are also a limited number of loaner trucks, trailers,
and a backhoe available if a crew’s regular vehicle is out of service. These
vehicles are stocked with a basic inventory of tools and supplies, which
allows work to continue even if a regular vehicle is undergoing repairs or
routine maintenance. Any requests for new or replacement vehicles or
accessories go through a rigorous review process, as Fleet manages their
portfolio using data and analytics, so these requests must be vetted with
specific requirements for adding to inventory. This process creates
awareness of the impact to existing vehicles, manpower requirements, and
budgets. It will be described in more detail in this report.

Avista’s service territory extends over more than 30,000 square miles of very diverse climates and
conditions, from steep mountain canyons to desert terrain, cities to farmland. Vehicles providing
customer service in Sandpoint face different challenges than those faced by Spokane-based crews or
those out in the Palouse. Different types of equipment are also required for different locations and
conditions. Avista’s Fleet group is responsible for ensuring that the right assets are in the right places,
always at the ready to provide any service required of them wherever they may reside. This is
especially true in emergency
situations such as windstorms, but
it is also a necessity for everyday
activities like dealing with minor
outages, replacing a failed pole,
installing new service, or
performing routine maintenance.

A Focus on Safety

Avista has a very strong
commitment to safety and safe
work practices. In keeping with
this philosophy, employees are always required to wear seatbelts on Company time (and strongly
encouraged to do so on their own time as well). Using mobile devices in a moving vehicle is prohibited
and use of alcohol or any controlled substances is strictly forbidden.5 All Avista drivers must follow safe
driving practices and obey all traffic regulations. A valid driver’s license or commercial driver’s license
(if applicable) are also required. In addition, as mentioned earlier, employees are required to perform a
walk around each time they move their Fleet vehicle to ensure that the area is safe and that there are
5 This includes prescribed medications that can affect driving capability.
Avista Fleet Crew
19 Journeymen Mechanics
5 Garage Foremen
4 Garage Servicemen
1 Coordinator
2 Drivers
1 Parts Specialist
2 Fleet Specialists
1 Fleet Analyst
2 Assistants
1 Manager
Left: Crane setting a pole on a steep hillside.
Below: Line truck faces conditions in Sandpoint
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 8 of 51
no impediments in the vicinity. Employees also have a rigorous safety protocol to follow, such as
testing the integrity of the bucket extension and safety gear before starting their shift and ensuring
that they have all of the safety equipment they need (like traffic safety cones, reflective vests and
flares) before they begin their work day.

Fleet also follows stringent safety protocols. All
aerial equipment is inspected on a strictly enforced
schedule. If a new aerial device (such as a boom,
bucket, or crane) is placed into service, they are
inspected after purchase by Fleet experts at
intervals of 30 days, 90 days, 180 days, and 365
days. Thereafter inspections take place every three
months. Fleet has two dedicated mechanics with
specialized training to perform these critical safety
and mechanical inspections. These inspectors are
mobile, so can provide onsite inspections across the service
territory, which reduces crew down time and fuel costs by eliminating transport of the Company’s
large trucks. Dates and records related to these inspections are maintained by Fleet, and decals and
forms are placed in each truck after inspection to keep truck operators informed of their vehicle’s
status.

Crash statistics indicate that a vehicle is 130 times more dangerous in backing up than in driving
forward.6 To help guard against these dangers, Avista installs backup alarms and cameras on every new
vehicle as part of their standard equipment.

About one in seven vehicle incidents occur in parking areas,7 so they are a natural place to focus on
reducing on-site incidents. Parking lots are filled with obstacles and hazards like moving vehicles and
pedestrians, often not paying attention the way they should. The Company encourages the use of
pedestrian crosswalks and promotes awareness of this issue for drivers of Avista vehicles and even
employee personal vehicles.

In addition, employees at all levels of the Company are encouraged to back into parking spaces, as this
provides better views of the surroundings when pulling out of a parking space, helping to avoid
oncoming traffic or potentially bumping into pedestrians. Backing into a parking space has two main
advantages: line of sight and maneuverability. Pulling out of a parking area frequently means
encountering blind zones created by the vehicles parked alongside which obstruct the driver’s vision. In
fact, about 20% of all accidents occur during parking,8 so the Company believes that this is a beneficial
focus area. Interestingly, studies have also found that the way employees’ park when they arrive at
6 Smith System “Advanced Backing,” https://www.drivedifferent.com/industry/utilities/
7 “Prevent Parking Lot Crashes,” State Farm Simple Insights, https://www.statefarm.com/simple-insights/auto-and-vehicles/prevent-parking-lot-crashes
8 “Parking Lot Accidents: Statistics, Causes, and Liability,” My Parking Sign, 2019, https://www.myparkingsign.com/blog/parking-lot-accidents/
Safety cones are set up around Avista
vehicles to protect the public
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 9 of 51
work can affect their safety behavior throughout the workday,9 which adds additional benefit. Avista
wishes to encourage safety as a habit and thus addresses this issue with all employees, especially those
responsible for operating Company fleet vehicles and equipment.10111213

To help specifically address driving related safety concerns, the
Company and the Fleet group provide the Smith System Driver
Improvement Course for employees. The Smith System is used
around the world to teach drivers to drive differently. Avista is
in good company utilizing this approach. More than half of the
Fortune 500 fleets use the Smith System for driver safety
training.14 The Smith method provides a more thoughtful
approach to driving, including the knowledge and tools to make
better decisions behind the wheel, which leads to a significant
return on investment in terms of crash and injury reduction,
maintenance savings, fuel savings, higher employee satisfaction
and, most importantly, saved lives.

As an example of the effectiveness of driver improvement
programs, Nationwide Insurance found that when they
implemented such a program, though miles driven increased by
19% that year, the organization’s preventable crashes
decreased by 53% and total motor vehicle loss costs went down
40%. Pike Industries, an asphalt paving company in Vermont,
has approximately 250 employees. These employees travel over 2 million miles each year hauling
construction equipment and materials as well as performing construction activities (many in highly
dangerous work zones) similar to what utility crews experience in their daily work. After implementing
a focused safety and driver training program like Smith, the number of significant roadway incidents
dropped to near zero, workers’ compensation claims for vehicle incidents dropped from a high of 73%
in total losses in one year to 2% the next. Vehicle property damage losses also followed this trend.15

This focused methodology is proven to increase safety. Although it is concentrated on Fleet vehicles
and equipment, it applies equally to driving while on company business or driving the family to the
movies. It is yet another piece of evidence that Avista cares about the safety and well-being of both
their own employees and that of the general public.
9 “4 Reasons Backing Into Parking Spaces Is Safer,” SafeStart, March 23, 2016, https://safestart.com/news/4-reasons-backing-parking-spaces-safer/
10 National Safety Council, “NHTSA: Motor Vehicle Crashes Have $871 Billion Impact,” June 11, 2014,
https://www.safetyandhealthmagazine.com/articles/10545-nhtsa-motor-vehicle-crashes-have-871-billion-impact
11 OSHA, “Guideline for Employers to Reduce Motor Vehicle Accidents,” https://www.osha.gov/Publications/motor_vehicle_guide.pdf
12 Ibid.
13 Ergoweb, “More Liberty Mutual Data on Workplace Safety,” September 26, 2001, https://ergoweb.com/more-liberty-mutual-data-on-workplace-safety/
also: OSHA, “Guideline for Employers to Reduce Motor Vehicle Accidents,” https://www.osha.gov/Publications/motor_vehicle_guide.pdf
14 Smith System, https://www.drivedifferent.com/. The Smith System reaches more than 250,000 drivers annually around the world.
15 Nationwide & Pike stories from the United States Department of Labor, OSHA, https://www.osha.gov/Publications/motor_vehicle_guide.html
• Motor vehicle crashes cost $871 billion in
societal and economic harm in the US
each year, more than $900 per person.10
• Motor vehicle crashes cost employers $60
billion annually in medical care, legal
expenses, property damage, and lost
productivity. They drive up the cost of
benefits such as workers’ compensation,
Social Security, and private health and
disability insurance. In addition, they
increase company overhead to
administer safety programs.11
• The average crash costs an employer
$16,500, increasing to $74,000 if there is
an injury, over $500,000 if there is a
fatality.12
• Liberty Mutual Insurance Company surveyed
business executives and found that 61%
believe their companies receive an ROI
of $3.00 or more for every $1.00 they
spent on improving workplace safety.13
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 10 of 51

So how does Fleet balance risk and investment
dollars based upon a limited budget while providing
vehicles, equipment, and tools that are always at the
ready to work as needed? One of the primary ways
they achieve this balance is by using statistical
analysis and modeling to determine how to optimize
the value of their assets. This data-focused approach
helps ensure that maintenance and associated costs
remain as flat and predictable as possible, keeping
capital outlays low and helping guarantee that the
customer gets the best possible value for the funding
they provide the Company to operate its fleet. Fleet
capital spending averages about 3% of Avista’s entire
capital budget.

Fleet uses a modeling system offered by Utilimarc, an industry recognized software and analytics
company, to help develop the most practical and cost-efficient decisions related to managing Avista’s
assets. The Utilimarc tools incorporate a wide spectrum of data to help develop lifecycle expectations,
costs, replacement schedules, etc. The broad base of this dataset includes utility industry benchmarks,
purchase and auction data, and nationwide vehicle information, providing visibility into how Avista
manages its fleet compared to industry peers. It also contains a robust dataset based on Avista’s own
fleet data, and uses this information to recommend vehicle replacement dates, develop actual and
projected costs, and even suggest staffing and expertise needed to manage the Company’s fleet most
effectively. It also considers annual expected ownership and maintenance costs for each vehicle and
equipment class.

Lifecycle Costs

As would be expected, fleet equipment experiences
increasing costs related to its operation as it ages.
Those costs are driven by the requirement of more
parts and more labor to keep a unit up and running as
it gets older. As the average age of a fleet increases,
more frequent breakdowns occur, along with a need
Utilimarc Software Insights:
❖Vehicle Safety
❖Fuel Expenditures
❖Maintenance Costs
❖Ownership Costs
❖Expenses Compared to Peers
❖Technician Productivity
❖Fleet Mix Makeup
❖Vehicle Utilization
❖Staffing Ratios
❖Vehicle Lifespan
❖Asset Expected Life Cycle Cost
❖Staff Wage Comparisons
❖Tracking Equipment Throughout
Asset Life
Data and Analytics

Figure 1. Utilimarc’s Estimated
Replacement Costs
Vehicle Type
Utilimarc Estimated
Replacement Cost
2019
Light Duty Bucket $169,000.00
Super HD Digger/Derrick/Derrick $392,909.00
Light Duty Service Truck $85,000.00
Heavy Duty Bucket $320,000.00
Light Duty Pickup $37,000.00
Stake Truck $95,000.00
Medium Duty Pickup $41,037.00
Super HD Bucket $292,000.00
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 11 of 51
for additional parts to keep
equipment in service, creating a
steady but accelerating trajectory
of costs and necessitating more
complex repairs and more
associated maintenance work
hours. Those increasing costs are
not just the burden of Fleet; the
people who depend upon these
vehicles and equipment will see
the impact in lost productivity and
downtime if a vehicle or key piece
of equipment is unavailable when
needed. The Utilimarc software
helps the Company determine
how to optimize the value of each
asset and when costs will begin to
exceed benefits, indicating that
replacement is needed. These analytics assist the Fleet professionals in determining how to globally
manage the fleet based on solid asset management practices.

For each class of vehicle in the Company’s fleet, Utilimarc determines what
lifecycle achieves the lowest cost of ownership and maintenance for an average
asset in that class over its lifetime.16 The model provides an approximately
three year vehicle replacement window, allowing flexibility when planning
replacement expenditures to reduce the effect on Fleet’s overall budget. The
Fleet Manager and Fleet Specialist closely monitor each vehicle, and once a
vehicle or piece of
equipment reaches its maximum predicted lifecycle
based on mileage, hours, and/or overall usage,
using the Utilimarc recommendations and their own
expertise, they determine if that item should be
retired from the fleet and if (and how) it should be
replaced. As shown in Figure 2, Fleet’s careful
management of their inventory is keeping nearly all
Avista’s vehicles within their recommended
lifecycle, helping keep maintenance costs and
capital budget requests low and steady.

16 It does this by calculating annualized total cost for each potential lifecycle. Annualized cost total is the sum of all ownership and maintenance costs a
unit incurs over the course of its life, divided by the number of years the unit is in service.
Avista’s average
vehicle age is
6.76 years
compared to the
industry average
of 6.4 years.
Figure 2. Avista’s Fleet Demographics For Recommended Replacement
Vehicle Type
Recommended
Replacement Age
(in Years)
Dump Truck 9-16
Bucket Truck 8-18
Digger Derrick 20
Pickup Truck 9-17
Service Truck 7-13
Stake Truck 18
Cranes 15-20
Passenger Vehicles 5-14
Excavators 11-21
Trailers 20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 12 of 51
Another consideration is required fleet
size.17 The Fleet group must allow for
vehicles to be out of service for
maintenance or other unforeseen
circumstances. Some assets are more
critical than others, especially those
that are specialized to particular tasks
or one-of-a-kind items, and this
criticality is also factored into Avista’s
maintenance strategies. Fleet must
manage their entire inventory to
ensure that assets are available when
needed under almost any
circumstance.

As shown in Figure 3, even with the
variability of costs they deal with, Fleet
has kept their costs fairly steady. The
blue bars, “ownership costs,” reflect
depreciation, interest costs, and
licensing. The yellow bars, “operating
costs,” include technician costs, parts,
outside vendors, and fuel expenses.
The green bars, “support costs,”
contain expenditures for support labor.
Just as an example of what this team
deals with, Figure 4 shows the cost of
parts over the same time period as shown in Figure 3 to provide an idea of the way just one factor
impacts the management of Fleet expenses.18

Labor Costs

On the employee side of the equation, the Utilimarc tool offers a wage comparison for fleet employee
classes, a recommended ratio of staff (and types of staff) to equipment, as well as statistics about
technician productivity. Avista’s technicians are routinely more efficient than industry averages. For
example, Avista’s average annual mechanic hours per vehicle in 2018 was 29.2 hours compared to the
industry average of 33.4 hours, indicating that Avista’s mechanics and fleet maintenance personnel are
17 For more information about this industry-wide, please see Dan Fellows, “How to Develop a Fleet Replacement Strategy,” EMSWorld, April 2016,
https://www.emsworld.com/article/12187528/how-to-develop-a-fleet-replacement-strategy
18 These costs for both Figure 3 and Figure 4 are based on Avista’s actual expenditures as tracked by the Utilimarc data system.
Figure 3. Avista Total Fleet Costs
Figure 4. Costs for Parts Over Time
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 13 of 51
highly efficient. In fact, according to Utilimarc, Avista is among the most efficient utilities in the nation
in maintaining their vehicles.

As mentioned earlier, Avista believes it is in the best
interests of Company operations to perform most
maintenance in-house versus outsourcing this critical
activity. Avista outsources approximately 11% of its
maintenance compared to the industry average of
21%.19 In-house maintenance allows having more
control over vehicle availability, but cost is also a very
important factor. Avista Fleet personnel have found that
outsourcing maintenance for utility vehicles typically
costs between $95 and $125 per hour, as compared to the total loaded labor cost for an Avista
Journeyman Garage position at around $67 per hour.20

Fuel Costs

Many fleet managers believe one of their greatest challenges is planning, budgeting, and mitigating the
variable cost of fuel. Fleet continually assesses expected fuel expenditures and fuel efficiency.
Obviously, the size of many of these vehicles makes this a challenge.

A combination of addressing driver
behavior (over speed, idling,
deceleration, acceleration, etc.),
selecting more fuel-efficient vehicles
when possible, adhering to
preventive maintenance schedules,
and monitoring fuel usage reports
can help, but these cost increases are
mostly beyond the control of drivers
and fleet managers. The cost is
exacerbated by the fact that many
Fleet vehicles are very large and do
not get high mileage. As an
example, some of the largest vehicles such as heavy-duty digger derricks only get about four miles per
gallon; the largest bucket trucks may only get around five miles per gallon. The majority of the
Company’s vehicles are bucket trucks, pickups, and service trucks. These large vehicles drag down the
Company average miles per gallon to about 9.3. Thus, fuel costs are always a big factor.

19 Utilimarc “2018 Fleet Executive Summary: Avista,” available upon request.
20 According to AAA most auto repair shops charge between $47 and $215 per hour for auto repair only, not specifically for the large vehicles Avista
utilizes. https://www.aaa.com/autorepair/articles/auto-repair-labor-rates-explained. Avista Journeyman Garage rate is from Avista Human Resources.
Figure 5. Avista Vehicles and Miles Per Gallon
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 14 of 51
In the United States gasoline and diesel
prices have varied widely over time, as
shown in Figure 6. These commodities
mirror the price of crude oil, which is
determined by worldwide supply and
demand. In addition, taxes add to the
price of gasoline. In Washington State,
the gasoline and diesel taxes are
currently 49.4¢ per gallon with an
added federal tax of 18.4¢ per gallon.
Only Pennsylvania has a higher state
gas tax.21 The amount of this tax is
subject to the decisions of the
Washington Legislature.

On a side note, regular drivers of Avista vehicles are given a fuel card so they can purchase fuel as they
need it without using their own credit cards and having to submit an expense report. This is another
way Fleet has streamlined operations.

Data Tracking

In the Fleet perspective, data is as much a key requirement in caring for assets as the mechanic and his
tool set. Vehicle maintenance records provide evidence of failures and the frequency of those events,
providing clues about certain vehicle brands or engine types that may be more costly or less reliable
than expected. Data provides identifiable patterns that can be incorporated into decision-making. It
also provides valuable information that helps continually improve Fleet’s asset management practices.
This is important, as poor maintenance
practices potentially equate to poor customer
service. If a key vehicle is not available when
needed, breaks down on the way to an
outage, or causes other delays due to
availability, the customer is poorly served. As
mentioned earlier, Fleet is highly focused on
availability. Data tracking and maintaining
good records helps them stay on top of this.
In addition, having a comprehensive set of
vehicle records is required by Federal law.22

21 “Washington State is Helping You See Exactly How Much You Pay in Gas Taxes,” November 17, 2017, https://q13fox.com/2017/11/23/washington-
state-is-helping-you-see-exactly-how-much-you-pay-in-gas-taxes/
22 Federal Motor Carrier Safety Administration, Department of Transportation, § 379.1. https://www.law.cornell.edu/cfr/text/49/379.1
Figure 6. U.S. Gasoline & Diesel Prices Over Time
A variety of vehicles may be needed to handle an outage or perform
a large installation or repair
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 15 of 51
Another tool Avista’s Fleet group uses to track
data is AssetWorks, an asset information
management system. Utilimarc provides
analysis, statistics, and recommendations on
aspects such as asset replacement schedules
and costs. AssetWorks is used to track an asset
throughout its entire life cycle. It has fully
integrated fleet, fuel, motor pool and GPS
management systems that Avista’s Fleet group
uses to keep track of their vehicle maintenance
records, track warranties, recalls, ensure that
aerial equipment is tested before it is used each
day, monitor usage, and handle work orders.

Avista’s Fleet also uses the Zonar software
system to track and document inspection records
and results. The Fleet team utilizes the reports generated by this system to help schedule preventative
maintenance and plan repairs efficiently. It is also an important part of the systems and documentation
required to remain in compliance with U.S. Department of Transportation regulations.23 The software
also has remote engine diagnostics to provide alerts before issues become serious.

Regulation

Regulatory considerations must also be
considered. Any truck or a truck/trailer
combination that weighs 10,001 pounds or
more must comply with Federal Motor Carrier
Safety Regulations regarding maintenance
and repair, required inspections, minimum
standard equipment, and safety gear
specifications. In addition, there are
regulations for trucks that include limits on
truck sizes, weights and cargo securement
rules.24

The Washington State Department of Transportation (WSDOT) also administers vehicle size and weight
state laws as well as administrative code and issuing the special permits needed to operate vehicles of
a size or weight greater than the legal maximum on state highways. They have regulations for
23 Federal Motor Carrier Safety Administration, https://www.fmcsa.dot.gov/regulations/title49/section/396.17 and
https://www.fmcsa.dot.gov/safety/passenger-safety/inspection-repair-and-maintenance-motor-carriers-passengers-part-396
24 “What Are the DOT Regulations for Trucks?” https://www.reference.com/government-politics/dot-regulations-trucks-1088fb70bee692c
The diversity of conditions across Avista’s service territory offers
its own challenges. As shown above, crews use a digger derrick to
hold up a pole in the river after the riverbank washed out.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 16 of 51
everything from mirrors to load securement, tires and axels,
accident reporting and even recording practices.25 The
Washington State Department of Licensing (DOL) administers
state laws and
administrative code
relating to the licensing
and regulation of
commercial vehicles and
their owner/operators.26
The Environmental Protection Agency mandates engine and fuel
emission controls for non-road diesel engines such as backhoes,
forklifts, generators, pumps, and compressors.27 They also have
requirements for all vehicle emissions.28 There are also national
commercial regulations related to everything from driver
background checks to vehicle maintenance records.29

Avista is required by the U.S. Department of Energy (DOE) to
acquire alternative fuel vehicles as a percentage of their annual light-duty vehicle acquisitions or,
instead, to use specific petroleum-reduction methods. The Company must file an annual report with
the DOE to show compliance.30 To maintain compliance with this directive, Fleet has actively added
Compressed Natural Gas (CNG) vehicles as appropriate as well as a CNG filling station on the Mission
Campus. They also purchase vehicles capable of
running on E85 fuel, which is a blend of gasoline
and ethanol.

There are also state regulations related to fuel
consumption, utilization practices, driver
monitoring, licensing, and reporting
requirements.31 Fleet must track all state, federal,
and local regulations associated with every asset
type; regulations which continually change over
time.
25 For a full description of WSDOT and National Commercial Vehicle Rules and Regulations, please see:
https://www.wsdot.wa.gov/publications/manuals/fulltext/M30-39/CVG.pdf and http://www.wsp.wa.gov/driver/commercial-vehicle-driver/commercial-vehicle-
laws/.
26 https://www.wsdot.wa.gov/publications/manuals/fulltext/M30-39/CVG.pdf
27 https://www.epa.gov/regulations-emissions-vehicles-and-engines/regulations-emissions-heavy-equipment-compression
28 https://www.epa.gov/emission-standards-reference-guide/epa-emission-standards-heavy-duty-highway-engines-and-vehicles
29 http://www.wsp.wa.gov/driver/commercial-vehicle-driver/commercial-vehicle-laws/
30 The Energy Policy Act of 1992 encourages the use of alternative fuels through both regulatory and voluntary activities. It requires fleets to acquire
alternative fuel vehicles including methanol, ethanol, and other alcohols; blends of 85% or more of alcohol with gasoline (E85); natural gas and liquid fuels
domestically produced from natural gas, electricity; biodiesel, etc. See: B100U.S. Department of Energy, “State & Alternative Fuel Provider Fleets,”
https://epact.energy.gov/ and https://afdc.energy.gov/laws/key_legislation#epact92
31 State of Washington Enterprise Services, https://des.wa.gov/services/travel-cars-parking/fleet-maintenance-service/fleet-management-best-practices
Federal Regulations:
• Training Requirements
• Drug & Alcohol Testing
• Commercial Driver’s License
• Insurance Requirements
• General Requirements
• Driver Files (Background Checks,
Qualifications, Records)
• Rules for Driving Commercial Motor
Vehicles
• Equipment Requirements
• Hours of Service
• Vehicle Maintenance Files
• Hazardous Materials Transport
State Regulations:
• Commercial Driver’s License
• Vehicle Inspection
• Size, Weight, Load
• Transportation of Hazardous
Materials
• Motor Vehicle Transporters
• Out-of-State and Interstate Permits
Compressed Natural Gas Fueling Station on Mission Campus
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 17 of 51
Benefits of a Data-Focused Approach

At Avista, the Fleet group utilizes analysis that is firmly focused upon the key goals of lowest cost of
ownership while providing highly reliable (and available) service. This analytical approach has proven
highly effective. In fact, the Fleet current monthly availability levels average 95%. At the same time,
Fleet capital expenditures have remained
very low and stable, as shown in Figure 7.

The Utilimarc, Assetworks, and Zonar
systems play a valuable role in helping
achieve the predictable, consistent
capital budget Fleet provides the
Company. In part, this is achieved by
accurately estimating forward needs and
smoothing out potential expenditure
“bubbles.” For example, if many vehicles
are concentrated within relatively few
vintages, the Company could experience
a sudden increase in parts and labor
costs, vehicle downtime, and technician
requirements simply due to a large group of vehicles aging at the same rate. Replacing a constant
number of units each year avoids this problem. Consequently, the Utilimarc model will occasionally
recommend replacing a unit before it reaches the end of its projected lifecycle, or it may let a unit run
beyond its lifecycle to maintain this balance.

All of the statistics, data, modeling, and specific information Fleet gathers, analyzes, and utilizes
provides a highly reliable budget estimate. It allows Fleet to replace equipment in a predictive manner,
with adequate staffing levels to meet expected workloads for maintenance and repair throughout the
budgeting period. It also gives the team plenty of heads-up time to prepare for when vehicles should
be repaired or retired and what new
equipment should be purchased. Thus, Fleet
budgets remain highly consistent across the
budgeting time frame, as their requests are
based upon metrics, analytics, and specific
expertise.
Figure 7. Fleet as Part of Avista Capital Budget
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 18 of 51
Managing Costs

Vehicles and equipment have fixed and variable costs associated with them. These costs fluctuate
depending upon the vehicle type, how it is used and driven, external factors such as weather and the
type of roads encountered, and market factors such as fuel costs. For example, there are higher fuel
and maintenance costs associated with driving in congested urban areas, in rugged terrain, or on rough
roads, as these types of conditions reduce fuel efficiency as well as add wear and tear and associated
costs. Interestingly, even things as simple as driving on a roadway with a lot of curves requires more
energy from the vehicle to counter the centrifugal force, resulting in more wear on the engine and the
tires.32 For the Fleet group, a variety of cost considerations and mission-critical activities are taken into
account when managing their assets and associated expenditures.

Maintenance and Operating Costs

Utility vehicles tend to be heavily used and often face adverse conditions such as steep topography,
extreme weather and off-road
situations. Normally they have more
moving parts and complex systems
associated with them and endure a
much higher level of use and workload
than typical vehicles. The cost of
ownership for Avista’s fleet vehicles
varies depending upon the vehicle
type, it’s usage, and the complexity of
its associated systems and equipment,
as shown in Figure 8.33

Age is also an important factor. Fleet
experts estimate that maintenance
costs for vehicles over six years of age
are about 2.75 times higher than the operating costs for vehicles less than three years old.34 Cost of
maintenance also increases if a vehicle pulls a trailer, experiences excessive idling, is operated by
multiple drivers, or experiences off-road, dusty, or extreme weather conditions. To add further
complexity, advanced vehicle technology, increased tire prices, and widespread use of engines that
require high-capacity and synthetic oils all add significant cost.35 Increasing shop overhead costs are
32 “Transportation Benefit-Cost Analysis,” http://bca.transportationeconomics.org/benefits/vehicle-operating-cost
33 These operating costs are based upon Utilimarc data specific to Avista.
34 Cristina Commendatore, “Vehicle Lifecycles vs. Maintenance Costs,” February 12, 2016, FleetOwner, https://www.fleetowner.com/maintenance/vehicle-
lifecycles-vs-maintenance-costs
35 Mike Antich, “Maintenance Costs Increase as Labor Rates Rise,” November 1, 2018, Automotive Fleet, https://www.automotive-fleet.com/318193/fleet-
maintenance-costs-increase-as-labor-rates-rise
Managing Costs

Figure 8. Fleet Average Operating Costs Per Year 33
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 19 of 51
also adding to maintenance costs as a greater number of sophisticated tools and software are needed
to service advanced vehicle systems. All of these factors must be tracked and factored into
maintenance strategies and practices, and the additional costs required must be managed.

There are basically two types of maintenance:
preventative and unscheduled. Preventative
maintenance is normally determined by
manufacturer recommendations based on
periodic mileage and/or calendar intervals.
Vehicles routinely undergo inspections, oil and
lubrication changes, cleaning, and replacement of
elements such as wiper blades and tires, as well
as repair of worn or broken parts. This keeps vehicles and equipment operating as expected and safe
for drivers and the public. This type of maintenance is preemptive in nature. It helps avoid potential
problems while maximizing vehicle availability and, if not performed regularly, will reduce vehicle
lifespan and ultimately increase costs.

At Avista, most scheduled maintenance for pickups, dump trucks, and service trucks is based on
mileage. Larger equipment such as digger derricks and bucket trucks, construction equipment, cranes
and the like are maintained based on the number of hours they have been in operation. Most other
equipment such as ATVs and UTVs, trailers, and equipment mounted on trailers like Genie lifts,
compressors, tensioners, etc. are maintained on a fixed schedule. For more details on maintenance
intervals, please see the Appendix C “Charge-Out Base.”

Unscheduled maintenance is also a factor. This may include things like wheel alignments or
replacement of parts that have been worn out, damaged or broken. These repairs must be made in a
timely manner in order to keep the fleet in a safe, operable condition. Avista minimizes these types of
unplanned outages with a robust and thorough
maintenance strategy. In addition, the Company
encourages equipment operators to report
when they notice something not working as it
should. Operators have knowledge of the
equipment and the expertise to identify issues
before they become serious simply by their
experience with the asset and their awareness.
As shown in Figure 9, Avista’s Fleet group has
been successful at keeping operating costs
consistent over time, and Avista’s costs are
typically lower than the industry average.

Figure 9. Fleet Primary Vehicles Operating Costs
Benefits of Staying Within Lifecycle:
•Reduction in Fleet Size
•Reduction in Maintenance Personnel
•Reduction in CO2 Emissions
•Improved Driver Morale
•Improved Company Image
•Improved Safety Across Fleet
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 20 of 51
Replacement

One of the largest expenses facing fleets is the cost of replacing vehicles and equipment. This is
especially true of utilities, because their vehicles tend to be very specific, and the types of equipment
they use such as aerial lifts, cranes, drillers, etc. are
specialized and expensive to replace. Replacement costs
for all types of vehicles have risen significantly in recent
years. For example, the average purchase price of light-
duty bucket trucks has been steadily increasing nearly
every year. The average cost was $92,571 in 2008, and by
2016 the average purchase price had risen to $148,974, a
61% increase.36 Heavy duty bucket truck average prices
are also up significantly, nearly 45% from 2006 to 2014.37
A single large bucket truck can now cost up to nearly
$400,000
depending upon how it is outfitted.38 The costs for this
type of equipment are expected to continue to increase
over time. It is also important to note that all capital,
ownership, and maintenance costs increase annually due
to inflation, which is currently 2% per year.39 All of these
increases have had a significant impact on Avista’s Fleet
budgets, though in the past years they have been mostly
held at bay due to creative and thoughtful choices in
managing the assets.

Types of Costs

Fleet managers must know all the costs associated with each vehicle and piece of equipment in order
to control and manage budgets and to determine when it is in the Company’s best interests to retire or
replace assets. There are two main cost classifications for Fleet operations: direct costs and indirect
costs. Direct costs are further differentiated by fixed and variable costs.

Direct Costs can be readily connected to a specific asset, for example, all the costs associated with a
particular pickup, or it can mean the portion of costs assigned to that asset. Avista utilizes the second
approach, assigning maintenance costs utilizing a “clearing account” in which these types of costs are
put into a single bucket and then apportioned as appropriate across the fleet. As an asset is
36 “Utilimarc: Bucket Truck Purchasing Costs Rose 61%,” Government Fleet, May 2, 2018, https://www.government-fleet.com/297221/utilimarc-bucket-
truck-purchasing-costs-rose-61
37 Fleet Benchmarking Study: “Heavy Duty Bucket Truck,” August 21, 2015, Utilimarc, https://utilimarc.com/fleet-benchmarking-study-heavy-duty-bucket-
truck/
38 KompareIt, “How Much Does a Bucket Truck Cost?” 2019, https://kompareit.com/business/constuction-equipment-cost-bucket-truck.html
39 Based on latest data available: April 2019, https://inflationdata.com/Inflation/Inflation_Rate/CurrentInflation.asp?reloaded=true
Vehicle Type Recommended
Replacement Age (in Years)
Dump Truck 9-12
Heavy Duty Bucket 13-17
Heavy Duty Pickup 6-9
Heavy Duty Service Truck 11-15
Light Duty Bucket 6-9
Light Duty Pickup 10-14
Light Duty Service Truck 10-14
Medium Duty Pickup 7-10
Stake Truck 11-14
Super Heavy Duty Bucket 6-9
Super Heavy Duty Bucket 11-15
Super Heavy Duty Digger/Derrick 11-15
Utilimarc Current Replacement Age Recommendations
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 21 of 51
maintained, the related expenses are put into this clearing account, then split between capital and
O&M based upon the type of vehicle and how it is used. Some assets are heavier on the capital side,
others require more O&M, thus Fleet allocates the expenditures in the clearing account in a meticulous
fashion, accounting for these factors and creating a monthly cost that is monitored and tracked.

Note that direct costs are fairly easily measured and are usually the focus of any cost reducing
measures. Things like maintenance costs, fuel, tires, insurance, repairs, and labor costs can be at least
somewhat influenced by management practices. Direct costs are broken into two primary categories:
fixed and variable.

Fixed Direct Costs are incurred by a vehicle whether it is being used or
not. These costs are typically computed based on time (such as cost
per month or year). Fixed costs may include expenditures to purchase
the vehicle, license it, and pay for elements like taxes, registration, and
other fees. Vehicles and equipment also need regular maintenance even if they are not used
frequently.

Variable Direct Costs are those related to the vehicle’s activity,
usually computed using the distance traveled or the hours of
operation. These kinds of costs include items such tires, fuel,
fluids, and wiper blades but also might include maintenance
and repairs as they arise from the asset’s use. Most direct costs
are in the variable category.

Indirect costs are expenses associated with maintaining the entire fleet and are not directly associated
with a particular piece of equipment but are still critical to its operation. Mechanics, their labor costs
and associated tools and equipment, work areas and buildings, as well as hardware and software
applications fall into this category. However, mechanic costs become direct costs during the time they
are actually working on a particular vehicle.

“Total cost of ownership” is another commonly used
description that includes both the purchase price of the
item plus the cost of operating it. Operations costs
usually include things like maintenance costs, downtime
costs, and driver costs. One of the proven ways to
reduce these costs and, at the same time, improve
productivity, is using Avista’s approach: centralized
administration and analytically determined practices.40

40 “Fleet Cost Management: Reducing Costs & Driving Productivity,” https://www.elementfleet.com/fleet-solutions/fleet-cost-management
Fixed Costs of
Owning a Vehicle
✓ Purchase Price
✓ Registration Fees
✓ Licensing Fees
✓ Scheduled Maintenance
Variable Costs of Owning
a Vehicle
✓ Fuel & Oil
✓ Tires
✓ Unscheduled Maintenance/Repairs
✓ Labor Costs
✓ Depreciation
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 22 of 51
Avista’s Fleet Assets

Utilities depend upon a wide variety of equipment in order
to serve customers. Beyond a diverse fleet of trucks and
other types of vehicles, they require the functionality and
usability of everything from boats to jack hammers,
snowplows to traffic control equipment. The Avista Fleet
team also maintains compressors, generators, welders, and
associated equipment needed to keep the utility
functioning every moment of every day.

Primary Fleet Resources

Avista’s fleet contains over 1300 different
vehicles and types of equipment across a
wide spectrum, all of which require
varying degrees of maintenance and
upkeep. Figure 10 shows some of the
primary types of vehicles and equipment
utilized at Avista. To clarify the categories
shown, please note that service trucks are
more specialized than pickup trucks, often
having additional associated equipment
such as water tanks, welders, cranes,
plows, buckets, lifters, tool storage, etc.
Excavation vehicles include ditch witches,
trenchers, vacuum units, front loaders,
bulldozers, and other earth-moving
equipment. The miscellaneous category
includes equipment such as generators.
Components include buckets, sanders,
jackhammers, reels, booms, and other
equipment fitted on vehicles. Figure 11
indicates Fleet’s non-vehicle outlays,
providing a glimpse into the other types of
equipment that must be purchased and
maintained to keep Avista operational and
serving customers effectively.

Avista’s Fleet

Figure 10. Avista’s Complete Fleet Inventory (2020)
Avista’s Primary Fleet Composition

• Pickup Trucks 39.0%
• Service Trucks 21.7%
• Bucket Trucks 14.9%
• Stake Trucks 8.7%
• Digger/Derricks 6.3%

These five vehicle classes make up 48.3% of
Avista’s total vehicle inventory.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 23 of 51
Avista’s Fleet Trucks

As mentioned earlier, trucks
make up a large percentage of
Avista’s fleet, about half in fact.
These vehicles tend to be highly
specialized and custom outfitted
to perform the work required of
them. They may be specially
insulated for high voltage work,
have heavy-duty frames and drive
trains, and components such as
drills, buckets, flatbeds, cranes
and more. Utility trucks are
considered commercial vehicles,
which means more government
regulations. They are also more
expensive and more complicated
to operate and maintain than
typical trucks.

At Avista these trucks are broken
into seven primary categories that
will be explained in more detail
below.
Figure 11. Avista’s Fleet Non-Vehicle Inventory
Figure 12. Avista’s Vehicle Inventory
Avista Truck Inventory 2020

Truck Type Count
Digger/Derrick 45
Dump Truck 39
Heavy Duty Bucket 35
Heavy Duty Pickup 34
Heavy Duty Service Truck 16
Light Duty Pickup 182
Light/Medium Duty Bucket 60
Light/Medium Service Truck 138
Medium Duty Pickup 61
Semi Truck 3
Stake Truck 62
Super Heavy Duty Bucket 11
Grand Total 686
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 24 of 51
Aerial Devices

All bucket trucks play a crucial role in the operation of a utility. Someone once said, “Ask a lineman
what they can’t live without in the field and you’ll find it’s a bucket truck.”41 A bucket truck has an
aerial work platform known as boom lift which is mounted on its back. The boom lift is outfitted with a
bucket that is designed for a person (or two people) to
stand in so they can perform work at heights, such as
power line maintenance or replacing streetlights. The
buckets are designed to be at about waist height for
safety, reducing the risk of someone falling out. These
trucks are also grounded so they protect against stray
current. Some bucket trucks can reach as high as 125 feet
in the air, though most have a range of 40 to 60 feet in
height. These trucks also have a significant amount of storage
onboard for tools and equipment. They are the safest and most
efficient way to convey linemen to the heights where they work
to manage, maintain, and improve the electric power grid.

As the primary power line service equipment, these vehicles are
on the road almost
constantly. Avista
currently has over
100 bucket trucks
of varying sizes
depending upon
the area
supported and
the tasks that
need to be
accomplished.
These vehicles
allow safe and
efficient access
to power lines
and critical
equipment and
are a mainstay in
the electric utility
world.
41 Amy Fischback, “Take A Look Inside A Lineman’s Bucket Truck,” T&D World, September 5, 2013, https://www.tdworld.com/electric-utility-
operations/take-look-inside-lineman-s-bucket-truck
Avista bucket trucks on the job
Using a variety of different sizes of bucket trucks and
support vehicles to repair storm damage in Kamiah
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 25 of 51
Service Trucks

Service trucks have specialized compartments to
carry a variety of tools and equipment, enabling
crews to perform routine jobs. These vehicles are
also equipped to deal with more complex
situations. In a power restoration effort, this level
of readiness can mean getting the lights on a lot faster.
Service trucks have been compared to having a doctor and a surgical suite in every ambulance, as they
enable the technicians to perform more multifaceted tasks onsite because their tools and equipment
are close at hand. Many of these trucks are equipped with four-wheel drive to allow them more
flexibility in accessing situations in rough terrain. In fact,
most of Avista’s service trucks are equipped with four-
wheel drive due to the topography and required access
across the service territory for both the gas and electric
sides of the business.42 Service trucks are highly versatile.
Even when
they do
not have
bucket attachments, they allow crews to have all the
tools they need with them at all times, with the
versatility in storage to allow these vehicles to be
customized to the needs of the day or the crew using
them.

Digger Derricks

This is a type of truck that is designed to dig
holes, hoist, hold, and set poles, and lift very
heavy equipment. It is a crane-like truck with a
huge boom on its back that has a heavy and
powerful hydraulic auger attached. These trucks
are designed for very heavy work including
digging holes, lifting and setting poles, turning in
screw anchors, lifting and setting transformers
or maneuvering other sizeable equipment into
place. The main components of a digger derrick
42 Utilimarc studies indicate that the difference in operating and maintenance expenses between 4x2 and 4x4 trucks has significantly narrowed, making it
easier to justify the extra upfront expense of a 4x4 based on the broader range of uses it offers. Sean Lyden, “The Rise of the 4x4 Service Truck,” Utility
Fleet Professional, September 2018, https://utilityfleetprofessional.com/departments/fleet-profiles/the-rise-of-the-4x4-service-truck
Avista electric service truck being charged
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 26 of 51
are the pedestal, the turntable, the boom, the
outriggers or stabilizers, the digger motor, the
auger and auger teeth, and the controls. From
digging to lifting, these trucks are designed to be
completely versatile. They are extremely large
due to the physical dimensions and heavy
weight of the attached pedestal and boom, as
well as the hydraulic motor, auger and
accessories. The digger derrick (or digger truck)
has a powerful engine to multiply the torque
and manage the hydraulic system that drives the
auger. The auger looks like a giant corkscrew and is used for drilling into the ground. Most can dig
holes about 18” in diameter and can dig a 10-foot deep hole in one “dip.” Their hydraulic augers dig
very quickly and efficiently. Many have cranes
as part of their attached equipment and can
perform heavy lifting as needed. Often these
trucks are used to both dig the hole, put the
pole in place, then hold it up as it is being set.
Sometimes they are used to hold a pole up to
keep lines in service when a pole has been hit
by a car and knocked down. They basically
serve as the pole until crews can make
necessary repairs. These machines are one of
the most used, most adaptable tools in line
work.

Stake Trucks
These are flat body trucks that have an open
platform rather than having a bed like a
traditional pickup. These platforms often have
sockets along the sides into which removable
posts or stakes can be placed to form a fence
around a load. These are an ideal solution for
hauling loads of various sizes, including loose
loads (for which the “fence” can be used). These
vehicles tend to have rugged and durable
construction so they can be used for a variety of
tasks, including hauling supplies and equipment,
spools of conductor or gas pipeline, or large bulky
items that will not fit easily into a pickup bed.
Many of Avista’s stake trucks have some tool
Using a digger derrick to set a pole
Stake truck (foreground) supporting a line crew
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 27 of 51
storage bins on board as well. These vehicles are used extensively by Avista’s electric and gas
distribution crews and are often important support vehicles on work sites.

Pickup Trucks

Pickups are used company-wide for a great variety of purposes.
These vehicles are used by both electric and gas crews for surveys,
inspections, maintenance activities, customer services such as meter
reading or trouble calls,
transporting crews and their
equipment, and so much
more. These trucks allow
engineers to inspect
transmission lines in rugged terrain and gas inspectors to access
pipelines in all areas. Pickups can carry tools and equipment
needed to perform repair or maintenance across the system,
including pull trailers with generators, spools of conductor or
gas pipe. Most have four-wheel drive to allow access to any
terrain.

Semi-Trucks

Semis are used by the Company to haul freight and large payloads. Avista’s small fleet of these trucks
provide support across the service territory.

Avista pickup takes a crew to work on
Clearwater Paper’s gas system
Avista has a small number
of semi-trucks for really big
jobs like hauling generator
parts to a power plant
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 28 of 51
Dump Trucks

Dump trucks are used across the service territory as well. Dump trucks are equipped with an open box
bed that is hinged at the rear and equipped with hydraulic lifts so the dump portion of the truck can be
lifted to allow whatever is inside to slide out. Some of these have
large capacity box beds, others have more of a fence surrounding
the cargo area. The Company has about 40 dump trucks of
various sizes and capacities, used for jobs such as hauling dirt
into and out of construction sites or hauling cargo.

Avista’s Other Fleet Vehicles & Equipment

Compressed Natural Gas

Compressed Natural Gas (CNG) capable vehicles are designed to be switchable to compressed natural
gas as their primary fuel if the situation allows it, while maintaining the flexibility of using gasoline or
diesel as a primary fuel if that is a better option.43 The
Company is adding CNG vehicles, primarily trucks, to the
fleet as it is feasible. At present, about 90 of Avista’s
fleet vehicles are related to CNG by being either CNG bi-
fuel vehicles or as the trailers that haul CNG to support
these vehicles.

43 Bi-Fuel or “switchable” vehicles give owners the best of both worlds. These vehicles can run on CNG as long as there is fuel in the CNG tank, then
switch to gasoline or diesel until the CNG tank is refilled.
Avista dump truck filled with bags of blankets,
hats, and mittens to distribute to low income
and homeless in Spokane County
Above: Compressed Natural Gas station at Mission Campus
Left: Avista natural gas-powered work truck
Avista natural gas-
powered dump truck
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 29 of 51
Snow Cats

These vehicles are invaluable assets in the rough country faced by some of Avista’s line crews. During
the winter, there are times when a line truck simply cannot access a downed powerline. Line crews
have had to use snow machines or, at times, had to snowshoe to a
situation to initiate repairs. Snow cats are especially helpful, as they
typically haul more
people and equipment
than a snowmobile
can.44 These handy
vehicles can also access
the Company’s
mountaintop meter
repeater stations
during winter months
for maintenance or
repair, or can be used to plow roads in remote areas for
crew accessibility.

Excavation Equipment

This type of equipment is used across the business as
well. Backhoes, excavators, bulldozers, loaders, skid-
steers, trenchers, drills, and components such as vacuum
systems all help perform routine utility work, flattening
areas for substation equipment, digging trenches to
install pipeline, laying underground electric cables or gas
lines,
excavating
areas to set
poles, building
roads to reach
transmission lines, snow removal, construction or demolition
activities, to name a few. These tools provide what Company
crews need for the construction aspect of their jobs,
whatever that may entail.

44 Snowmobiles can only accommodate one or two riders, who are exposed to the elements as they travel and have very little or no storage for supplies.
Snowcats are enclosed all-terrain vehicles that usually carry 2-6 people plus their gear.
Snowcat plows a path for line crews
Above: Some of the terrain Avista line crews face
(Pine Creek – Burke Thompson line)
Avista gas crew uses a backhoe to dig up and repair
a gas leak in Odessa
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 30 of 51
Puller-Tensioners

This is specialized equipment used to maintain a constant tension on power line/conductor as it is
being strung or taken down. A puller (winch) is set up at one end of the powerline section, and a
tensioner is set up at the other end. The reel of conductor is
placed behind the tensioner. The end of the pulling line is
attached to the conductor end after it has been threaded
through the tensioner. Then while the line is being strung, it
is held by this device under tension to keep it clear of the
ground and other obstructions that could cause damage.
These devices can pull out old conductor, wind it on a reel,
then release the new conductor under tension to keep it
under control as it is being placed on the poles. These
devices are also invaluable in holding conductor so it can be
spliced if it is
broken or
damaged.

Mobile Crane

This is a cable-controlled moveable crane with
a telescoping boom that has a hook on the end.
These cranes are used to lift and move very
heavy objects, aiding in construction projects
or helping crews extract, place, or maintain
large items like transformers or conductor
spools. Most of Avista’s mobile cranes are
attached to a truck, enabling them to quickly
and easily respond as needed as well as access
even relatively small areas.

ATV/UTV

All terrain or utility vehicles are a staple for a utility with a service territory as challenging as some of
Avista’s areas. All-terrain vehicles (ATVs) are small, typically meant for one or two people, and are very
nimble. These are more like motorcycles with four wheels – riders straddle them to ride. ATVs also
have a handlebar system for steering. Utility task (or terrain) vehicles (UTVs) are larger, often seating
Puller-Tensioner stringing a high voltage
transmission line
Avista service truck with a crane lifts a spool of cable
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 31 of 51
between two and five people, typically have covers on top and bench or bucket seats (i.e. are more
carlike) and sometimes small beds for hauling equipment. These units have steering wheels rather than
handlebars and are designed for rougher terrain than
a traditional four-wheel drive pickup. ATVs are usually
cheaper than UTVs but do not have the horsepower
and hauling capacity of a UTV. Avista utilizes both
types of vehicles for various applications. For
example, a transmission inspection engineer may use an ATV to access lines in
remote, heavily forested areas where roads cannot reach. Line crews might
use UTVs to access these same types of locations when they need the extra room to haul people and
equipment.

Trailers

These make up a high percentage of Fleet’s inventory,
as they are so
versatile. Avista
uses trailers of all
different shapes
and sizes,
covered and
flatbed, open and
ready to haul
whatever is
needed, or heavily customized to specific utility uses. Trailers haul everything from backhoes to
conductor reel, poles, CNG or water tanks, ATVs and UTVs, snow cats, boats, generators, various
excavation equipment, power plant parts, welders, compressors, and some even perform as mobile
substations. They are a versatile and invaluable part of Avista’s fleet inventory.

Left: ATV
Right: UTV
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 32 of 51
Miscellaneous Equipment

Vehicles and equipment such as fleet cars and SUVs, boats, and
backyard mobile equipment, as well as equipment like utility carts,
generators and welders are also managed by Avista Fleet.

Additional Equipment Needs

The Fleet Department has the capability of renting
specialized vehicles, specifically utility trucks or heavy
equipment, if they are needed for a particular project and
are not available within the Company’s inventory. If the
rental includes any aerial equipment such as lifts or
buckets, it must first be inspected by Fleet specialists to
ensure that it is in full compliance with Avista’s safety requirements before being released into use.

Fleet is also responsible for renting passenger vehicles or providing Company loaner cars for regular
employees. If an employee needs transportation for two days or less while on Company business,
Avista has three loaner cars available. Two of their loaner passenger vehicles are electric vehicles.45 If
the vehicles routinely provided are not adequate or if an
employee is traveling outside the area, the Company
has very specific requirements around employees
renting vehicles from an outside source. The Company
utilizes Enterprise Rent-a-Car for these situations.
Reservations for Enterprise vehicles must be made at
least 12 hours in advance. A few of their rental cars are
parked at the Mission Campus for convenience.

45 Of these two electric vehicles, one has a total trip limit of 50 miles so can only be used within Spokane, and the other can travel as far as 250 miles on
electric power if the batteries are fully charged.
Fleet provides electric vehicles for employee use in
conducting Company business
Crews must use a boat to access a pole that
crosses a river.
Using a small caterpillar to set a pole
on Palouse farmland to minimize
field damage
Using a boat to set flashboards
at Little Falls
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 33 of 51
If employees are traveling on Company business, they are
required to select the most economic and efficient
ground transportation method available (rental car or
public transportation, for example.) If they are renting a
vehicle, standard class is the default option unless there
are special considerations. This concept helps the
Company manage and control costs.

Employees are only eligible to drive a dedicated Company
vehicle if their manager determines that their job duties
and responsibilities
justify such use.46
Once approved,
drivers are required to
submit their mileage
records monthly for
every vehicle they
utilize without
exception. Company
vehicles may be driven
to an employee’s home only if that person is on call or
is a first responder for the Company.

Finally, employees are expected to be responsible for their vehicles. They must report anything they
notice that might indicate a mechanical problem, and they must try to keep their vehicles clean and
well organized, not only for efficiency in their work, but because these vehicles represent a physical
symbol of Avista to customers.
46 This is done through the use of an “Assigned Vehicle Decision Matrix” based on specific requirements and criteria such as driving over 18,000 miles per
year on Company business, having to carry tools or supplies that are not practical for a personal vehicle, daily trips to multiple locations, customer safety
and concern considerations (sometimes an identified Company vehicle provides necessary credibility), or if the employee faces extreme driving conditions
such as off road driving. See Appendix A for the Assigned Vehicle Decision Matrix.
Fleet Definitions
Fleet Vehicle – A Company owned, rented, or leased
vehicle available for employee use.
Assigned Vehicle – A fleet vehicle assigned to a
specific employee or work group on the basis of job
duties.
Fleet Pool Vehicle – A fleet vehicle that is available
to loan when an employee or department’s regular
vehicle is undergoing inspection, maintenance, or
repair.
Personal Vehicle Used for Business Purposes – Use
of an employee’s own vehicle to engage in Company
business. Eligible for mileage reimbursement.
Dollar Road Fleet Building (above) includes
multi-purpose lifts (below)
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 34 of 51

Operations & Maintenance (O&M) Expenditures

Avista’s Fleet group manages primary
Operations and Maintenance/non-
capital expenditures using a clearing
account, as mentioned earlier. All these
types of costs are put into one bucket
then dispersed monthly across the fleet
based on the type of vehicle or
equipment and how it is used.

These types of expenditures can vary
based on market conditions, such as
fuel, parts, tires, and even employee
pay. As shown in Figure 13, these types
of costs have gone up over time, mostly
at somewhat standard inflation levels, though fuel
costs have been widely variable. Even with often changeable costs in the market, Avista’s Fleet O&M
costs have stayed relatively stable and typically below budget, as shown in Figure 14, indicative of the
careful, analytical, measured approach this team takes to managing their people and equipment.47

The Fleet group manages a great variety of vehicles and devices and therefore must maintain a fairly
complex inventory. Beyond the expected vehicles and equipment, their non-capital expenses also
include elements such as
hardware and software, taxes,
permits and the like. This
category also includes
employee training and travel,
union contractual obligations,
parts and supplies for both
vehicles and supporting
equipment, tools, uniforms,
leases and rentals, costs of
regulations and compliance,
47 Data sources: Mechanics Pay: https://www.federalpay.org/employees/occupations/automotive-mechanic, Tire Prices:
https://www.statista.com/statistics/262841/us-producer-price-index-of-car-tires/, Car Parts: http://www.in2013dollars.com/Motor-vehicle-parts-and-
equipment/price-inflation, Gasoline: https://www.ceicdata.com/en/united-states/consumer-price/consumer-price-average-gasoline-unleaded-regular
Avista’s Fleet Investments

Figure 13. Fleet Related Expense Cost Trends (U.S.) 47
Figure 14. Fleet Budget and Actual Clearing Account Related Expenditures
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 35 of 51
and labor expenses related to maintenance and repair.

The largest expenditure categories
are fuel, employee pay, repairs,
parts, and tires, as shown in the
pie chart of Figure 15. This is all a
balancing act. Fuel, tires, parts,
and repair services are priced by
the market, though the team
attempts to shop around for the
best prices whenever possible.
Employee pay is another primary
category. Avista must stay
competitive with the industry to
attract and retain the high-
quality employees needed to
achieve the levels of availability the Company’s work crews need and expect. Avista is also bound by
union requirements.

Capital Expenditures

Fleet’s capital budget requests also tend to be stable, as shown by the “Average Budget” line in Figure
16, especially with the guidance of the Utilimarc software regarding replacements. Note that the blue
bars are actually approved, not requested, budgets, which can vary substantially. Over the last several
years, approximately $7 million per year is spent on vehicles and equipment, depending upon the
need. Some budget years are dramatically affected by the type of equipment required. As an example,
in 2009 and 2010 the Company purchased twelve digger derricks (some at nearly $400,000 each) and
twelve heavy duty bucket trucks, pushing their requested funding temporarily above typical levels, as
shown in Figure 16. However,
they plan for a stable budget
of about $7 million per year,
in part based on the historical
year average. Though this
team controls some of the
Company’s key assets, Fleet
capital expenditures typically
comprise only about 2%-3%
of the entire Avista budget, as
shown in Figure 17. This year
Figure 15. Fleet O&M Clearing Account Historic Expenditures
Figure 16. Fleet Capital Spending 2005-2019
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 36 of 51
they were allocated about $6.2
million for each of the next five years.

Many of Fleet’s capital purchases are
for trucks as mentioned previously.
However, many other components
are also required to perform routine
utility work. The historic capital
expenditures for these are shown in
Figure 18.

Figure 17. Fleet Capital Budget as Part of Avista Total Capital Budget
Figure 18. Fleet Historic Capital Spending Since 2005
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 37 of 51
As shown in Figure 19 on the right, Fleet is responsible for purchasing, maintaining, and retiring assets
across the service territory and in every
major area of the Company. Large
operations such as those in Spokane,
Pullman, Lewiston-Clarkston and Coeur
d’Alene by their natures require more
equipment, but Fleet also provides vehicles
and equipment for business units like
Generation, Substations, and the Meter
Shop.

Managing such a diverse fleet has wide
ranging yet and often subtle challenges as
well. Keeping a lid on costs, maximizing
value from contracts, forging strategic
partnerships, seizing opportunities
presented by new technology, preparing
for a zero-emission future, managing
occupational road risk, and dealing with
ever changing legal requirements and
regulations pose their own problems. In
addition, managing utility vehicles is more
complex than a handling a typical fleet of
cars and trucks. Utility vehicles are
normally highly customized for various
tasks, carry a lot of very expensive
equipment and people, and are required
to perform perfectly under every kind of
weather and road condition. They must
be safe for both employees and the
public. They must be protected against
theft and vandalism and be licensed and
permitted. Importantly, they must be
supported by adequate maintenance
staff and practices, a sufficient parts and
service inventory, and suitable storage
areas.

As shown in Figure 20, Avista’s Fleet
group has been highly successful at
keeping their costs low over the long
Figure 19. Fleet Historic Capital Purchase Dollars By Location
Figure 20. Fleet Capital Actuals and Budget
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 38 of 51
term, as indicated by the
trend line, staying at an
average of about $7 million
per year. This consistent
spending pattern is expected
to continue into the future.

Utilimarc recommends that
Avista spend about $8 million
per year in capital
replacements. This is based
upon replacing 91 of Avista’s
1,334 Fleet assets annually
over the next five years,
which is about 7% of the
existing fleet. Replacement, as
mentioned earlier, is based on asset management strategies related to maximizing lifecycle costs. This
data includes mileage, hours of operation, and general performance and costs. About 58% of these
planned replacements are for various trucks or digger derricks, the other 42% are components and
equipment such as welders, compressors, generators, lifts, excavation equipment, and the like.

Figure 22. Utilimarc Recommended Replacements
Figure 21. Fleet Historic Primary Capital Expenditure Categories
Bucket truck and Genie lift allow crews
access to transmission tower at Noxon
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 39 of 51
Fleet has managed their budgets so effectively that the Company has been able to maintain the
recommended industry average age for their fleet vehicles, leading to controlled maintenance costs
over time, as shown by the green line
in Figure 23 (note that this budget
amount includes inflation). Utilimarc
recommends a replacement budget
based primarily on lifecycle costs. If
more assets are being used beyond
their recommended life, it will
inevitably lead to more breakdowns
or failures as the asset ages. As
shown in Figure 24, the Company is
driving toward a goal of having all
Avista’s Fleet assets at or near their
expected life to keep costs low and
service availability as high as
possible. As mentioned earlier, the typical
budget for Fleet is about $7 million. This year the Capital Planning Group allocated $6.2 million per
year for the next five years.

Figure 24. Number of Units Past Recommended
Lifecycle Under Various Budget Scenarios
Figure 23. Maintenance Costs Under Various Budget Scenarios
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 40 of 51

Avista’s Fleet ensures that every vehicle and piece of equipment meets operators’ needs and
expectations. The information shared in this report is evidence of the Fleet team’s commitment to
providing the efficiency, cost effectiveness, safety, reliability, and availability around equipment that is
critical to keeping Avista’s energy delivery system operating. Fleet performance is enabled and proven
by data that that has been collected consistently for over a decade. This information allows the Fleet
team to make value driven, data focused decisions for each business unit and for the Company. Data
and analytics play a key role, but there are many more factors.

When it comes to safety, the Fleet team is constantly working to ensure that they are rolling out the
latest safety information and technology to all vehicle and equipment users. Safety systems are in
place for all Fleet equipment. The Fleet team works closely with OSHA as well as state regulators to
make sure that all safety equipment, technologies and practices meet regulatory requirements. They
collaborate with vehicle ergonomic experts to reduce any chance of injury. As an example, due to
advanced safety systems, Avista crews now have a new and safer way to handle energized conductors
on the job site, reducing outage duration and making maintenance or repair faster and more efficient,
while at the same time protecting employees from harm. As another example, at the end of 2019 Fleet
is deploying the first Avista heavy duty vehicle with advanced safety features, including collision
avoidance systems. Efforts such as these have a positive impact on reducing long term injury rates for
field workers and making work areas safer for the general public as well.

Storms and the related outages have severely tested Avista’s fleet in recent years. 95% availability
sounds impressive, but what does it mean when it really counts? Time and experience prove that
Fleet’s performance does not disappoint. The Company’s largest outage event, the November 2015
windstorm, pushed Fleet equipment to the edge. In a ten-day period, almost a quarter of a years’
worth of fuel was consumed. Equipment was utilized 24 hours a day, non-stop, but there was not a
single catastrophic failure of equipment. Small repairs and maintenance were completed during rest
periods to maximize crew and equipment availability. Avista’s Emergency Operations Plan incidence
results consistently show that Fleet performs at a very high level during major impact events. It is
clearly evident that Fleet programs, data driven analytics, and investment strategies are working to
provide Avista with exactly what is needed to perform work as a utility under any condition.

Value is another important element provided by Fleet. As reported earlier in this report, Fleet
performance and results are typically in the first and second quartile compared to industry data,
proving that Avista’s Fleet team manages the Company’s key work resources wisely. Expenditures have
stayed level even though some costs change constantly. This is due to careful and thoughtful Fleet
management and choices. Fleet delivers what is needed to perform work for customers and provide
new and innovative safety solutions, never losing sight of reliability and availability. Fleet’s
performance is proven to be outstanding. This dedicated group of people work hard every day to
ensure success in all the key areas necessary for operating Avista’s electric and gas systems.
Summary

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 41 of 51

Assigned Vehicle Decision Matrix

Is this add request as follows:
All other requests please answer the following
questions in section one.
A field position that requires a vehicle as a part of
the positions tool (i.e. bucket truck, stake trucks,
tester van, service truck, etc.)?
If YES skip to section 2, if NO see next column

Section 1

Section 2
YES NO
1. Manager to complete business case
with financial analysis - submit to
Fleet.
2. Manager to complete a VLC request
form in conjunction with vehicle
capital specialist.
3. Submit VLC for Officer approval.
4. Coordinate order and delivery with
Fleet Services.
5. Provide an Assigned Vehicle to the
employee.
• Employee will submit an Expense
Report with business mileage for
reimbursement at the IRS-approved
rate per business mile.
OR
• Use of a pool vehicle
OR
• Rent a vehicle (Contact
Fleet Coordinator)

Manager Evaluation:
Should Avista provide the employee an Assigned Vehicle for business purposes? (Please answer the
following questions for clarification.)
•Will the annual mileage in exceed 18,000 miles
OR
•Do the job duties regularly require necessary tools, materials or equipment or supplies that are
not practical to carry or load daily into a personal vehicle?
(Regular usage is defined as 3-5 times per week)
OR
•Do the conditions under which a vehicle is frequently used pose an unreasonable risk of
damage or excessive wear to an employee’s personal vehicle, such as driving off road or
parking in state right of ways where minimum traffic awareness measures must be taken?
(Frequently is defined as at least 1 or more times per month)
OR
•Does the job function require daily trips to multiple locations and a vehicle with
required Company identification?
Appendix A: Assigned Vehicle Decision Matrix
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 42 of 51

Revised January 2018

Purpose
The purpose of this Vehicle Use Policy (“Policy”) is to ensure the safety of employees and the public while
driving during the course of doing business; provide employees with expectations for the use of company-
owned and rented vehicles; provide expectations on the use of personal vehicles for company business; and
ensure compliance with all federal, state, city and local motor vehicle regulations.

Policy Statement
Avista provides company-owned or rented vehicles for employees whose job duties and responsibilities
necessitate driving. Driving any vehicle carries significant risk of injury. Avista is dedicated to ensuring the safety
of its employees, and therefore has developed guidelines for the assignment, use, operation and maintenance
of fleet vehicles and the use of personal vehicles while being used for business. This Policy supplements Part 4 of
Avista’s Incident Prevention Manual, which is incorporated and referenced herein.

Policy Definitions
Fleet Vehicle – A Company-owned, rented, or leased vehicle available for employee use. A Fleet Vehicle is
designated as either an Assigned Vehicle or a Fleet Pool Vehicle.
Assigned Vehicle – A Fleet Vehicle that is assigned to an employee or to a department on the basis of a specific
department’s or employee’s job duties and reserved for day-to-day use.
Fleet Pool Vehicle – A Fleet Vehicle assigned to and issued by Fleet Services as a loaner when a department’s
Assigned Vehicle has been scheduled for inspection, maintenance or repair.
Personal Vehicle Used for Business Purposes – The use of a personal vehicle during the course of business that
would qualify for mileage reimbursement under Avista’s Travel & Expense Reimbursement Guidelines.

Scope and Applicability
The vehicle use policy applies to all employees when using fleet, assigned or fleet pool vehicles as defined
above, as well as personal vehicles while being used for business. The employee’s record of acknowledgement
will be kept in Avista Learning Network and will be acknowledged annually.

The policy is broken into two sections: Personal Vehicles Used for Company Business and Company Owned
Vehicles. Since any employee may find it necessary to travel outside the office for business reasons, this policy
shall be reviewed by all employees. The Company Owned Vehicles Section is for employees who may as a course
of their duties operate a company-owned vehicle as defined above.

Appendix B: Vehicle Use Policy
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 43 of 51
Personal Vehicles Used For Company Business
Vehicle Safety Rules:

• Employee must wear a safety belt at all times the vehicle is in motion and must ensure that all occupants do the same.

• Employee shall follow Avista’s Mobile Device Policy, which limits the use of mobile devices (including hands free) in personal vehicles on
company business. The use of a mobile device shall happen only when the vehicle is pulled to side of the road and legally parked.

• The use of alcohol and controlled substances prior to and during operation of any vehicle is strictly prohibited.

• Vehicles shall be operated within the legal speed limit at all times and at lower speed where conditions warrant.

• Employee shall take steps to ensure the security of Avista-owned property that is being transported.

• Employee must follow generally accepted safe driving practices and obey traffic regulations for the state, city and county in which they are
operating the vehicle.

• Employee shall ensure that their vehicle is in safe operating order.
Reporting Requirements:

• Before driving a personal vehicle for company business, employee must notify his or her manager if there is a change in status to their
driver’s license for any reason, including but not limited to, revocation, restriction or permission.

• Employee will be solely responsible for payment and any defense of citations received while operating their personal vehicle during the
course of business.

• If an accident occurs during the use of an employee’s personal vehicle for business purposes, they shall notify their manager to complete
an Avista Report of Accident Form.
Company Owned Vehicles
Eligibility:

Employees are eligible for an Assigned Vehicle if their manager determines their job duties and responsibilities satisfy the criteria set
forth in the “Assigned Vehicle Decision Matrix” (See Appendix A.) Managers will evaluate and determine an employee’s eligibility and
submit the necessary information to Fleet Services.

Once issued an Assigned Vehicle, employees are required to maintain a valid and current driver’s license for the type of Fleet Vehicle
they are operating and comply with all rules and requirements in this policy. An employee’s failure to comply with this policy will result
in loss of vehicle privileges and/or discipline up to and including termination.
General Requirements:

• Employee shall not use Fleet Vehicles for non-business reasons, except for “de minimis” use (such as a short stop for an errand on the
way between a business purpose and the employee's work location or home).

• Pets are not allowed to ride in Fleet Vehicles including the truck bed.

• Smoking and vaping are strictly prohibited in Fleet Vehicles.

• Absolutely no hitchhikers are allowed in Fleet Vehicles.

• Towing of any type of employee owned recreational equipment is prohibited.
Passengers:

During the course of business employees may need to transport passengers who are not employees of Avista. Passengers must always
use a seatbelt. If the vehicle is outfitted with a laptop mount, the driver and passenger must take precaution that the device and mount
is not in the airbag deployment zone. The device and mount should be placed in the center of the cab.

In limited and non-recurring instances employees may need to provide transportation for a family member in a company owned or
rented vehicle while on call, commuting or traveling for business purposes. If this is needed the employee should notify their manager.
If there is a need outside of the previous definition the manager must contact the Fleet Manager for guidance.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 44 of 51

Company Owned Vehicles (cont.)
Vehicle Safety Rules:

• Employee must wear a safety belt at all times the vehicle is in motion and must ensure that all occupants do the same.

• Employee shall follow Avista’s Mobile Device Policy, which limits the use of mobile devices (including hands free) in both company
owned and leased vehicles and personal vehicles on company business. The use of a mobile device shall happen only when the vehicle is
pulled to side of the road and legally parked. The full policy can be found in the Avista Incident and Prevention Manual section 4.

• The use of alcohol and controlled substances prior to and during operation of any vehicle is strictly prohibited.

• Vehicles shall be operated within the legal speed limit at all times and at lower speed where conditions warrant.

• Employee is responsible for the security of vehicles. Employee should avoid leaving any items of value in vehicles wherever possible.

• Employee must follow generally accepted safe driving practices and obey traffic regulations for the state, city and county in which they
are operating the vehicle.
Employee Reporting Requirements:

• Employee must turn in vehicle mileage, no Avista vehicle is exempt. An Operations employee using Maximo for time keeping will submit
mileage as a part of their daily time reporting. All other employees must turn in their mileage sheets on a monthly basis to Utility Plant
Accounting.

• Employee must notify his or her manager immediately if there is a change in status to their driver’s license for any reason, including but
not limited to, revocation, restriction or permission. Managers and Fleet Services reserve the right to review any Employee’s motor
vehicle records for any reason at any time.

• Employee must notify his or her manager of any inspections and citation(s) received while operating a Fleet Vehicle.

• Employee will be solely responsible for payment and any defense of such citations.
Fueling Fleet Vehicles:

• Employees who are provided with a Fuel-Only card must use it to fuel Fleet Vehicles at off-site retail stations. The assignment and
distribution of off-site fueling cards is managed by Fleet Services. When fueling, employees are expected to enter accurate data,
including fuel pump number, vehicle number, current odometer reading, and engine hours (if applicable).

• Employee must use the appropriate gasoline for each Fleet Vehicle. Fleet Vehicles that utilize regular unleaded gasoline do not require
“Unleaded Plus” or “Unleaded Supreme” gasoline. Use of premium fuel is only for small tools that require fuel with no ethanol. If the
vehicle is an alternative/dual fuel vehicle then the alternative fuel should be used when available.

• Employee must not keep fuel card instructions and codes with their assigned fuel card to prevent unauthorized persons from fueling.
Fleet Vehicle Maintenance & Inspection:

• Employees shall perform a “walk around vehicle” inspection each day prior to moving the Fleet Vehicle to ensure it is safe. This
inspection shall be completed after required paperwork or data entry and must always be the last task completed prior to moving the
Fleet Vehicle.

• Employees must inform Fleet Services of any Fleet Vehicle maintenance needs or safety problem.

• Any Fleet Vehicle that does not meet safe operating conditions shall be immediately removed from service; its use will be prohibited
until unsafe conditions have been corrected and re-inspected before being placed in service again. Employees should use “lock out- tag
out” procedure for unsafe vehicles.

• Fleet Vehicles must be cleaned (interior and exterior) regularly to help maintain a good appearance.

• Employees must maintain the visible logo and equipment number on the Fleet Vehicle. Employees must report to Fleet Services if the
Fleet Vehicle’s logo or equipment number becomes less visible or otherwise less noticeable to others. Fleet Vehicles greater than 10,000
pounds Gross Vehicle Weight Rating (GVWR) are also required to display USDOT number.

• Employees must not modify or add accessories to any Fleet Vehicles unless the modifications or accessories are authorized and/or
coordinated through his/her manager and Fleet Services. Window tinting will not be authorized.

• Employee must not decorate any Fleet Vehicle unless authorized by his/her manager and Fleet Services. Decorations include but are not
limited to bumper stickers, window clings, antennae balls and advertisements.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 45 of 51

Company Owned Vehicles (cont.)
Vehicle Accidents:

All employees must follow the requirements in the most recent Vehicle Accident Handbook, which is kept with each Fleet Vehicle and
includes a Vehicle Accident Report form. The current Vehicle Accident Handbook can be accessed through the Safety Department Sharepoint
site or at this link: Vehicle Accident Handbook.

There will be an incident assessment conducted on each accident to determine cause and how the accident could have been prevented.
Employee will fully cooperate with such assessment. Upon conclusion of the review, Employee will be notified of the results of the
assessment.
Policy Responsibilities
Each Department Manager Responsibilities

• Understanding, communicating the Policy.

• Requesting Fleet Vehicles for eligible employees using the Assigned Vehicle Decision Matrix Notifying Fleet Services when a vehicle needs
to be acquired, reassigned or the status of an employee with an Assigned Vehicle has changed. Reasons for reassignment include job change
or transfer, long term disability, termination, relocation, change to driver’s license status, leave of absence or retirement.

• Ensuring that employee possesses a valid driver’s license appropriate for the type of vehicle being operated in accordance with Part 4
(Vehicle and Equipment Operation) of the Avista Incident Prevention Manual.

• Approving exceptions to allow employees to drive vehicles home in certain cases.
Fleet Services Responsibilities

• Maintaining a database of all Fleet Vehicles, assigned departments, and assigned employees Acquiring and disposing of Fleet Vehicles.

• Ensure proper care of Fleet Vehicles through maintenance and inspections.

• Maintaining the Assigned Vehicle Decision Matrix.

• Facilitating and coordinating efforts with department management to train employees regarding this Policy and any changes.

• Annual review of the policy, updating as needed.

• Maintaining a database of all Fleet Vehicles, assigned departments, and assigned employees Acquiring and disposing of Fleet Vehicles.

• Ensure proper care of Fleet Vehicles through maintenance and inspections.

• Maintaining the Assigned Vehicle Decision Matrix.

• Facilitating and coordinating efforts with department management to train employees regarding this Policy and any changes.

• Annual review of the policy, updating as needed.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 46 of 51

Vehicle Class Description Gross Vehicle Weight Rating Charge Out Base
32 Passenger Cars Mileage
46 4 x 4 pickups/SUV's, 1w/single rear wheels 6,000 GVWR or less Mileage
47 4 x 2 Service trucks, Cargo Vans, w/single rear wheels 16,000 GVWR or less Mileage
48 4 x 4 Service trucks/Cargo Vans, w/single rear wheels 16,000 GVWR or less Mileage
56 Service trucks, high cube vans, flat beds, dumps, w/dual rear wheels under 26,000 GVWR Mileage
57 Dump & Flat Beds (Over 26,000 GVWR)Mileage
58 Digger derricks, Service body trucks, boom or crane trucks, etc., w/single rear axles Over 26,000 GVWR Hours
65 Road Tractors Mileage
66 Digger Derricks, cranes & knuckle booms, w/Tandem Rear Axles Over 33,000 GVWR Hours
67 Bucket trucks (45 ft and under)Hours
68 Bucket trucks (Over 45 ft)Hours
76 Off road construction equipment Hours
77 ATV's, UTVs, snowmobiles fixed monthly rate
78 Snow Cats Hours
79 All terrain aerial equipment, cranes, manlifts, and back yard booms Hours
85 All other equipment and trailers with mounted equipment, including: Genie lifts,fixed monthly rate
welders, vacuum units, compressors, line tensioners, stringing equipment,
boats, air compressors, pipe trailers, generators, drilling equipment
86 Equipment Trailers, flatbed, and box/van only * No Mounted Equipment *10,000 GVWR and under fixed monthly rate
87 Equipment Trailers, flatbed, and box/van only * No Mounted Equipment *10,001 GVWR and over fixed monthly rate
Appendix C: Vehicle Classes
Avista Class 46 Vehicle
Left & Above: Avista Class 56 Vehicles
Avista Class 48 Vehicle Avista Class 67 Vehicle
Above: Avista Class 68 Vehicle
Above & Right: Avista Class 66 Vehicles
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 47 of 51

Aerial Device: Sometimes called a boom truck or cherry picker, this is a
vehicle with a long foldable arm (also called a
boom) that can be used to lift workers to a
height. The boom is typically mounted to a
truck bed. If the arm is short and compact and
is primarily used to lift items off the truck bed,
it is called a “knuckle boom.” If when folded it
is the length of the truck bed, it is called a “trolley boom.”

Alternative Fuel Vehicles: This category includes electric hybrid vehicles and those that use
compressed natural gas (CNG), biodiesel, or electrically charged batteries.

Backhoe: This is a piece of excavating equipment that consists of a digging bucket on one end of a two-
part articulating arm, usually mounted on the back of
a tractor or front loader. The section of the arm
closest to the vehicle is called the boom, while the
section the bucket is attached to is called the dipper.

Backup Alarm: These are activated when a vehicle
goes into reverse, notifying anyone behind that
vehicle that it will be backing up, providing more
safety for anyone who may be behind the vehicle.

Benchmarking: This means comparing performance from one
organization with that of other organizations, measured according to
specified definitions and standards so that the data is directly
comparable. In the Fleet world, this usually focuses on fuel usage, service
delivery, maintenance practices, life cycles, costs, etc.

Compressed Natural Gas (CNG): This is natural gas, primarily methane,
which is compressed to less than 1% of the volume it takes up in its
natural state, allowing it to be stored in higher volumes than standard
natural gas and be more easily transported. CNG burns cleaner than
gasoline, reducing emissions up to 80%. It is also abundant and
inexpensive compared to gasoline. However, it requires significant modifications in order to be utilized
in vehicles and must have adequate storage space and filling stations, which are currently not widely
available.48
48 “Advantages and Disadvantages of Natural Gas,” Conserve Energy Future, https://www.conserve-energy-future.com/advantages-and-disadvantages-of-
natural-gas.php
CNG Station on Mission Campus
Appendix D: Fleet Glossary of Terms

Knuckle Boom
Trolley Boom
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 48 of 51
Cost Benefit Analysis: This means looking at the costs and benefits associated with a particular course
of action or choice of actions. For example, the cost of purchasing a larger bucket truck versus the
potential risk of not being able to reach some of the equipment that may need to be repaired.

Digger Derrick: A utility truck also called a digger truck or a pole truck, this vehicle is equipped with an
auger to drill holes for setting poles. These very heavy-duty trucks can also pull, hold poles or lines in
place, haul thousands of pounds in a single load,
and lift extremely heavy items.

Direct Costs can be readily connected to a specific
asset, for example, all the costs associated with a
particular pickup, or it can mean the portion of
costs assigned to that asset such as Fleet’s tools.

Fit for Purpose: A vehicle or piece of equipment
that is designed specifically for the purpose it
serves.

Fleet Register: A database containing all the
details about the vehicles and equipment in the Company’s fleet.

Fleet Maintenance Records: These are details kept about each vehicle, including vehicle description,
year of purchase and cost, mileage, fuel type, safety inspection results, routine maintenance reports,
vehicle defect information, and repair records.

Fixed Costs are incurred by a vehicle whether it is being used or
not and are typically computed based on time (such as cost per
month or year).

Gross Vehicle Weight (GVW): This is the maximum operating
weight of a vehicle as specified by the manufacturer. It includes
the vehicles chassis, body, engine, fluids, fuel, accessories,
passengers, and cargo. It is a term used for both motor vehicles
and trains. (It does not include any trailers being towed.)

Plug-In Hybrid Electric Vehicle (PHEV): These vehicles tend to use
gasoline or diesel as a main source of fuel but also have an electric
motor to either assist in powering the vehicle or to provide primary
power for a period of time.

Indirect Costs are expenses associated with maintaining the entire
fleet. These costs are not directly associated with a particular piece
of equipment but are still critical to its operation such as mechanics
Avista Digger Derrick
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 49 of 51
and their labor costs, tools and equipment, fleet buildings, as well as hardware and software
applications.

Meantime Between Service: This is a metric that defines the average operating time between regularly
scheduled services/maintenance. It provides an indication of the quality of the services an asset
receives. A high mean time between service dates may indicate a lack of investment in caring for an
asset, which can lead to accidents or other safety issues along with the potential for premature failure.

Mechanic Per Vehicle is the ratio between the number of mechanics on staff and the number of
vehicles in the fleet.

Operating Cost: This cost is associated with the
maintenance and upkeep of an asset. It includes
the sum of all Company mechanic labor, contract
mechanic labor, parts, tires, and fuel expenses. It
can also include depreciation, insurance,
registration and the like.

Ownership Cost: This includes all costs associated
with owning an asset, including the purchase
price, maintenance costs, insurance, and any costs
related to operating the asset.

Power Operated Equipment (POE) is a unit that operates off-road, including backhoes, skid steers,
generators, etc.

Skid Steer: This is a small, rigid-framed machine with either four
wheels or a track movement system that has lift arms attached to a
bucket, small backhoe, plow, trencher, auger or other
attachments.49 These are used to lift and carry material or aid in
excavation. They are capable of zero-turn radius, which makes them
highly maneuverable, especially in situations requiring a small and
agile loader.

Stake Truck: Also called a platform truck, this has a plain flatbed or side panels (which are often
removable) for hauling equipment.

Support Cost: The sum of all expenses related to management and support staff, the facilities, and
associated shop supplies.
49 For an idea of all the attachments available to these versatile machines, see: https://www.casece.com/northamerica/en-us/products/skid-steer-
loaders/overview/attachments
Skid Steer
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 50 of 51
Support Staff Per Vehicle is the ratio between the
number of support staff and the number of
vehicles in the fleet.

Total Cost or Total Cost of Ownership: This is the
sum of ownership, operating and support costs. It
includes both the purchase price of the item plus
the cost of operating it. Operations costs usually
include things like maintenance charges,
downtime costs, and driver costs.

Utilization is the usage of vehicles based on annual average miles driven within a minimum mileage
threshold.

Units: This is a general term for a vehicle, trailer or
piece of power equipment like a generator, Genie
lift, or compressor.

Variable Costs are those related to the vehicle’s
activity, usually computed using the distance
traveled or the hours of operation. These kinds of
costs include items such tires, fuel, fluids, and
wiper blades.

Vehicle is a unit that operates on the road.

Vehicle Equivalency (VE) or Vehicle Equivalency Units (VEU): This weighs the number of units and
vehicles in the fleet according to the annual average maintenance and repair hours needed for that
particular unit or vehicle. For example,
adding up how vehicles a company has in
order to determine how many mechanics
need to be hired. It also allows comparing
the requirements of one vehicle (such as
an employee fleet car) to another (such as
a digger derrick) to ascertain maintenance
and repair budgets. A car might have a
ratio of 10 VEU to maintain compared to a
digger derrick of 100 VEU to maintain.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 7, Page 51 of 51
Avista Utilities
Facilities Infrastructure Plan
2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 1 of 46
Thanks & Acknowledgements
Anna Scarlett – Guidance, Leadership
David Schlicht – Data, Insights, and Expertise
Eric Bowles – Expertise, Data, Guidance
Jennifer Deline – Writing, Editing
Julie Lee – Budget and Actual Expenditures
Ken Copenhaver – Editing, Publication
Lindsay Miller – Co-Author, Expertise & Guidance
Robert Johnson – Data, Insights, and Editing

Lisa La Bolle – Primary Editor and Author, Research, Drafting, Figures, Graphics, Production

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 2 of 46
Table of Contents
Thanks & Acknowledgements ........................................................................................................................ i
Introduction ..................................................................................................................................................2
Avista’s Facilities Investments ...................................................................................................................... 20
Avista’s Facilities Capital Investments ........................................................................................................... 22
Capital Project Investment Selection Process ...................................................................................................... 22
Classification of Infrastructure Need by Investment Drivers ............................................................................... 25
Facilities Budgeted Capital Projects By Business Driver ...................................................................................... 31
Avista’s Facilities O&M Investments ............................................................................................................. 32
Summary and Wrap-Up ................................................................................................................................ 32
Appendix A: Awards ..................................................................................................................................... 32
Appendix B: Capital Request Form ................................................................................................................ 32

Table of Figures

Figure 1. Avista Facilities Managed and Related Expenditures ................................................................................................... 4
Figure 2. Avista Staffing Levels per Square Foot vs. Industry Standard ...................................................................................... 4
Figure 3. Avista Employee Counts .................................................................................................................................................. 5
Figure 4. Avista Employee Area Growth ...................................................................................................................................... 5
Figure 5. Avista Employee Headcount and Customer Growth ..................................................................................................... 8
Figure 6. Avista Square Feet of Property Managed & Value ...................................................................................................... 11
Figure 7. Terracon Identified Avista Facilities Total Issues by Cost ........................................................................................... 12
Figure 8. Avista Maintenance Expenditures vs. Industry Recommendation .............................................................................. 12
Figure 9. Avista Work Backlog Identified by Terracon Study ..................................................................................................... 13
Figure 10. Avista Budget by Square Foot & Per Employee........................................................................................................ 14
Figure 11. Terracon Number of Issues Identified by Location and Risk ..................................................................................... 15
Figure 12. Avista Facilities Growth 2008 – Present and Associated Staff .................................................................................. 16
Figure 13. Environmental Compliance Issues and Ranking ....................................................................................................... 19
Figure 14. Facilities Spending Compared to Space Managed ................................................................................................... 20
Figure 15. Facilities Capital Expenditure Budget ....................................................................................................................... 26
Figure 16. Primary Capital Expenditures for Facilities 2005-2019 ............................................................................................. 27
Figure 17. Square Footage of Avista Facilities Managed ........................................................................................................... 28
Figure 18. Facilities Structures & Improvements Capital Budget & Actuals ............................................................................... 32
Figure 19. Facilities O&M Budget and Actual Spending............................................................................................................. 32
Figure 20. Avista O&M Spending vs. Industry Recommended Levels ....................................................................................... 32

Table of Tables

Table 1. Facilities Capital Budget Compared to Avista Capital Budget ...................................................................................... 22
Table 2. Facilities Capital Projects 2020 - 2024 ......................................................................................................................... 27
Table 3. Facilities Planned Asset Condition Budget ................................................................................................................... 31
Table 4. Facilities Planned Performance & Capacity Budget ..................................................................................................... 32

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 3 of 46

A utility is an asset-heavy entity, requiring a great deal of infrastructure to support its operations.
Trucks, crews, office and operations buildings, large storage areas, equipment and supplies, support
staff and more are required in order to provide 24-hour a day customer service for Avista’s electric and
gas customers. As would be expected, many of the facilities built over time to support Avista
operations are quite dated. Some were built in early Company
days during the late 1800s, many others were built in the
1950s and 1960s (almost 70 years ago!) Others are modern
and provide sufficient service for today’s purposes.

In order to continue to adequately serve customer needs and
customer investments in infrastructure going forward,
buildings must be maintained, upgraded and updated to meet
the uses for which they are intended. Common sense and
good stewardship indicate that facilities will need more
maintenance over time if they are to remain useful. Complete
replacement may be required to remain functional, not only
to keep up with current
requirements, but also
to save money over the
long term. For Avista,
these requirements
include a steady
increase in customer
base and increasing
focus on customer
service, which
naturally requires
more employees and
equipment over time.

Trucks and vehicles have also increased in size and complexity,
requiring more space as well as specialized maintenance and
support. Materials and supplies must be located in close
proximity to crews in an organized, efficient space for quick
access in order to provide effective daily work flow and to
remedy outages in a timely manner. Employees must have
adequate and safe work areas to perform their jobs and serve customers. All of these facets come into
Above: Mission Campus Pole Yard
Below: Lewiston Office
Introduction

•All maintenance requirements for
office buildings, shops, call and
service centers, equipment &
vehicle areas, warehouses, docks,
storage facilities, parking zones,
and all other Company physical
spaces
•Heating, cooling, ventilation,
electrical, plumbing, and lighting
system functionality & efficiency
•Space management
•Property and grounds
•Janitorial services
•Lease management
•Handling employee moves &
accommodations
•Energy efficiency measures
•Facilities construction
•Shared space scheduling
•Parking areas
•Employee moves
•Planning, budgets, project
management, record keeping
Avista Facilities Team
Responsibilities Include:
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 4 of 46
play in order for Avista to provide an appropriate level of customer service, and they are centered in
the facilities that support Company operations.

Facilities underpin the success of most organizations, and this is
especially true in the utility industry. The heart of the ability to serve
customers lies in the crews and equipment that go out and perform
the work, from the daily practices such as replacing failed equipment
or installing service for new customers, to crisis situations of putting
the system back together after a major storm. This necessitates
reliable, dependable vehicles, ready access to tools, equipment and
supplies, effective and efficient employees, and a strong focus on safety. These requirements are at
the heart of Avista Facilities Management work, plans, and strategies.

Utility infrastructure also includes the support functions that
are required for Avista to function as a business, such as
accountants, engineers, mechanics, customer service
representatives, line patrol vehicles, phone systems, work
cubicles, chairs, computers, service bays, and so much more.
All of this requires a framework for which the Avista Facilities
team provides systems, structures, maintenance, and
associated support.

This small group of seventeen employees is responsible for all
of Avista’s lands and buildings, which includes a wide
spectrum of responsibilities such as managing janitorial
services, ensuring a roof is repaired before it fails, replacing a
structure when it no longer serves the necessary purpose or
becomes cost ineffective, handling major construction projects, fixing clogged plumbing, and even
spraying weeds. It should be noted that only about 57% of the Facilities staff performs actual
maintenance and repair work across the Avista service territory; others execute capital projects, and
others provide general support across the
organization. This group manages and
maintains 51 facilities totaling 1,265,514
square feet on over 59 acres, in addition to 38
sites across a service territory containing nearly
1.6 million customers scattered across 30,000
square miles in four states.1 In addition, the
Company service territory is split into sections
of 12 operating districts, each containing
1 Avista Quick Facts 2019, https://myavista.com/about-us/our-company/quick-factsqs
Avista Facilities Staff

•1 Corporate Facilities Manager
•1 Building Ops. Supervisor
•1 Quality Assurance Inspector
•3 Building Servicemen
•1 Electrician
•3 HVAC Technicians
•1 Painter
•1 Groundskeeper
•2 Project Managers
•1 Corporate Space Planner
•1 Interior Planners
•1 Administrative Assistant
“Maintenance” is defined as the act of
keeping assets in acceptable condition.
It includes preventative care, normal
repair, replacement of parts and
structural components, and other
activities needed to preserve the asset
so it can continue to provide acceptable
service and achieve its expected life.
The little Avista service center in Kamiah
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 5 of 46
regional crews, support employees, buildings, storage yards, and associated equipment and facilities.
Supporting such a vast area and
such a diverse group of assets
requires leadership, vision, good
planning, expertise, experience,
and decision-making tools. The
Facilities team utilizes all of these
aspects, including performing
regular studies of facility
condition, receiving feedback
from employees when they
identify issues, and using common
sense, industry standards, surveys
and evaluations, as well as asset
management techniques such as
life cycle costs and asset health indices. They consider issues such as safety, criticality, efficiency, cost,
potential savings, and long term costs and value while holding to a clearly defined budget. It is a
balancing act, as the age of Avista’s buildings means that the needs and demands for repair, remodel,
or replacement have continued to grow and become more pressing over time, while the budgets for
maintenance have remained relatively flat. To add to this situation, the amount of facilities space being
added to the Company portfolio continues to increase. This issue is clearly shown in Figure 1.2

Manpower levels in Facilities have remained nearly the same for over a decade, as shown in Figure 2.
Though industry standards
recommend one full time employee
per 49,000 square feet of space
managed,3 Avista currently has one
employee per 55,903 square feet of
space managed, putting ever
increasing burdens on very few
employees who are maintaining
facilities which continue to grow
older.

As shown in Figure 2, Avista has
increased the number and size of its
properties over 62% in the past ten
years. Though capital expenditures to
2 Larger expenditures in 2018 are due to the new Fleet Building ($6.3 million) as well as constructing the Dollar Road Facility ($14.3 million) and the Deer
Park Service Center ($5.1 million).
3 International Facilities Management Association, “Operations and Maintenance Benchmarks: Research Report #32,” page 51. This report is not available
online. It must be purchased. However, Avista has one available if requested.
Figure 1. Avista Facilities Managed and Related Expenditures 2
Figure 2. Avista Staffing Levels per Square Foot vs. Industry Standard
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 6 of 46
purchase and build new facilities have increased, over the same time period O&M budgets have
remained relatively flat, which means they are
maintaining a far greater amount of space with
the same amount of dollars.

Avista’s full time employee levels have
remained relatively stable over the past few
years as can be seen in Figure 3 (blue line).
Figure 4 highlights the fact that most of
Avista’s space needs are related to professional
level employees (both Avista employees and
temporary employees or contractors.)

Often temporary employees are associated
with technology, such as hiring specialists to install the new Windows 10 operating system company-
wide. When temporary projects wind down, temporary employee levels decline accordingly, as shown
in Figure 3. Contracting is a cost-saving measure, typically used when the Company either does not
have the expertise in-
house or lacks the
manpower to perform
labor and time-
intensive tasks like
wood pole and gas line
inspections, or for short
term tasks such as
technology installations
as mentioned above.
Contractors are an
important work source,
and though they are
not full-time long-term
employees, they still
need a place to work,
even if just temporarily.
Thus, finding adequate
office space, maximizing the use of existing space,
and minimizing splitting up teams is an ongoing
struggle.

Another issue repeatedly faced by the Facilities team
is declining customer satisfaction. They face constant
Figure 4. Avista Employee Area
Growth

Note that Energy Delivery is broken
out because it contains the largest
number of employees and would
skew the main chart.
Figure 3. Avista Employee Counts
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 7 of 46
complaints from customers, employees and contractors about the condition of the buildings they
manage, including dirty windows, stained carpets, pot holes in the parking lots, odors, cracks, loss of
paint, too few (or no) conference rooms, lack of adequate work space, etc. To make matters worse,
work response time to internal customer issues at Avista facilities has increased significantly in the past
ten years. Currently what used to be same-day response has
increased to an average of three days to react to non-emergency
concerns simply due to lack of manpower.

Unfortunately, existing funding has required an O&M shift to
maintaining only the most critical systems, thus more aesthetic
problems such as dirty carpets and windows are “selectively
neglected.” These types of issues tend to be very noticeable to
employees and customers, affecting the perceptions of both with
respect to the Company. It also reduces the expected life of assets
and increases long term maintenance costs. As can be imagined, all of
these issues along with the constant pressure of not being able to address basic problems, unhappy
customers both internal and external, and being understaffed and overworked is taking a toll on
Facility employee morale as well as the lifecycle expectations and costs associated with these assets.

Even facing all of these challenges, the Facilities team has achieved numerous successes and awards.
Facilities has worked to achieved LEED GOLD status for each floor of its corporate office building. A
LEED certified building has incorporated sustainability into its design and construction, and thus can
potentially perform more sustainably than
typical comparable buildings in the
marketplace. Addressing this phase of a
building’s life is important because many
irreversible decisions with impacts on
sustainability are made during the design
and construction processes. At Avista, this
sustainability focus was included as part of
an overall renovation of the corporate office
building, including the HVAC, electrical and
plumbing systems for each floor.

Upon the completion of this work, the Facilities team chose to apply for the designation of LEED-
Existing Building (EB). LEED-EB aims to maximize operational efficiency while minimizing environmental
impacts. Its main users are building owners and facilities managers. Since LEED-EB is based on actual
building O&M practices, a LEED-EB certified building is actually performing more sustainably than its
peers. Addressing the operations phase of a building’s life is critical, because on a life-cycle basis, that
is typically when most of the environmental impacts occur. Moreover, improvements in this phase lead
to actual, concrete, measurable benefits. Facilities was able to demonstrate all these benefits and
received LEED GOLD for this work.
Avista Officers and Facilities staff receive the LEED GOLD Award
Square Feet Managed # of FTEs
Less than 50,000 2
50,000 - 100,000 4
100,001 - 250,000 5
250,001 - 500,000 9
500,001 - 750,000 13
750,001 - 1,000,000 16
1,000,001 - 1,500,000 27
1,500,001 - 2,000,000 35
2,000,001 - 3,000,000 44
More than 3,000,000 140
IFMA Recommended Maintenance Staff
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 8 of 46
Another designation that Facilities has worked toward is an Energy Star rating. Buildings that earn the
U.S. Environmental Protection Agency’s Energy Star use 35% less energy and generate 35% fewer
greenhouse gas emissions than similar buildings across the nation. The financial value of energy savings
isn’t just limited to utility bills. It accrues across the board — from asset value to shareholder value to
operating income. Beyond the positive financial impacts, saving energy also makes a real-world impact
in meeting environmental goals of reducing greenhouse gas emissions. To date Facilities has achieved
this designation at two of its facilities, the Spokane Valley Call Center and the Corporate Office
Building.

Benefits of Well Maintained Facilities

Buildings and facilities are exposed to all kinds of weather – rain, sun, snow, wind and other natural
elements. Over time, this exposure has an adverse effect on roofs, windows, doors, paint,
asphalt, wood and other building materials. Paint begins to peel, doors warp, and covers
leak. If left unattended, interior walls, floor coverings and ceilings can also be damaged
through routine use, resulting in costly repairs if not addressed in a timely manner. Avista’s
buildings house employees and expensive equipment that must be protected. These are
Avista assets, paid for by customers, and must be adequately maintained in order to
continue to perform their intended purposes, be it storing poles and transformers, providing
maintenance and storage areas for vehicles, or creating working spaces for employees.

Performing adequate maintenance allows the Company
to preserve and fully utilize their properties while
reducing expensive repairs in the long term. It also
ensures a safe environment for people and equipment.
Damaged or poorly maintained facilities can create very
real safety risks and associated liability for employees,
customers, and contractors. The Facilities group focuses
on reducing risk by monitoring the condition of Avista
facilities across the service territory using a variety of tools and
techniques described in further detail later in this report.

One of the subtle but important aspects of maintaining facilities is
to provide comfortable, safe, and efficient work spaces. This is one
of the keys in attracting and maintaining quality employees. It is estimated that over 30% of current
utility employees are within five years of retirement.4 The utility industry is seeing a huge shift in
4 Gil C. Quiniones, “30% of Utility Workers Retiring in 5 Years, New Recruiting Strategies Essential,” Breaking Energy, June 12, 2014,
https://breakingenergy.com/2014/06/12/utilities-preparing-for-massive-workforce-turnover/

Broken
Gutter
Damaged
Roof
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 9 of 46
attracting, motivating and training new employees. Today’s
employees, especially those with specialized skills, know that they are
in high demand in every industry and are no longer interested in
being employed by one organization or industry for their entire
careers. Utilities such as Dominion Energy, with an employee base of
over 16,000 employees, have found that employee workspaces play a
large role in helping them retain talent. They state: “A company that
hopes to have a successful future must attract strong candidates and
retain talented employees. We strive to create work spaces that meet
the needs of our current employees and help attract new ones.”5 One
of the ways they achieve this is to focus on providing a
comfortable, clean, efficient and welcoming workplace. A recent
study found that 2 out of 3 employees in today’s workforce say
that the physical environment of their workplace affects their
decision to stay or leave an organization and, in fact it ranked 8
out of 10 in impacting their satisfaction and job performance.6

Employees view their work setting and the workplace services
offered as an extension of their level of care by a company. A
recent study revealed that high workplace satisfaction is also
positively correlated with high employee production, meaning the
physical workplace can be used as a
strategic asset to improve engagement,
employee motivation, and performance. In
fact, studies prove that a “shabby” work
environment creates negative attitudes in
employees, reducing their output and
actually affecting the bottom line.7 Satisfied
employees provide higher quality customer
service, which is a primary goal at Avista.

5 “Attracting, Developing, and Retaining Talent,” Dominion Energy, https://sustainability.dominionenergy.com/talent-strategy/ and
https://sustainability.dominionenergy.com/employee-experience-overview/
6 Michael Guta, “23% of Employees Decide Where to Work Based on the Office Environment, Survey Finds,” Small Business Trends Magazine, July 8,
2018, https://smallbiztrends.com/2018/07/office-design-can-attract-employees.html and Lindsey Pollak, “What Do Multigenerational Employees Want in a
Work Environment?” https://www.lindseypollak.com/multigenerational-work-environment/
7 “Facilities Management Plays Key Role in Employee Satisfaction,” Buildings Magazine, March 20, 2012, https://www.buildings.com/article-
details/articleid/13762/title/facilities-management-plays-key-role-in-employee-satisfaction also “Employee Engagement Linked To Workplace Satisfaction,”
Executive Magazine, May 27, 2016, https://facilityexecutive.com/2016/05/employee-engagement-linked-to-workplace-satisfaction/
Many of Avista’s work areas are less than ideal
Figure 5. Avista Employee Headcount and Customer Growth
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 10 of 46
The Facilities staff participates in helping Avista retain its
talent base by attempting to provide work areas that help
promote job satisfaction and work production, have
ergonometric designs to safeguard employee health, and that
are safe, effective and efficient. Adequate meeting areas,
maintenance and work stations, cafeteria and break areas,
exercise facilities, and the like all add to employee quality of
work life. However, providing these basic amenities is a
constant challenge at Avista, given the age of many of the
facilities and lack of funding to provide space, furniture and
equipment.

Customer perception is also a subtle but important Facilities
consideration. Run down, dilapidated facilities give the impression of
poor service and performance. Customers may hesitate to enter a
customer service center in this condition, isolating them from
interactions with the Company. Poorly maintained facilities may also
encourage customers to feel that the money they send in every month
as they pay their bills may not be spent wisely or to preserve the assets they have provided for the
Company through their rates. Avista strives to be engaging and welcoming with customers,
encouraging interaction. That makes this is an important facet in maintaining the appearance and
condition of the physical presence of the Company in its service buildings, operations areas, storage
yards, and customer service centers.

Management Practices: The “How”

We know why this work is important, so how does the Facilities
team effectively tackle such a large, complex, and diverse asset
base and the associated tasks? One methodology employed is the
utilization of systematic procedures and protocols to determine
how to best manage Avista’s facilities. Part of this evaluation
includes industry best practices as determined by national
organizations that specialize in this area, including Building
Owners and Managers Association (BOMA) and the International
Facility Management Association (IFMA).

BOMA uses their expertise in the industry to provide training as
well as research results and recommendations to building owners
across the nation. They also give out highly prestigious industry
awards. Avista has received the BOMA 360 Performance Program
Founded in 1980, IFMA is the
world's largest and most widely
recognized international association
for facility management
professionals, supporting 24,000
members in more than 100
countries. Together they manage
more than 78 billion square feet of
property and annually purchase
more than $526 billion in products
and services. They focus on best
practices, training, research, and
education.
INTERNATIONAL FACILITY
MANAGEMENT ASSOCIATION
(IFMA)
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 11 of 46
Certification for the Corporate Headquarters Building.8 This certification
was granted to Avista as a result of the Facilities team’s efforts to add
energy efficiency measures when they remodeled this 1959-era
building, and acknowledges the fact that they operate and manage it
better than most comparable buildings around the world.9

IFMA is also recognized as an international expert on managing
facilities, offering certification, education, and industry-specific
information and research.10 The expertise offered by these
organizations helps guide Avista’s facilities management practices. In
addition, Facility’s employees utilize technology to monitor equipment,
systems, energy usage, etc. Specialized analysis is also used to help
predict failures and to help identify issues prior to failure. Data is
gathered to track issues and concerns over time in the service of
developing a more proactive approach to sustaining assets. The
Company also calls in outside expertise to objectively evaluate the
condition of facilities and provide professional guidance on facilities and
conditions as described below.

Terracon Facilities Evaluation

In 2017 the Company hired Terracon Consultants to perform a condition assessment on 76 Avista-
owned facilities and 35 real estate sites at 34 different locations, comprising approximately 981,000
square feet. These facilities were constructed between 1903 and 2016. Terracon estimated the value
of this infrastructure at approximately $242 million.

The Terracon study was highly detailed and in depth. They examined every characteristic of each
facility from a variety of perspectives. External structures from asphalt in the parking lot to roof
condition, fences, curbs, and storage areas were examined to ascertain and score condition and to
identify issues and note concerns. Internal aspects such as walls, carpets, and furniture condition were
evaluated. They surveyed building systems including plumbing, heating and cooling, electrical, lighting,
air quality, drainage, and security. They looked at safety aspects from both the customer and employee
perspective. Then each item in the facility was rated based upon its condition and assigned a budget
category of O&M Preventative Maintenance, O&M Deficiency Repairs, Capital Replacement, and
Capital Renewal/In-Kind Replacement.11
8 https://www.boma.org/BOMA/Recognition-Awards/BOMA_360_Performance_Program/BOMA_360_Buildings/BOMA/Recognition-
Awards/BOMA_360_Buildings.aspx?hkey=651693fa-b5df-4923-b091-0b3a9987e937
9 “BOMA 360 Performance Program,” BOMA International, https://www.boma.org/BOMA/Recognition-Awards/BOMA_360_Performance.aspx
10 International Facility Management Association (IFMA), https://www.ifma.org/
11 O&M Preventative Maintenance is planned maintenance conducted regularly on equipment still in working condition. O&M Deficiency Repairs involve
unplanned maintenance conducted on equipment to get it into working condition. Capital Replacement is unplanned, replacement or refurbishment of
assets that have failed. Capital Renewal/In-Kind Replacement involves planned, cyclical replacement or refurbishment of assets at the end of their useful
lives to maintain a state of good repair.
The Building Owners and
Managers Association (BOMA)
International is a federation of
88 BOMA U.S. associations and
18 international affiliates.
Founded in 1907, BOMA
represents the owners and
managers of all commercial
property types including nearly
10.5 billion square feet of U.S.
office space that supports 1.7
million jobs and contributes
$234.9 billion to the U.S. GDP.
Its mission includes advocacy,
education, shared knowledge,
and best practices.
BUILDING OWNERS AND
MANAGERS ASSOCIATION
(BOMA)
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 12 of 46

The Terracon study identified and prioritized issues they found with the goal
of extending the overall service life of these facilities and reducing the
possibility of unplanned repairs, safety issues, failures or service interruptions.
It also provided a thorough inventory and condition
assessment of all Avista-owned facilities, including
current deficiencies, forecasted costs for repairs and
anticipated future maintenance needs. Terracon
prioritized the maintenance and replacements they
identified using a specialized software product designed
for this purpose.
Figure 6. Avista Square Feet of Property Managed & Value
Terracon Inspection Items
Included:

•Building Exterior (lighting, paint,
glass, doors, siding, trim, general
condition)
•Outbuildings & Storage Areas
•Perimeter (fences, sidewalks,
parking, storm drains, landscaping,
storage yards, signage, lighting)
•Roof (general condition, drains,
gutters, downspouts, seams,
flashings)
•HVAC (type, age, filters, belts, fans,
air intakes, general condition)
•Electrical Systems (panels, lighting,
service mast, etc.)
•Emergency generator (age and
condition)
•Plumbing (restroom condition,
toilets, sinks, septic systems,
general infrastructure)
•Building Interior Systems (paint,
carpets, tile, casework, general
furniture condition & usability)
•Line Docks
•Elevators
•Fire Protection Systems
•Security (general and security
systems)
•Roll Up Doors
•Waste Collection
•Compressed Air Systems
Site Square Feet Acres Value
Beacon Substation 31,670 19 $4,729,932
Chewelah Facility 5,200 1.6 $1,094,625
Clarkston Service Center 24,678 4.3 $5,080,245
Coeur d'Alene Service Center 51,084 9.4 $10,794,280
Colfax Facility 2,169 0.3 $263,453
Colville Service Center 20,105 6 $5,364,761
Courtyard 56,000 1 $16,082,583
Davenport Service Center 13,608 0.7 $2,443,993
Dollar Road Service Center 15,000 1 $4,566,811
Downtown Project Center 25,000 1 $4,676,144
East Davenport 2,000 0.9 $377,072
Elk City Facility 1,800 1 $276,358
Grangeville Facility 9,904 0.5 $1,036,402
Grants Pass Service Center 1,126 0.3 $1,129,175
Jack Stewart Training Center 26,108 34.5 $4,260,418
Kamiah Facility 800 0.5 $378,818
Kellogg Service Center 13,622 1.9 $3,074,896
Klamath Falls Service Center 5,132 1 $3,680,695
LaGrande Service Center 3,730 0.6 $2,646,677
Lewiston Call Center 5,468 0.6 $1,614,292
Main Campus 463,692 37.9 $118,237,135
Medford Service Center 29,800 1 $5,555,944
Orofino Facility 7,190 0.5 $2,127,522
Othello Service Center 6,400 0.5 $1,644,203
Pierce Facility 1,200 1 $239,668
Pullman Service Center 25,436 6 $5,128,085
Ritzville Facility 2,500 1 $404,586
Roseburg Service Center 4,000 1 $1,417,649
Sandpoint Service Center 17,931 6.5 $3,857,002
Spokane Valley Call Center 14,022 2.8 $3,136,360
St. Maries Service Center 12,209 4.3 $2,625,370
Steam Plant Square 81,500 1 $23,384,227
Tekoa Facility 1,383 0.1 $186,134
Total 981,467 149.7 $241,515,515
Facilities Evaluated by Terracon
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 13 of 46
Terracon’s research into
Avista’s infrastructure and
practices found that Avista is
underfunding preventative
maintenance activities,
leading to a reduced service
life of Company assets and
their components and
increasing the possibility of
unplanned service
interruptions. In Terracon’s
expert opinion (which is
backed by the industry),
funding levels for
preventative maintenance
should typically run from 2-4%
of the plant replacement value of the assets being maintained.12 This level of funding provides the
necessary expenditures to maintain only the basic functionality of facilities. In fact, they assert that this
funding level should be used as an absolute minimum value, encouraging that “Where neglect of
maintenance has caused a backlog of needed repairs to accumulate, spending must exceed this
minimum level until the backlog
has been eliminated.”13

The estimated replacement
value of Avista’s assets when
the survey was taken in 2018
was approximately $242 million,
with estimated maintenance
and replacement requirements
based on the Terracon report of
$8,800,640 per year, which
equals 3.64% of the current
replacement value of Avista’s
facility-related assets. Figure 8
clearly demonstrates that the
12 The 2-4% is mandated by the Building Research Advisory Board, a branch of the National Academy of Sciences, in their report “Committing to the Cost
of Ownership - Maintenance and Repair of Public Buildings,” https://www.nap.edu/catalog/9807/committing-to-the-cost-of-ownership-maintenance-and-
repair-of. This percentage level is also recommended by the Federal Facilities Council, “Determining Current Replacement Values,”
https://www.nap.edu/read/9226/chapter/4. It is also recommended by the Building Research Board Committee on Advanced Maintenance Concepts for
Buildings report “Committing to the Cost of Ownership – Maintenance and Repair of Public Buildings,” https://eric.ed.gov/?id=ED322581
13 The National Academies of Sciences, Engineering, and Medicine, “Budgeting for Facilities Maintenance and Repair Activities: Report Number 131,”
https://www.nap.edu/read/9226/chapter/3
Figure 7. Terracon Identified Avista Facilities Total Issues by Cost
Figure 8. Avista Maintenance Expenditures vs. Industry Recommendation
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 14 of 46
amount spent by Avista at about $4 million per year
(the blue bars), does not reach the minimum level
of O&M expenditures standard in the building
industry for basic sustenance of facilities (the green
line). At Avista, O&M expenditures have actually
decreased with the addition of more square
footage. In fact, over the past ten years Facilities
has increased its portfolio of square footage by
almost 63% with no significant increases in staff or
funding levels for maintenance and repair.

Out of the approximately $4 million budgeted for
facilities O&M annually, only about $850,000 is
applied to actual maintenance, which primarily
consists of changing filters. The rest goes to pay for
utility bills including electricity, gas, water, sewer,
garbage service, internet service, and the like.

Unfortunately, facility maintenance activities
compete for limited funding with many other
programs: transmission line rebuilds, turbine
replacements or upgrades, substation
transformers, technology programs, gas line
extensions, wood pole inspections, etc. and it is
relatively easy to push building maintenance
activities to the bottom of the priority list. Often
deferred maintenance is not immediately reported,
if at all, and the associated issues can go
unrecognized until assets fail, start to incur
significant costs, create safety hazards, or present
noticeably poor service to the public.

The backlog of work required to adequately maintain Avista
facilities continues to grow as shown in Figure 9. Nearly
every facility requires some kind of corrective work, and this
has been especially true at the Mission campus, which
houses nearly 60% of the Company’s buildings.

To get a handle on this situation, Terracon recommends that
Avista change to a budgeting concept that is based upon
projected maintenance requirements rather than the
straight-line (plus inflation) approach currently used by the
Headquarters 381,110
Warehouse 35,000
Investment & Recovery 13,200
Waste & Asset Recovery 15,000
Ross Park 17,000
Line Dock 28,750
Covered Areas/Canopies 8,000
Fleet Building 30,000
Parking Garage 171,000
TOTAL SQUARE FEET 699,060
Mi
s
s
i
o
n

C
a
m
p
u
s

Figure 9. Avista Work Backlog Identified by Terracon Study
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 15 of 46
Company. They believe that this will
help the Company get a handle on this
backlog and move to a more proactive
strategy. They also encourage an
increase in preventative maintenance
activities to extend the remaining
service life of the Company’s assets,
thus delaying the need to capitalize
expenditures required when replacing
these assets before their expected
end-of-life timeframe.

This Terracon study is the center of
the Company’s Facilities asset
management plan. It provides both a benchmark of the current building performance and a defensible
estimate of reinvestment costs needed to keep Avista’s facilities functioning at an acceptable level.
Terracon’s extensive study of Avista’s facilities resulted in a list with specific, detailed descriptions of
condition and issues identified. This list includes everything critical to the operation of Avista’s
facilities. Items such as 60-year old electrical panels no longer in compliance with safety standards, old
motors that have far exceeded their expected life and for which parts are no longer available, wood
surfaces desperately in need of paint to protect them from the elements, missing lights, leaking roofs,
and more can be found on this list.

Terracon’s list is sorted by relative risk and the impact the item has on the
Company’s ability to perform its work, making the highest priority projects
readily apparent. Of the 363 “at risk” items
Terracon identified, nearly 60% had a risk rating
higher than 5 (on a 1 to 10 scale) and 20% were
identified as having an actual impact on operations.
All of the items on list were identified as needing
an immediate fix at a cost of almost $6.4 million, a
mixture of capital and O&M required dollars.
Though each year as many elements on this list as
possible are being addressed in a priority
fashion, the list will continue to grow as
the infrastructure continues to age,
especially if it is not receiving adequate
maintenance in the meantime. The
Terracon priority list is on the next page.

Figure 10. Avista Budget by Square Foot & Per Employee
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 16 of 46

Equipment Monitoring

Another tool in the Facilities toolkit is the use of equipment
monitoring technology. This technology allows Facilities to
actively monitor and track equipment and building
performance, and to create more thorough and cost-effective
preventative maintenance (PM) schedules. For the buildings
that have this specialized equipment installed, the information
provided allows observing and controlling the building
environments in real time as well as scheduling and modifying
mechanical equipment operation remotely. These systems also collect and store data about system
performance for trending and analysis. Results can be used to predict failures and correct issues before
Figure 11. Terracon Number of Issues Identified by Location and Risk
Facility # of Items
Total Cost to
Repair or
Replace
Ave. Risk
Factor
Ave.
Impact
Rating
Highest
Risk
Rating
Highest
Critical
Rating
Main Campus 101 $2,505,742 5.7 3.3 7.68 10
Steam Plant Square 45 $1,583,121 5.6 2.8 6.56 8
Sandpoint Service Center 21 $189,662 5.7 3.5 7.07 8.5
Kellogg Service Center 17 $87,440 5.2 2.5 6.4 2.5
Clarkston Service Center 15 $365,264 5.7 2.6 6.71 4
Medford Service Center 15 $73,166 4.8 2.7 7.35 6
Davenport Service Center 14 $82,945 4.6 3.6 6.16 8.5
Pullman Service Center 14 $141,803 4.9 2.7 6.16 4
St. Maries Service Center 13 $214,844 4.9 3.2 6.56 6
Courtyard 10 $573,117 6.0 4.7 7.07 10
Lewiston Call Center 10 $68,191 4.9 3.1 6.16 8
Orofino Facility 10 $96,053 3.9 5.1 5.83 10
Colfax Facility 9 $41,622 5.1 3.4 6.48 8
Chewelah Facility 8 $37,956 4.9 4.1 6 8.5
Coeur d’Alene Service Center 8 $25,174 3.9 6.1 4.36 10
Grangeville Facility 8 $113,191 5.2 4.1 6.16 10
Ritzville Facility 8 $32,273 4.2 6.2 5.1 10
Tekoa Facility 5 $16,469 4.9 3.9 6.71 10
Jack Stewart Training Center 4 $44,414 4.2 3.5 5.1 6.5
Pierce Facility 4 $19,850 6.0 2.0 6 2.5
Roseburg Service Center 4 $14,230 4.2 2.5 5.39 2.5
Colville Service Center 3 $2,465 3.5 6.5 3.74 6.5
Elk City Facility 3 $2,765 5.0 4.0 5.39 5
Grants Pass Service Center 3 $8,158 3.7 2.5 4.36 2.5
Kamiah Facility 2 $1,115 4.8 2.5 5.39 2.5
Klamath Falls Service Center 2 $20,691 3.9 2.5 4.12 2.5
LaGrande Service Center 2 $952 4.5 4.5 5.2 6.5
Othello Service Center 2 $35,295 4.3 3.5 4.9 4.5
Spokane Valley Call Center 2 $906 4.4 8.3 4.36 10
Downtown Project Center 1 $10,469 3.7 2.5 3.74 2.5
Sorted by Number of Issues Identified
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 17 of 46
critical failure. The type of data collected includes temperatures, run hours, BTUs, gas or electric
consumption rates, pressure, and more.

Building Automation Management Systems

The Company’s Building Automation Management System is similar to the equipment monitoring
systems, collecting a variety of information similar to that collected by the other equipment monitoring
systems. However, the Automation System also includes a graphical front-end user interface, making it
easier to use and understand. HVAC operational information such as temperature, run hours, pressure
levels, energy usage, etc. is collected to provide early identification of problems within the building’s
systems, automatically optimize their operation and performance, monitor and make changes in real
time, and generate customized reports of performance. The Automated System is incredibly helpful in
troubleshooting issues as well as identifying when a system has failed (or is getting close to doing so)
before it significantly impacts general building operations.

Both of these systems also help maximize building energy efficiency. For example, they may help
Facilities experts see that window blinds are needed for a work area that is requiring higher-than-
expected cooling, or that the run schedule of an HVAC can be modified to reduce operating time.
These systems collect searchable data with complete maintenance records of all equipment and
systems to help identify recurring problems, to identify trends, and to perform analysis.

About 75% of Avista’s facilities (based on square footage) have added automation to increase the
efficiency of building management, primarily in larger facilities and service centers. The Company’s
objective is to have 100% of existing buildings automated. This is a key component of Facility’s goal of
continual improvement in managing their facilities. For new buildings, this technology is a Company
standard, along with required
energy efficiency measures to
keep Avista in compliance with
Washington State Energy Code.14
It is difficult to measure the full
savings impact of these systems on
new buildings other than what
common sense would dictate, but
as an example, the Company’s
existing HVAC system upgrades to
this technology saved 60% of
HVAC electrical cost alone, so it is
apparent that the savings from
this careful monitoring are
significant.
14 https://www.energycodes.gov/adoption/states/washington under “Washington State Certification of Commercial and Residential Building Energy Code”
Figure 12. Avista Facilities Growth 2008 – Present and Associated Staff
Project or Site Year of
Impact
Added Square
Feet
Total Square
Foot Increase
Avista
Facilities
Work Staff
Industry
Recommended
Staffing
2008 Baseline square Footage 2008 800,937 10 16
Spokane Valley Call Center 2009 14,022 814,959 10 17
Colville Service Center 2010 8,000 822,959 10 17
Dollar Road Truck Storage 2010 8,000 830,959 10 17
Mini Line Dock Addition 2011 13,000 843,959 10 17
Jack Stewart Training Center Modular 2011 2,000 845,959 10 17
St. Maries Offsite Parking 2011 5,000 850,959 10 17
New Mission Warehouse Building 2013 35,000 885,959 10 18
New Dollar Road Fleet Building 2013 23,000 908,959 10 19
New Waste and Asset Recovery 2015 15,000 923,959 10 19
Kettle Falls Office 2015 7,800 931,759 10 19
Investment Recovery Building 2016 7,000 938,759 10 19
Beacon Vehicle Storage 2016 21,000 959,759 10 20
Noxon/Cabinet Gorge Bunkhouses 2016 20,000 979,759 10 20
Downtown Project Center 2016 25,000 1,004,759 10 21
Mission Fleet Building 2018 15,000 1,019,759 10 21
Deer Park Service Center 2018 12,000 1,031,759 10 21
Dollar Road Phase 2 2018 35,000 1,066,759 10 22
Airport Hanger 2018 4,000 1,070,759 10 22
Dollar Road Wash Bay 2018 16,000 1,086,759 10 22
Dollar Road Phase 3 2019 28,000 1,114,759 12 23
Mission Parking Garage 2020 171,000 1,285,759 13 26
Total Square Feet 484,822 20,219,739
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 18 of 46
Contracted Services

Limited staff means that some of the work required must be performed by contractors. Currently
approximately 60% of Facilities work is contracted. Contractors are selected based upon a variety of
criteria, including performance benchmarks, cost, and evaluations. In Facilities, these individuals are
primarily utilized for repetitive tasks such as grounds keeping, janitorial work, snow removal, and
cafeteria duties. Contracting can be less expensive than using Company employees, but that is not
always the case, so Facilities makes this choice based on the type of
work needed, length of contract required, and the criticality of the
work being performed. A recent complication in bringing in contract
help is that the main campus is now a “locked down” security site. This
means that all contractors must be escorted by an employee at all
times while on site, so when help is brought in for the Mission
Campus, both the cost of the contractor and the associated escorting
employee must be factored in.

Although contractors provide a beneficial resource for Facilities, an
important factor to note is that Avista Facility employees manage all of the Company’s buildings and
primary systems. Being well acquainted with these facilities provides a quick and efficient response to
issues. It may take days or even weeks to schedule a contractor to do a repair, and the issue may be of
such a nature that waiting is not an option. Having skilled employees available to do specialized work,
and relatively quickly, with a robust understanding of the equipment or buildings involved and loyalty
that encourages performing the work well is a great benefit to the Company.

Given limited manpower and budgets, a careful blend of resources helps allow Facilities to keep
operating at current levels.

Managing Regulatory Issues

The Facilities group is heavily impacted by regulations.
Building codes, rules, and standards all have an impact
on work processes and expenditures. There are a wide
variety of regulations related to facilities and how they
are managed, such as state and federal requirements for
energy efficiency when building new facilities or
renovating existing ones, fire codes, safety regulations,
city statutes and building codes, federal requirements to
provide adequate accessible parking spaces and building
accommodations, and much more.
Department of Energy Has
Code Requirements for:

❖ Total building performance
❖ Air leakage
❖ Mechanical systems
❖ Interior & exterior lighting
❖ Elevators
❖ Transformers & meters
❖ Motors
These apply to any new buildings, additions or any
building alteration.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 19 of 46
Federal regulations impact most elements of buildings.15
According to the U.S. Department of Energy: “The legal
obligation to comply with the energy code (meeting all the
applicable requirements) rests squarely on the
professionals who design and construct buildings.”16 Many
of these codes also apply to maintenance. For Avista, this
means Facilities. It touches the way they design and
remodel buildings, which heating, cooling, and lighting
systems they install, and how they sustain key elements of
each building.

Federal law mandates that each state have an energy code
and establish minimum requirements for that code. It is up
to each state to implement and enforce its own code that
meets or exceeds the federal government requirements.
Thus the State of Washington also has a lengthy list of
requirements.17 In addition, different counties have their
own requirements, and so do cities and towns. An example
of some of the regulations that impact Facilities are the
impacts of today’s Energy Code on new construction
projects. These requirements include the allowable watts per square foot of lighting systems, the
minimum energy efficiencies required of mechanical systems, occupancy requirements for offices and
conference rooms, and use of energy efficiency techniques to meet the requirements of the code.18 All
of these items cause an increase in scope, schedule and budget for most new construction projects and
remodels as well, but are required in today’s regulatory environment.

Managing Environmental Issues

Another, often unrecognized, issue facing Facilities is the impact of environmental regulations. There
are federal, state, and local permits and requirements for elements such as managing runoff associated
with parking lots, state and county storm water compliance, wells and water quality permits, zoning
and setbacks, right-of-ways, protection mitigation for sensitive areas, and the like. Many of Avista’s
facilities were designed and built in the 1960’s. The codes and requirements between now and then
have increased greatly, causing many of the Company’s locations to fall below not only Avista’s
environmental standards, but below state and federal requirements as well. The chart on the next
page indicates the Company’s current environmental compliance ratings.
15 U.S. Department of Energy, “Building Energy Codes Program,” 2018,
https://www.energycodes.gov/sites/default/files/becu/2018_IECC_commercial_requirements_lighting.pdf
16 U.S. Department of Energy, “Building Energy Code Compliance,” November 14, 2016, https://www.energy.gov/eere/buildings/articles/building-energy-
code-compliance
17 “Washington State Energy Code, Commercial Provisions,” https://fortress.wa.gov/ga/apps/SBCC/File.ashx?cid=6195
18 For more information, please see: “Whole Building Design Guide,” https://www.wbdg.org/resources/energy-codes-and-standards
State of Washington Has
Code Requirements for:
❖ Energy efficiency standards
❖ Insulation
❖ Mechanical systems
❖ Water heating systems
❖ Climate zones
❖ Arrangement of windows & doors
❖ Plumbing
❖ Electrical & lighting systems
❖ Footings, foundations & walls
❖ Equipment & system controls
❖ Fans
❖ Duct sealing
❖ Lighting
❖ Location of daylight zones
❖ Air barriers/thermal envelopes
❖ Construction elements
❖ Accessibility
These apply to any new buildings, additions or any
building alteration.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 20 of 46

Figure 13. Environmental Compliance Issues and Ranking
Colville District Office

Medford Weld Shop
Rathdrum Service Center
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 21 of 46

Managing Expenditures

The Facilities group is responsible for a continually growing – and growing older – portfolio of
infrastructure while staying within an established budget. Though capital budgets have grown along
with Company expansion,
Operations & Maintenance
expenditures have not kept pace,
as shown in Figure 14. Since 2008
Avista has added 464,577 square
feet of facility space, as reflected
in the increased capital
expenditures, but during the
same period, O&M expenditures
have remained nearly flat.

Some of the largest capital
expenditures in recent years
include extensive renovations of
the headquarters and other old
buildings on the main campus. This work took place from 2013 through 2018. The new Dollar Road
Service Center and the Downtown Network warehouse were completed in 2017 and 2018, and the
new Deer Park Service Center entered into service in 2018. These projects are discussed below in
further detail.

Over the past several years, Facilities has
also dealt with a great deal of change in
their O&M funding allowances, making
managing expenditures more and more
difficult. As an example, in the past,
Facilities would submit O&M projects for
planned maintenance activities each year,
but as O&M Facility’s budgets have
become flat, they no longer have the
funding for planned maintenance.
Discretionary income has been reduced to
nearly zero, meaning most maintenance is
reactive in nature. Often assets are not
repaired or replaced until they fail.
Avista’s Facilities Investments

Figure 14. Facilities Spending Compared to Space Managed
Dollar Road facility under construction
The new Deer Park Service Center

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 22 of 46
Emergency repairs are almost always more expensive than planned work, and when these types of
situations arise, the impact on their already limited budget is significant.

Another major factor in the Facilities O&M budget is the impact of weather. As mentioned earlier,
Facilities does not have available funding for discretionary work. Safety regulations require an entire
plow of sidewalks and parking areas for every inch of snow, which can cost approximately $15,000 per
event just for the Corporate Headquarters, not counting all of the service and customer centers. Snow
removal is allocated an annual budget of $50,000 per year, which is enough to manage about 1.5 snow
events within that year. However, experience has shown that an average winter can result in up to
$220,000 in snow removal costs, which include snow and ice removal from company parking areas for
the safety of customers and employees. Freezing rain requires de-icing and its associated costs as well.
These unpredictable costs often result in Facilities exceeding their budget. There have been times
when the parking lots have required several plowing events within just a few days. In a heavy snow
year, the cost of snow removal and de-icing can add up quickly. As an example, in 2019, almost
$330,000 was spent for snow removal and de-icing for the Mission Campus parking areas, using up not
only the snow removal budget, but the entire yearly unplanned
budget for Facilities.

Expense requests and costs also change over time. For an
example, outlying service centers used to take care of routine
maintenance of their land and buildings themselves, including
plowing their parking lots, but in recent years these activities
have gradually returned to central Facilities. These expenses were
not anticipated or budgeted for, thus they drain funding from
other competing needs. Trying to find the money needed to
match every Terracon-identified issue, employee identified issue,
and unexpected expense that arises is a balancing act. We will try
to describe the processes for trying to maintain this balance
in the next section.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 23 of 46

Capital Project Investment Selection Process

In the Facilities world, the allowed capital budget is quite small, typically between 2% and 5% of the
entire Avista budget, thought this varies significantly based on large projects they are given, such as
building a new service center. The Facilities capital budget includes the Structures and Improvements
program for Asset Condition work. This typically comprises things like replacing a compressor, roof,
shop door or pump as well as remodeling space for improved efficiency or to meet new needs. It also
includes repairing damage from storms or general use. This bucket is wide ranging and varies based on
the conditions Facilities faces every day. Facilities apportions approximately 50% to Asset Condition
work that is identified using Paragon Asset Condition software (Terracon), 30% is set aside for manager
requested projects, and 20% is kept aside for unexpected capital needs and furniture replacements.

Facilities Capital Request Board

Since the Terracon list has been described at length in previous sections, we will now describe the
approval process for capital projects that are proposed by Avista personnel (the 30% allotment).

These types of requested facilities projects undergo a multi-level
internal review process. It begins with the related manager who either
identifies the capital need themselves or is notified of an issue that
needs to be resolved by an employee. If the manager believes the
project is in the best interests of the group and the Company, the
proposal is submitted to that manager’s director. If the director also
sees the value of the request, it is submitted to a group known as the
Facilities Capital Request Board.

This Board meets every fall to review the requested projects for the
upcoming year. Managers from each major business area send a
representative. The employee chosen usually changes every year. In
Avista’s Facilities Capital Investments

Proposed Capital Projects
Approval Process
Manager
Department Director
Facilities Capital Request Board
Facilities Project Steering
Committee
Capital Planning Group
Business Case Primary Driver 2020 2021 2022 2023 2024
New Pullman Service Center Asset Condition $0 $0 $5,000,000 $7,000,000 $0
Service Building Basement Renovation Asset Condition $3,000,000 $0 $0 $0 $0
Structures and Improvements/Furniture Asset Condition $2,000,000 $2,200,000 $2,500,000 $2,750,000 $2,750,000
Central 24 HR Operations Facility Performance & Capacity $0 $0 $0 $10,000,000 $9,000,000
Sandpoint Service Center Performance & Capacity $0 $0 $0 $1,500,000 $8,500,000
Total Facilities Capital Budget $5,000,000 $2,200,000 $7,500,000 $21,250,000 $20,250,000
Total Avista Capital Budget $405,000,000 $405,000,000 $405,000,000 $405,000,000 $405,000,000
% of Total Capital Budget 1%1%2%5%5%
Table 1. Facilities Capital Budget Compared to Avista Capital Budget
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 24 of 46
addition, there is a requirement of at least one person from Environmental Affairs, Operations,
Materials Management, and Facilities. This broad mixture of perspectives is designed to provide a
neutral and “outside” perspective while having access to the
expertise and experience of the directly related and impacted
business entities.

By the time the Board receives the list of requests, it has already
been vetted twice within its related department. The requests
are prioritized based on the Capital Request form19 that was filled
out and approved.

At this level, each request is reviewed for required criteria such
as risk, safety, environmental impact, and compliance. It is
important to note that peer pressure is a very effective tool in
these negotiations. People tend to work in natural silos. A leaking
roof in Colville seems just as important to those employees as a
broken service bay door does to the employees in Colfax. When
the Board members see all of these requests together, the
impacts, cost/benefit, and priority can be examined
comparatively, making it much easier to prioritize them and see
which would have the most positive impact or create the most
value for the Company as a whole. Thus this process is designed to ensure that multiple stakeholder
participation provides a thorough and robust analysis of all facility needs and alternatives across the
Company.

Facilities Steering Committee

For standalone Business Cases, such as the new service building in Deer park, approval comes from the
Facilities Project Steering Committee. This Committee is comprised of directors who are responsible
for approving the submission of all Business Cases to the Capital Planning Group. Before approval, it is
the responsibility of Facilities to make sure each business case includes a description of the business
problem and background on the situation, alternatives,
projected costs, savings, requirements, timelines and
deadlines, benefits, proposals/options and a
recommended solution. Once Facilities has
demonstrated the need for a capital investment, the
Steering Committee will allow the Business Case to
move forward into the Capital Planning Process.

19 A copy of the Capital Request/Business Case Request Form can be found in Appendix B.

•Shared Services
•Information Technology
•Security
•Natural Gas
•Financial Planning &
Analysis
•Generation & Substations
•Corporate Communications
•Environmental Affairs *
•Operations *
•Materials Management *
•Facilities *

* Key Advisors
Business Units
Represented in the
Facilities Capital
Request Board

Chewelah Service Center
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 25 of 46
Capital Planning Group

Once they pass through the processes described above and are approved for consideration, business
cases are submitted to the Capital Planning Group (CPG), a group of Avista Directors that represent
capital intensive areas of the Company. This group is comprised of directors from a variety of business
units to add a depth of perspective, though their role is to consider capital decisions from the
perspective of overall Company operations and strategic goals. Facilities business cases are evaluated
equally with those from Transmission, Distribution, Enterprise Technology, Generation, etc.

The Capital Planning Group (CPG) reviews the submitted business cases from business units across the
organization, including Facilities, and prioritizes funding to meet the upcoming five year capital
spending guidance as set by senior management and approved by the Finance Committee of the Board
of Directors. The CPG meets monthly to review the status of the capital projects and programs,
evaluate changes requested, and approve or decline new business cases. They also monitor the overall
current year capital budget. This group develops and recommends a 5-year capital expenditure plan by
investment driver to the Company’s officers based upon the amount of funding available as approved
by the Company’s Board of Directors. The CPG is responsible for reviewing, approving, deferring, or
denying capital requests, and for appraising productivity and strategic proposals.

Initial expenditure requests may need to be
modified based on the timing of equipment,
permits, available crews, priorities of projects,
etc. The CPG approves or declines these
changes based on managing a total budget
amount. Therefore, as changes occur
throughout the project, project funding may
change, or one project may be funded while
another is removed or delayed to allow higher
priority projects to be funded. This is done
while remaining within the total approved capital spending amount. This group reprioritizes as needed
to ensure that the highest priority projects are identified and funded.

Avista’s Capital Planning Group evaluates aspects such as the project description, alternatives, cost and
other financial assessments, risk, justification, resource requirements, and how each project fits into
the Company’s overall strategies. They provide a comprehensive and strategic perspective that helps
ensure that the right projects are funded adequately at the right time.

Ultimately the individual investments selected to be included in Avista’s final budget represent a
portfolio of projects and funding levels intended to optimize:

1) The overall demand for investment,

2) The specific requirements of the projects and programs proposed for funding, and the potential
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 26 of 46
consequences associated with deferring needed investments, and

3) A balance among the needs and priorities of all investment requests across the enterprise and
the Company’s investment planning principles.

In setting its overall infrastructure spending limits, the
Company considers a range of factors referred as “key planning
principles” as shown in the bubble diagram on the right. The
result demonstrates a reasonable balance among competing
needs required to maintain the performance of Avista’s
systems, as well as prudent management of the overall
enterprise in the best interest of customers.

External factors such as new regulatory or legislative
requirements may drive changes in the plan. The projects in
the Company’s portfolio are continuously reviewed for changes
in assumptions, constraints, project delays, accelerations,
weather impacts, outage coordination, system operations, performance, permitting/licensing/agency
approvals, safety, and customer-driven needs that arise.

Classification of Infrastructure Need by Investment Drivers

Each year Avista makes investment decisions with the goals of maximizing the value of limited funding
and other resources while managing competing requirements and alignment with the Company
mission and values. A variety of projects are proposed for each budget cycle with varying
characteristics.

Avista utilizes a method of organizing infrastructure investments to create more clarity around the
particular needs being addressed with each investment and to simplify the organization and
understanding of overall project plans for the entire Company. This process organizes capital
investments using six classifications of need or “Investment Drivers.” Utilizing the standards and
principles described previously, Facilities develops projects that are within their allocated budget and
that are intended to make best use of the funds they are given. Like the other business units, they
group their requested projects into the appropriate investment driver to help promote understanding
of the basic need related to their requests. The Company’s investment drivers are defined below.

Note that all of Avista’s capital expenditures across the Company can be characterized by one of these
drivers, though not all of the investment driver categories are represented for each asset class. For
example, electric distribution investments encompass all six categories; however, investments planned
for Facilities only utilize two of the six categories: Asset Condition and Performance & Capacity.
Definitions of the others are included here for the reader’s information to help promote understanding
of the Company’s strategic budgeting categorization. It is also important to note that even though not
all of the investment drivers will be used in all of Avista’s primary asset categories in every budgeting
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 27 of 46
cycle, they remain an efficient and effective way of categorizing expenditures in a clear and
transparent fashion that promotes better understanding of how the Company makes business
decisions.

• Asset Condition – All assets have a functional service life. The
Asset Condition category provides funding to replace assets
or portions of assets as needed. This may include replacing
parts as they wear out or when items can no longer meet
their required purpose, as systems become obsolete and
replacement parts are no longer available, if safety or
environmental issues are identified, or if the condition of an
asset is such that it is no longer optimizing its own
performance or customer value and actions need to be taken
to restore the condition of the equipment or replace it. Some
things are so critical that they cannot be allowed to fail.
When these types of items reach an age when they are close
to or at the end of their useful life, the Company preventively
replaces them to maintain reliability and acceptable levels of service. Examples in this category
include everything from building new service centers in Pullman and on Dollar Road as the old
centers have deteriorated and been outgrown, to replacing failing roofs and installing energy
efficient lighting. This broad category for Facilities is called “Structures and Improvements” and it is
comprised of everything from replacing a broken door to purchasing property.
• Performance & Capacity – Programs in this category help ensure that assets satisfy business needs
and meet performance standards. This may include upgrading systems and controls, remodeling
work areas, providing equipment such as cranes for lifting large transformers, spools of conductor
and the like, replacing old and inefficient HVAC and electrical systems, consolidating supplies into a
common area for efficiency and inventory control, security and safety measures, providing
warehouse space, etc. It the other primary driver for the Facilities group.

• Mandatory & Compliance – The Company makes a large number of business decisions as a direct
result of compliance with laws, regulations and agreements, including projects related to air and
water quality permits, equipment essential to legally operating within the interconnected grid,
public safety, contractual obligations, etc. These expenditures are compelled by regulation or
contract and are largely beyond the control of the Company. The Facilities group does not have
money set aside under this category, as their expenditures related to environmental compliance, for
example, are typically part of a larger project belonging to another group and are therefore not
specifically singled out in this category.

• Failed Plant & Operations – This category funds replacement of failed equipment. At times assets
will fail unexpectedly due to damage or an accident or will wear out earlier than expected, but this
category also accounts for equipment that requires periodic replacement. Facilities accomplishes
these types of programs using their Structures and Improvements capital spending category under
the Asset Condition driver.

Figure 15. Facilities Capital Budget
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 28 of 46
• Customer Requested – This category is primarily related to connecting new distribution customers or
large transmission-direct customers. This category is not applicable to Facilities.

• Customer Service Quality & Reliability – This category is set aside for expenses relating to meeting
customer expectations for quality of service and reliability. Typical expenses the Company would see
in this category might include distribution feeder automation which allows isolating the sections of a
line so customers not directly impacted by a faulted section can maintain their service. No funds
were set aside in this budget cycle for Facilities in this investment driver category.

As mentioned earlier, it is easy to push Facilities projects to the bottom of the priority list. Many of the
issues this group deals with are not as obvious as a failed transformer or a broken cross arm. Aging
buildings and structures typically affect only those who work there, and there is a lack of direct
correlation between these failures and/or constraints and providing exceptional service. However,
these issues do impact employees and their efficiency and effectiveness in performing their jobs, as
well as impacting job satisfaction, loyalty and pride. Customers also take note of deteriorated
buildings, sidewalks, and landscaping, which impacts their perceptions about the Company. These
factors, though they may not be directly connected with dollars, are important and have a value. Thus
they are an underlying component of Facilities planning and cost requests.

Recent History Capital Expenditures

Facilities uses their capital funding to
tackle a wide variety of required work.
The general categories are shown in
Figure 16.

The Company’s area service centers are
on a continual track for repairs and
upgrades. All of them made the Terracon
list with at least one item that is
considered “immediate repair required,”
with an average of eight items each and
an average cost of $64,000 to make each
of the required repairs. Repairs are
initiated using a priority process (as described earlier) so the strategy is not necessarily to tackle an
entire service center at a time, but to start with the most pressing needs at each service center as
Table 2. Facilities Capital Projects 2020 - 2024
Figure 16. Primary Capital Expenditures for Facilities 2005-2019
Business Case Primary Driver 2020 2021 2022 2023 2024
New Pullman Service Center Asset Condition $0 $0 $5,000,000 $7,000,000 $0
Service Building Basement Renovation Asset Condition $3,000,000 $0 $0 $0 $0
Structures and Improvements/Furniture Asset Condition $2,000,000 $2,200,000 $2,500,000 $2,750,000 $2,750,000
Central 24 HR Operations Facility Performance & Capacity $0 $0 $0 $10,000,000 $9,000,000
Sandpoint Service Center Performance & Capacity $0 $0 $0 $1,500,000 $8,500,000
TOTAL $5,000,000 $2,200,000 $7,500,000 $21,250,000 $20,250,000
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 29 of 46
determined by safety, customer service, and impact on the business based upon Terracon’s risk rating
system or as determined by the Steering Committee.

The “miscellaneous” category shown on the pie chart includes a broad spectrum of capital projects,
including security expenditures like fencing, cameras, and fire suppression systems, parking lot repair
or improvements, and storage solutions to name a few. In the recent past, this category included the
cost to reroute North Crescent around the Mission Campus as an example.

Structures and Improvements is an ongoing category that includes capital maintenance, site
improvement, and furniture and equipment budgets at over 40 Avista offices, storage buildings, and
service centers. It includes major repairs such as leaking roofs, control systems, and floors; replacing
equipment such as air conditioners, windows, generators, pumps, and lighting; installing sprinkler
systems, handrails, exterior siding, and condensers. It also includes larger-scale projects such as
remodels and renovations such as adding covered storage areas and warehouse space. Items can range
from purchasing a cash register that cost about $100 for the cafeteria to a completely new HVAC
system for the Corporate Headquarters building that cost over $22 million.

Avista’s buildings range in age from the late
1800s to today, and many are facing the
associated age challenges. The HVAC category
focuses on replacing end-of-life heating and
cooling systems in older facilities with new
energy efficient systems. Most of this work over
the past ten years was performed on the
Company’s buildings in Spokane, but several
outlying service areas have also been updated.
This effort will continue into the future as aging
and end-of-life systems are replaced and
upgraded to help save energy costs. In the
current budgeting cycle, it is expected that
expenditures will follow a very similar pattern
Figure 17. Square Footage of Avista Facilities Managed
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 30 of 46
for Facilities capital spending with the exception of the Mission Campus, for which the long-term
upgrade is nearly complete.

Over the past ten years, the main campus has
undergone updates, renovations, additions, and
repairs which are being finalized this year. The
Corporate Headquarters building, completed in
1959 and designed by famed architect Kenneth
Brooks, has undergone extensive upgrades. The
Mission campus and associated buildings
comprise nearly 60% of the Company’s buildings
and infrastructure, so this was a very large
project. The Corporate Headquarters building was
renovated one floor at a time, upgrading
outdated heating, cooling, electrical and plumbing systems, remodeling the
existing space to increase usage efficiency, and removing asbestos. Avista
applied its own energy management
practices to this restoration, which
earned them a BOMA 360
designation, LEED Gold Certification,
and achieved significant energy
savings of more than $350,000 per
year in electricity costs (depending upon the weather) plus
nearly an 82% reduction in water usage, all due to energy
and water efficiency measures included in the remodel.

This large long-term project included replacing several old outbuildings with new buildings able to
provide service for today’s larger trucks and equipment, as well as renovating storage areas to more
effectively manage the supplies and equipment the Company requires to serve customers (such as
transformer and pole inventories). When the campus parking structure is finished in 2020, the ten-year
Mission Campus Plan should be complete and this project will no longer require a large percentage of
Facilities capital budget.

One of the highlights of the Mission renovation
is the new Service Building on the campus,
which now allows Avista to efficiently service
and maintain their own fleet of trucks and
vehicles rather than having to use outside
maintenance sources, which are far more
Mission Campus Buildings
Main Campus Parking Structure When Completed
Headquarters 381,110
Warehouse 35,000
Investment & Recovery 13,200
Waste & Asset Recovery 15,000
Ross Park 17,000
Line Dock 28,750
Covered Areas/Canopies 8,000
Fleet Building 30,000
Parking Garage 171,000
TOTAL SQUARE FEET 699,060
Mi
s
s
i
o
n

C
a
m
p
u
s

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 31 of 46
expensive.20 It also provides space for storing valuable vehicles and equipment inside an enclosed and
secure area.

The Fleet Building is a great example of the creative and efficient ways the Facilities Group manages
projects. To design the new Fleet building in a way that maximizes its effectiveness, the Facilities team
put together a Business Process Improvement (BPI) team. This team observed existing workflow and
processes. They watched Fleet employees performing their jobs,
specifically how they maintained vehicles in the existing building.
They interviewed personnel on what would make their work more
efficient and safer. They drew a “spaghetti” diagram of existing work
flows showing, for example, how many times an employee had to go
to the back of the building to get supplies and how long that took.
They toured other fleet operations facilities to glean best practices.
At the end of this process, and with extensive input from Fleet
personnel, a building was designed which stayed in budget
while providing a state-of-the-art facility that has become an
example for other fleet buildings around the country.

In this new building, personnel have the capability of adding or
removing booms, buckets, and accessories as needed, there
are pull-through lanes to increase safety,21 parts and fluids are
located directly adjacent to each of the maintenance bays
(rather than in the back of the building), safe wash bays were
added,22 doorways are wide enough to fit today’s larger
vehicles,23 and lifts are included that can be quickly adapted to
fit a variety
of vehicle
sizes. The
Company is
adding
20 According to AAA most auto repair shops charge between $47 and $215 per hour for auto repair only, not specifically for the large and specialized
vehicles Avista utilizes, which can cost much more.
21 Prior to pull through lanes, trucks had to back out into a tight turnaround area with a number of flaggers on hand to direct them so they didn’t back into
anything or anyone.
22 This may seem like a trivial thing, but one of the ways Avista strives to keep their vehicles well cared for includes cleaning them. In the past, this was
done by an employee with a spray hose on a ladder, an obvious safety concern. The new wash bays have decks all around them on the second story of
the building, allowing employees to clean the largest rigs safely.
23 The previous fleet building literally had one inch of clearance on either side for many of the Company’s largest work trucks; many would not fit inside.
Our largest vehicles can fit into the Fleet Building for
maintenance & repair

New Fleet Building wash bay and service areas
(above)
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 32 of 46
Compressed Natural Gas vehicles to its fleet, and the new building provides the capability of servicing
these specialized vehicles as well. Energy efficiency was also a major consideration. Rather than heat
this large open space with traditional HVAC systems, in-floor heating was chosen. This system keeps
the work areas warm at far less cost. The new Fleet building can service Avista’s largest vehicles inside
an enclosed area rather than out in the parking lot. Employees state that having their tools readily at
hand saves them hours of work every month and has greatly enhanced employee satisfaction.

Facilities Budgeted Capital Projects By Business Driver

Asset Condition Projects/Programs

During this budget cycle, Facilities has three projects in the Asset Condition category, including general
structures and facilities improvements, renovation of the existing Mission Campus Service Building,
and building the new Pullman Service Center. These projects are described in detail below.

Pullman Service Center

The Pullman Service Center was constructed in the 1950s,
and although it has experienced upgrades, remodels, and
additions since that time, it has been outgrown for today’s
needs and size of equipment. The current center provides
support to nearly 41,000 natural gas and electric
customers scattered over some 5,000 square miles. Forty
one employees work out of this facility. The Pullman area
is one of the fastest growing in Avista’s service territory,
significantly increasing the workload requirements of the
crews there as well as the amount of equipment needed
onsite.

The current facility is simply too small to efficiently and
effectively support employees in serving customers. Supplies
are scattered across a variety of storage areas around the
Pullman area, not onsite. Expensive company vehicles have
no protected parking areas and today’s large work vehicles
Table 3. Facilities Planned Asset Condition Budget

Asset Condition 2020 2021 2022 2023 2024 Five Year
Total
Five Year
Average
New Pullman Service Center $0 $0 $5,000,000 $7,000,000 $0 $12,000,000 $2,400,000
Service Building Basement Renovation $3,000,000 $0 $0 $0 $0 $3,000,000 $600,000
Structures and Improvements/Furniture $2,000,000 $2,200,000 $2,500,000 $2,750,000 $2,750,000 $12,200,000 $2,440,000
Total $5,000,000 $2,200,000 $7,500,000 $9,750,000 $2,750,000 $12,200,000 $5,440,000
Above: Pullman break room/meeting room/work area
Below: One of the many Pullman storage areas
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 33 of 46
cannot fit into the existing shop for maintenance.
There is also insufficient space for employee work
areas.

A third-party assessment found that the building
suffers from a serious need for repairs to the
electric, water, plumbing and septic systems, roof,
floors, and ceilings. The shop roll-up doors
(original to the building) have become a safety
concern for both employees and the vehicles that
use them. There is no fire system in place at all.
This independent survey identified over $5 million
in repairs needed to continue to utilize the original
building.

Analysis determined that it made more fiscal sense
to let go of the concept of trying to invest in the
old building and start again with a new, larger,
more efficient facility that will provide the services
needed to best serve customers. It will include space for all of the Pullman crews and their functions to
be located in one central location. It also provides a materials yard large enough to hold and organize
all of the equipment crews need to perform their jobs in one location, which is especially important in
an outage situation where quick access to supplies can directly shorten customer outages. Employees
will be located in a clean, safe work space with room for both offices and maintenance areas.

Safety is also a major consideration. The new location will not be located on a major highway, unlike
the existing facility, which has an entrance that requires entering and exiting onto a 55 mph highway.
Trucks pulling large equipment onto that roadway can be terrifying for both Avista crews and passing
motorists as well. The new location will also provide environmental benefits, with storm water
protection and oil containment measures.

Service Building Renovation

The Gas Meter Shop was located on the Mission Campus in the Service Building, which is attached to
the corporate office building. It was recently relocated to Dollar Road, leaving 13,000 square feet of
total vacated space in the basement of the Service Building. The design and use of the vacated space
will need to be determined. There are a number of space requests that Facilities has received and
these needs will be evaluated to determine the best solution for developing that space. Regardless of
the option chosen, capital expenditures would likely include HVAC, electrical, plumbing, lighting,
sprinkler systems as well as asbestos abatement and wall construction.

Current Pullman Service Center Highway Location
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 34 of 46
Possible solutions being explored for this space include:

• Work Space - Facilities has found itself in continual need of space. Included in this request would
be workstations, offices, conference rooms and a breakroom. There are currently no enclosed
offices open within Mission Campus, with a mix of open area workstations scattered
throughout the General Office Building. It is possible that there will be more need for offices
and office space in the future.
• Meeting Space - Facilities has received many requests for large meeting rooms for 50 or more
employees. Currently the only room that can accommodate a crowd of this size is the
Auditorium, which is not an effective meeting space.
• Training Space - There is an increasing need for additional training areas, especially given
increasing mandatory training requirements, many in the craft area. The Jack Stuart Center has
limited training room available and is only available when not being utilized by the Line School.
The Service Building location could be designed to accommodate both training and multi-
purpose events.
• “MakerSpace” – This is a collaborative work space for making, learning, exploring and sharing
ideas which would allow employees to work on projects together.
• Increase Wellness Center - There have been many requests to expand the current Wellness
Center, perhaps including a multi-purpose room to offer larger classes and provide additional
workout equipment.

Structures and Improvements

As described earlier, this program is responsible for the capital
maintenance, site improvement, and furniture budgets at all of
Avista offices, storage buildings, and service centers. There is money
budgeted in this category each year; it is an ongoing program. Its
purpose is to systematically evaluate the condition of all the
Company’s facilities and develop plans and
strategies for functionality while being cost-
effective. Part of these expenditures are driven by
the Terracon condition study, and part are
determined via an internal Facilities Condition
Assessment Survey, which takes into account the
condition, lifecycle costs, age, functionality, and
criticality of each facility and ranks their needs
accordingly.

The work in this category may include repairing or replacing a roof, replacing asphalt, concrete or old
furniture, repairing broken structural elements, adding security features such as fencing and gates,
augmenting materials storage areas, installing irrigation systems, replacing a boiler that fails,

Above: Roof
repairs needed

Left: A line
truck impedes
a stairway in
order to fit
inside a service
bay

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 35 of 46
purchasing emergency generators, or
replacing old and inefficient electric or
plumbing systems. It can also include
work improvement elements such as
adding a crane to safely lift heavy
equipment, shelves to store maintenance
materials closer to work areas, or adding
ergonomics to improve productivity. One
focus area is for canopies, the covered
areas used to shelter trucks and
equipment. Many of these have become
unstable over time and require
replacement.

Employee efficiency is also a tangible benefit of adequately maintaining facilities. The turnaround time
for performing routine maintenance on a line truck for example, can be reduced significantly if tools,
supplies, and equipment are readily available. Even simple things like having a truck lift that allows the
crew to move freely underneath the vehicle to perform maintenance and repairs quickly reduces
downtime and increases vehicle availability.

In order to continue to function, buildings must be maintained. The Company recognizes that letting
assets fall into disrepair ultimately impacts the ability to provide the best possible customer service,
creates safety risks, and ends up costing much more in the long term. The goal of the Structures &
Improvements program is to adequately maintain Company properties
while trying to keep
costs low as well as
remain within the
Facility allotted
budget.

Above: Mission Campus canopy buildings
Facilities work involves complex
systems like those above and on the
left as well as historically significant
assets such as the Steam Plant in
Downtown Spokane (far left)
Figure 18. Facilities Structures & Improvements Capital Budget & Actuals
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 36 of 46
Performance & Capacity Projects

The current budget cycle has two Performance and Capacity projects: construction of a 24-hour
Operations Facility and a new service center in Sandpoint. These projects are described in detail below.

Central 24-Hour Operations Facility

Avista is a 24-hour a day operation. Employees from Transmission, Delivery, Information Technology,
Security, Customer Service, Electric and Gas Dispatch, SCADA and Operations are on the job constantly
to ensure the integrity of Avista’s systems, continual
customer service and that customer load
requirements are being met every minute of the
day. At Avista, the current location for both System
and Distribution Operations is the fourth floor of the
Corporate Headquarters building.

The existing Distribution Operations area is
congested, in great part due to the large number of
computer screens required to monitor distribution
system conditions and handle daily distribution
operations, as well as deal with outages and
emergency situations. This group is also responsible
for dispatching crews for maintenance activities or
to address issues. Distribution Operators work 12-
hour shifts, 24 hours a day, every day. As they hand
off their work to the next Operator on shift, there is
no room at the desk for the incoming Operator to sit
beside the on-shift Operator to be brought up to
speed on current conditions. In addition, there is no
space in their area for training or to utilize when
they bring in additional personnel and expertise
during events such as storms.

Table 4. Facilities Planned Performance & Capacity Budget
Above: Distribution Operations tight workspace

Below: Work space conditions when extra personnel are
brought in for emergencies

Performance & Capacity 2020 2021 2022 2023 2024 Five Year
Total
Five Year
Average
Central 24 HR Operations Facility $0 $0 $0 $10,000,000 $9,000,000 $19,000,000 $3,800,000
Sandpoint Service Center $0 $0 $0 $1,500,000 $8,500,000 $10,000,000 $2,000,000
Total $0 $0 $0 $11,500,000 $17,500,000 $29,000,000 $5,800,000
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 37 of 46
System Operations faces a similar situation, primarily due to regional and federal issues. They are
regulated by the North American Electric Reliability Corporation
(NERC). NERC oversees developing and supporting standards
related to the entire American interconnected grid as the
regulatory body for all U.S. utilities. NERC requires all System
Operators to be certified and regularly pass a national test, which
requires continuous training. Currently the training area is the
Training Coordinator’s office, which allows room for only 3-4
additional employees at a time, making it difficult to adequately
provide required employee training in a timely fashion.

In addition, in April 2022 Avista will be joining the Western
Energy Imbalance Market (EIM),24 which will heavily impact
System Operations in both workload, training, and space
requirements. This Market encompasses about 75% of the loads
and resources in the Western Interconnection, providing Avista
(and its customers) additional buying and selling power in the
Western energy market. The EIM provides a number of
advantages for its participants which will directly benefit Avista
and its customers. The
Western EIM’s state-of-the-art technology automatically finds
and delivers the lowest cost energy to serve more than 42
million consumers in eight western states and parts of
Canada. In addition to optimizing diverse resources from a
larger pool (which lower costs for all participants) the EIM
provides environmental benefit by spreading intermittent
renewable energy integration across the Western U.S., helping
more renewable energy assimilate into the
system. The broad base of participating utilities
allows Avista, for example, to purchase excess
low-cost California solar energy when that
state’s customer demand levels are low but
Northwest loads are high. The decision by
Avista to become part of this system has
obvious and tangible benefits to customers,
including access to a broad, diverse resource
pool, more opportunities to access low cost
power, ability to leverage the diversity of loads
and demands across the region (i.e. selling
24 The Western Energy Imbalance Market (EIM) is administered by the California Independent System Operator (CAISO). For more information, see
https://www.westerneim.com/pages/default.aspx
Above: One desk in System Dispatch: note the
number of required screens and space needed

Below: The current training area
Year Curtailment
Avoided (MWh)
CO2 Emissions
Avoided (metric
tons)
2015 31,082 13,220
2016 328,238 140,486
2017 161,097 68,951
2018 194,988 83,455
Total 715,405 306,112
Western Energy Imbalance Market Benefits
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 38 of 46
energy to a southern utility when it’s loads are peaking, then buying back from them when Avista’s
loads are high in the same day or even across seasons.) In addition, this forum provides increased
access to renewable energy that is expected to be required in the near future by the Washington
Legislature.25

In order to integrate the complex requirements
of this new market into existing Company
operations, changes will be required in the way
the Company manages the real time system. This
will require an estimated 13 additional personnel
in System Operations.26 The space for the current
critical Operations functions has been maximized
for the existing staff. These additional positions
will require more space than is available without
a significant remodel, moving other employees,
or moving this entire group to a new location.
These specialized employees also require
additional equipment beyond the typical
employee, for example, extra space for computer
monitors (some of these positions utilize 8 to 12
large screens or more for monitoring the system
and operating conditions), and therefore require
significantly larger workspaces than a typical
employee.27

System and Distribution Operations are the nerve center of the
utility, controlling the distribution, transmission and generation system in real time. These employees
perform a critical function, operating Avista resources in balance with the energy market to ensure
that resources exactly meet load requirements for customers every minute of the day. Utilities often
separate these critical 24-hour operations from their headquarters for security reasons, typically
locating these key people and associated systems in unmarked locations, as the disruption of this
group could be devastating to system operations, reliability, and stability. The change in manpower
requirements associated with the EIM creates an opportunity to move System Operations to a more
secure and anonymous location. At the same time, this project would enable providing an upgrade to
25 Western Energy Imbalance Market chart from their home page: https://www.westerneim.com/pages/default.aspx
26 System Operators are mandated by NERC Standards to ensure that frequency, voltage, interchange and system stability are within acceptable ranges
and to respond to emergencies accurately and within a specified time frame. System Operators must respond to ever-changing conditions of normal
operations and emergency conditions due to weather, equipment malfunctions, public accidents and even vandalism and sabotage. They ensure that
adequate resources are available to meet customer load demands within Avista’s system, and to guarantee that Avista is adequately managing its part of
the Western Interconnection. The new positions will manage the Company’s participation in the EIM.
27 This is true for both Distribution Operations and System Operations. It is estimated that an additional eight workstations will be required for the new
System Operators as these are 24-hour positions served in 12 hour shifts.
Current Energy Imbalance Market
Participants surrounding Avista

Current Energy Imbalance Market
Participants surrounding Avista
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 39 of 46
the technology used by these employees to monitor and control grid operations and to incorporate the
new systems required for Avista to integrate into the Western Energy Imbalance Market.

Another important consideration in the physical location of the operations-related employees is that
the Federal Energy Regulatory Commission (FERC) Standards of Conduct Requirements demand
separation between electric and natural gas transmission system employees and wholesale operations
employees.28 Due to the changing nature of FERC’s Standards of Conduct regulations over time, most
utilities have taken a conservative approach in ensuring they are in compliance with this mandate.
They have found that it can become extremely complex to adequately separate these employees if
they are in the same building. Structural and physical separation and information technology network
controls have not always been sufficient. Moving Avista’s System Operations offsite would mitigate any
risk of non-compliance with FERC Standards of Conduct now and in the future, as well as address the
current space limitations.

Sandpoint Service Center

The Sandpoint Service Center dates to the 1950s. It was acquired by
Avista when the Company took over PacifiCorp’s electric operations
there in 1996. This area is experiencing a high level of growth, with a
rate of 2.9% from 2017 to 201829 compared to about 1.8% growth in
Spokane over the same time period,30 spurred in
part by some great publicity for Sandpoint such as
being named “Best Small Town” by both Sunset
Magazine and USA Today.31 Over time the Company
has outgrown the Sandpoint facility. The existing
storage area does not have room for all of the
inventory required to keep up with current work
demands, and there is no adjacent property
available for expansion. The Sandpoint storekeeper
has become incredibly inventive, utilizing every
spare nook and cranny in the facility, but that makes it difficult to track
and manage inventory effectively. To add to the storage issue, the
Sandpoint area has a unique voltage level which differs from the rest of Avista due to its development
by another utility. This requires unusual materials and supplies that cannot be acquired from other
district offices and so must be stored onsite in Sandpoint.

28 “FERC Standards of Conduct and Business Support Functions,” FindLaw, https://corporate.findlaw.com/litigation-disputes/ferc-standards-of-conduct-
and-business-support-functions.html.
29 World Population Review 2019, http://worldpopulationreview.com/us-counties/id/bonner-county-population/ /
30 World Population Review 2019, http://worldpopulationreview.com/us-counties/wa/spokane-county-population
31 “Best Small Town: Sandpoint, Idaho,” Sunset Magazine, https://www.sunset.com/travel/northwest/best-small-town-sandpoint-idaho-0 and “USA Today,
Rand McNally name Sandpoint most beautiful small town in America,” Coeur d’Alene/Post Falls Press, https://www.cdapress.com/archive/article-
763b3f51-0162-5d6f-a396-093d843e5552.html

Sandpoint Office
cracked walls, end-of-
life bay doors and
HVAC equipment

Sandpoint Office
cracked walls, end-of-
life bay doors and
equipment
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 40 of 46
Safety concerns at this facility are very real. There are no exit lights or smoke detection systems. The
yard is so small that there are both vehicle and employee safety issues as vehicles attempt to
maneuver into and out of the yard and up to the loading dock. Some of the roll up loading bay doors
are damaged beyond repair, the lighting must be upgraded, the roof requires repair, the windows must
be replaced, the concrete sidewalks and asphalt parking areas are cracked and pitted, the fences are
broken in places, there are security issues, and
the list goes on. Many of the building’s systems,
including electrical and HVAC, are antiquated
and inefficient and some violate current code
requirements.

Sandpoint also has some unique environmental
concerns. A creek runs through the Service Center property that floods in the spring, inundating the
pole yard with water. This close proximity to water sources that drain into area waterways demands a
higher level of accountability, especially with Avista’s environmental focus. This highly utilized service
yard contains trucks and equipment that by their nature experience leaks and create mud and runoff
that cannot be adequately contained with the current set up.

This area also experiences some of the highest amounts of snowfall in Avista’s service territory,
averaging about 58 inches of snow per year.32 A great effort goes into removing snow from work
vehicles before they can go out into the field because there are
not adequate places for Company vehicles to be sheltered. In
fact, one of the old shelters collapsed in 2017 due to snow
loading and poor construction. Recently another vehicle
suffered significant damage due to ice unloading from an Avista
storage area due to lack of covered vehicle spaces.

The Company proposes acquiring a new site (not located on a
major highway) upon which to construct a new service building,
line dock, storage yard, warehouse, and covered storage areas
for vehicles and equipment. This will include energy efficient
heating and cooling systems, security and fire systems, plus
adequate room for employees and maintenance operations. One
of the focus areas will be on environmental protection, with storm water management, oil handling
facilities, and protected transformer storage, ensuring compliance with legal and environmental
regulations. Another key benefit will be in bringing all of the Sandpoint area employees together in one
location along with the supplies and equipment they need to most capably perform their jobs. The
existing facility will be sold to help offset the cost of the new location.

32 https://www.bestplaces.net/climate/city/idaho/sandpoint
Covered parking would be great! At times,
vehicles must be shoveled out before use
Overcrowded storage area
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 41 of 46

Since 2005 the Company has spent an average of $4.3 million on Facilities operation and maintenance,
divided into sections based on expected levels of need. O&M spending pays the utilities at every site,
including electricity, water, sewer, garbage pickup, and natural gas service. It also funds repairs for
leaking roofs, energy
management audits and
upgrades, grounds keeping, office
supplies, building supplies such as
lights and toilet paper,
coordinating employee moves,
and managing office space, to
name a few. To add further
complexity, the definition of what
can be considered capital has
become more restrictive, forcing
more requests into the limited
O&M category. As shown in
Figure 19, not only has Facilities
kept their O&M budgets fairly
flat, but they have stayed very
close to their budget allocation even with the variability they face in this category of spending.

Facilities Operations and Maintenance work is separated into two categories, discretionary and non-
discretionary. Discretionary work is maintenance not related to asset lifecycle or safety, such as carpet
cleaning, general equipment maintenance, exterior upkeep, asphalt repairs and painting. Non-
discretionary spending is primarily related to safety. This includes maintenance of elevators, fire
systems, and lighting as well as snow and ice removal. It also includes building automation,
janitorial/cleaning services, and utilities such as electricity and sewer. Due to budget limitations,
facilities is often forced to choose not to do sustaining maintenance and instead “run to fail” those
particular assets that do not fall under the category of public or employee safety. General operating
costs such as utility bills have continually increased, requiring Facilities to postpone or eliminate more
and more maintenance projects in order to stay within their allocated budget.

The Terracon (and industry standards) recommended spending levels for simply sustaining a
company’s facilities and meeting the basic needs (such as providing utilities) should be between 2-4%
of the value of those facilities.33 In Avista’s case, their infrastructure value has been placed at
$241,515,515, meaning the minimum sustainability O&M facilities spending level should be between
33 “Budgeting for Facilities Maintenance and Repair Activities,” National Academy of Sciences, Engineering, and Medicine,
https://www.nap.edu/read/9226/chapter/3
Figure 19. Facilities O&M Budget and Actual Spending
Avista’s Facilities O&M Investments

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 42 of 46
$4.8 million and $9.6 million per year. As
mentioned earlier, the total funding for Avista
Facilities O&M budget is about $4.3 million on
average, somewhat lower than the lowest
recommended percentage, but that is somewhat
misleading. The industry standard number
assumes that this funding will sustain buildings,
that is, provide preventative maintenance. Almost none of
Avista’s O&M money is spent for preventative work unless
replacement of filters is included. Most of this money
instead goes to paying for basic utilities.

To add complexity, analysis of Facilities investments is not
necessarily as straight-forward as other assets can be, as they are
dealing with so many variables. The buildings this team manages are a variety of ages and are
comprised of a variety of materials. For example, the Clarkston Service Center has an exterior made of
wood rather than composite siding or brick. It has been in serious need of repainting for quite some
time and, as a result, has suffered weather damage. Because Facilities was unable to do proper
maintenance over time, the cost to make this repair is now significantly higher than it should be,
costing an estimated $60,000, which is not manageable in the current funding model. Thus this work,
though it needs to get done, continues to fall back on to the “to do” list or “fun to fail”.

For another example, many of the Company’s parking areas have broken curbing, pot holes, and
cracks. Though these problems can cause safety issues, there is not enough funding to address them
all. Facilities does its best to care for all of its assets, but this team is constantly fighting an uphill battle
in trying to stay ahead of the need.
Ritzville Service
Center exterior
(above) and
interior (right)

Figure 23.
Facilities
O&M
Expenditure
s vs. Square
Feet
ManagedRitz
ville Service
Center exterior
(above) and
interior (right)
Figure 20. Avista O&M Spending vs. Industry Recommended Levels
Avista parking area & sidewalk

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 43 of 46

It is quite possible that Facilities is the most underrated and least appreciated team at Avista, which is
somewhat understandable. Every employee utilizes dozens of Facility assets in their daily work lives,
from parking lots to cubicles, bathrooms, water fountains, break areas, truck maintenance facilities,
conference room technology, heating, cooling, and the like. We benefit from cleaning services, mowed
and green lawns, exercise facilities, security, and so much more, but most are not really cognizant of
the effort it takes to provide these routine services. Employees just naturally expect to have them,
much like customers, who don’t really pay much attention to the convenience of their electric power
until there is an outage.

Facilities uses the best technology and information available to them to try to manage their buildings
with the lowest cost and highest efficiency. When given money, this group focuses on using it to
provide both long term value and customer benefits. As shown here, they have very little funding;
thus, it is in the very best interests of all parties that this money is used wisely.

The Terracon study provides invaluable insights into areas of highest need for replacement or repair,
which provides great assistance in delegating funds to get the most possible value. Facilities also
utilizes automated building management systems to track building operations and help identify
recurring problems and trends which should be addressed. The Facilities team is always on the go.
There is never an end to the need to repair or replace something in their 1.2 million square feet of real
estate. It is important to note that they do this extremely successfully given their limited funding. They
are operating at about half the recommended national staffing level for facilities per square foot, with
approximately half the amount required to effectively maintain facilities according to national
standards, and with almost no O&M budgets or discretionary funding for handling unexpected
expenses such as a heavy snowfall or a failed HVAC system. Their O&M expenditures often go over
budget, much to their chagrin, because they simply cannot predict when something might fail and
must be repaired or replaced.

Even with all of the efficiencies the team has developed and creative solutions they employ, there is a
consequence to running at such lean manpower and funding levels. Many basic objectives cannot be
achieved. Buildings simply cannot be sustained at the level they should be, which leads to early
deterioration and, eventually, higher costs to repair or replace. Systems cannot be maintained
adequately without preventative maintenance needed for the assets to achieve their optimum lifecycle
and provide the most economic value. Employees cannot reasonably be expected to continue to do
their best work under constant criticism and frustration. This situation is simply not sustainable and is
ultimately not in the best interests of the Company or customers.

Summary and Wrap-Up

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 44 of 46

Appendix A: Awards

The Facilities Group raised over
$10,663 for the Second Harvest
Foodbank in 2019, enough for
53,000 meals

Snow Removal Costs at Mission
Campus in 2019
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 45 of 46
Appendix B: Capital Request Form

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 8, Page 46 of 46
Exhibit No. 11, Schedule 9
Capital Investment Business Case Justification Narratives Index
Business Case Name
Page
Number
Distribution
Elec Relocation and Replacement Program 3
Joint Use 10
Saddle Mountain 230/115kV Station (New) Integration Project Phase 2 17
Electric Storm 24
Meter Minor Blanket 31
Distribution Grid Modernization 37
Distribution Minor Rebuild 49
Distribution Transformer Change Out Program 58
LED Change-Out Program 66
Primary URD Cable Replacement 75
Substation - Station Rebuilds Program 79
Wood Pole Management 86
Wildfire Resiliency Plan 98
Distribution System Enhancements 108
Transmission
Rattlesnake Flat Wind Farm Project 115kV Integration Project 122
Clearwater Wind Generation Interconnection 125
Colstrip Transmission 132
Protection System Upgrade for PRC-002 140
Saddle Mountain 230/115kV Station (New) Integration Project Phase 1 146
Transmission Construction - Compliance 149
Transmission NERC Low-Risk Priority Lines Mitigation 159
Tribal Permits & Settlements 164
Use Permits 171
West Plains New 230kV Substation 177
Westside 230/115kV Station Brownfield Rebuild Project 184
Spokane Valley Transmission Reinforcement Project 191
SCADA - SOO and BuCC 198
Transmission - Minor Rebuild 205
Transmission Major Rebuild - Asset Condition 211
Substation - New Distribution Station Capacity Program 221
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 1 of 414
Natural Gas
Gas Cathodic Protection Program 228
Gas Facility Replacement Program (GFRP) Aldyl A Pipe Replacement 231
Gas Isolated Steel Replacement Program 243
Gas Overbuilt Pipe Replacement Program 246
Gas PMC Program 250
Gas Replacement Street and Highway Program 257
Gas HP Pipeline Remediation Program 260
Gas Non-Revenue Program 263
Gas Regulator Station Replacement Program 268
Gas Rathdrum Prairie HP Main Reinforcement 276
Gas Reinforcement Program 281
Gas Telemetry Program 288
Jackson Prairie Joint Project 292
General Plant
Apprentice/Craft Training 295
Capital Tools & Stores 300
Fleet Services Capital Plan 311
Structures and Improvements/Furniture 326
Telematics 2025 342
Oil Storage Improvements 353
Campus Repurposing Phase 2 362
Gas Operator Qualification Compliance 382
Strategic Initiatives - Clean Energy Fund 2 388
Strategic Initiatives - Clean Energy Fund 3 393
Strategic Initiatives - Scott Morris Center for Energy Innovation Tenant
Improvements 399
Strategic Initiatives - Real Time Power System Simulator (RTS) 404
Strategic Initiatives - Upriver Park Development 410
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 2 of 414
Electric Replacement and Relocation
Business Case Justification Narrative Page 1 of 7
EXECUTIVE SUMMARY

The Electric Replacement and Relocations (Road Moves) program is driven by compliance mandated by
the “Franchise Agreement” contracts with local city and state entities and “permits” issued by Railroad
owners. Within each agreement are provisions for relocation of utilities at the request of the right-of-way
(ROW) owner. Under a Franchise Agreement or Permit, Avista is allowed to occupy space within a ROW
owned by the respective jurisdiction in order to serve its customers. Electric relocations occur every year
during the construction season, but are unplanned, so historical trends are used to estimate the annual cost
to fully fund all the relocation projects. The annual costs of electric relocations have very little variance year
to year, therefore fully funding the business will likely ensure all electric relocations under Franchise
Agreements or Permits will be completed. This is mandatory work to maintain compliance with existing
franchise and operating permits with state highway districts and railroads. This impacts WA and ID
Customers.

The Electric Relocations business case is unplanned and demand driven work, contractually obligated, and
adds high risk to the company if not completed. Funding allocation is based on historical spending trends.
The average historical spend for Electric Relocation over five years is $2.7 million (three-year average =
$3.1 million). Because electric relocations are directly correlated with the number of highway and street
projects, the reason for the upward trend in spend is likely an increase in transportation project spending.

VERSION HISTORY
Version Author Description Date Notes
Draft Amy Jones Initial draft of 2020 Business Case Refresh 6/30/2020
1.0
1.1
2.0

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 3 of 414
Electric Replacement and Relocation
Business Case Justification Narrative Page 2 of 7
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The Electric Distribution and Transmission Replacement and Relocations (Road Moves)
program is driven by compliance mandated by the “Franchise Agreement” contracts with local
city and state entities and “permits” issued by Railroad owners. A “Franchise Agreement”
generally refers to a non-exclusive right and authority to construct, maintain, and operate a
utility’s facility using the public streets, dedications, public utility easements, or other public ways
in the Franchise Area pursuant to a contractual agreement executed by the City and the
Franchisee. Although each Franchise Agreement or permit is a little different, they all serve a
similar purpose in providing utility access along city, county, state and railroad right-of-way
(ROW). The agreement(s) make provisions for Avista to install electric equipment along these
ROW’s in order to provide service to Avista customers.
Within each agreement are provisions for relocation of utilities at the request of the ROW owner.
These requests are usually driven by road and or sidewalk re-design projects.
For reference, franchise 95-0990 recorded with Spokane County paragraph VI states “If
at any time, the County shall cause or require the improvement of any County road,
highway or right-of-way wherein Grantee maintains facilities subject to this
franchise by grading or regarding, planking or paving the same, changing the grade,
altering, changing, repairing or relocating the same or by constructing drainage or
sanitary sewer facilities, the grantee upon written notice from the county engineer
shall, with all convenient speed, change the location or readjust the elevation of its
system or other facilities so that the same shall not interfere with such County work
and so that such lines and facilities shall conform to such new grades or routes as
may be established.”
For example, a State Department of Transportation (DOT) is widening an intersection or
highway, which requires Avista to relocate their overhead or underground electric facility
to accommodate the new DOT design. A smaller example for instance is a local
municipality is installing new ADA ramps on the corners of local street intersections, which
sometimes requires Avista to relocate a utility pole to accommodate the new ramp design.
The asset conditions replaced through Electric Relocations can vary since the relocations are
unplanned and therefore not coordinated with Avista’s Asset Maintenance programs. Most
assets in an Electric Relocation project are replaced because they are unsalvageable and close
to their useful life. In the case of relocating newer assets, efforts are made to re-use as much
material as possible.
Requested Spend Amount $3,000,000 annually
Requested Spend Time Period Ongoing Program
Requesting Organization/Department Electric Operations
Business Case Owner | Sponsor Amy Jones | David Howell
Sponsor Organization/Department Operations
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 4 of 414
Electric Replacement and Relocation
Business Case Justification Narrative Page 3 of 7
Under a Franchise Agreement or Permit, Avista is allowed to occupy space within a ROW owned
by the respective jurisdiction in order to serve its customers. Electric relocations occur every
year during the construction season, but are unplanned, so historical trends are used to estimate
the annual cost to fully fund all the relocation projects. The annual costs of electric relocations
have very little variance year to year, therefore fully funding the business will likely ensure all
electric relocations under Franchise Agreements or Permits will be completed.

1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
This major driver of this business case is Mandatory & Compliance. Franchise agreements,
typical state highway and railroad permits, and DOT prescribe that the utility will relocate at their
expense when in conflict with entity activities. Mandatory work to maintain compliance with
existing franchise and operating permits with state highway districts and railroads.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
This program has been funded for several years and ensures compliance with our Franchise
agreements and/or railroad permits. If not funded, we would be out of compliance with our
Franchise agreements and/or railroad permits. The work would need to occur and would be
funded under another business case.
Work under Franchise Agreements or Permits are contractual, agreed upon, and if the terms of
the agreement or permit are not executed a breach of contract will likely ensue. Also, state and
local government departments which oversee highways, roads, and city streets incorporate the
guidelines set forth in the American Association of State Highway Transportation Officials
(AASHTO) Roadside Design Guide into the design of the highways and roads. The guidelines
are based on the type of roadway and posted speed, but generally do not allow for any fixed
objects inside the traveled way or sides of the roadway (“clear zones”) for public safety. As a
result, nearly all new road projects require utilities to relocate or remove all poles inside and
outside the traveled way. The new roadside design guidelines allow for placement of new facility
in a location that improves the safety of the driving public, thus reduces risk to Avista. Avista
designers coordinate with each state or local road project to ensure the new relocations meet
the clear zone standards yet minimize cost. Most Franchise Agreements have provisions to
prohibit the ROW owner from requiring the utility to move the same facility more than once over
a span of years, usually five.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Measures to determine successful delivery on business case objectives include:
 YTD Spend
 Compliance with Franchise agreements and/or railroad permits
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 5 of 414
Electric Replacement and Relocation
Business Case Justification Narrative Page 4 of 7
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem

1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
NA

Option Capital Cost Start Complete
Relocate/replace facilities in conflict with street and
highway projects where established franchise
agreements and/or permits exist.
$3,000,000
annually
Continuous Program
UNFUNDED: Avista would be out of compliance
with established franchise agreements and/or
permits if work is not completed.
$0
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The Road Moves business is unplanned work, contractually obligated, and adds high risk to the
company if not completed, no alternative analysis is considered. This program is demand driven
and unplanned work. Funding allocation is based on historical spending trends.
The graph below shows the historical spend for Road Moves (2015 – 2020 YTD - May). The
average spend over the five years is $2.7 million. Because electric relocations are directly
correlated with the number of highway and street projects, the reason for the upward trend in
spend is likely an increase in transportation project spending.

$2,669,472
$3,206,007
$3,692,070
$2,217,060
$3,246,503
$-
$500,000
$1,000,000
$1,500,000
$2,000,000
$2,500,000
$3,000,000
$3,500,000
$4,000,000
2015 2016 2017 2018 2019
Electric Relocation & Replacement Historical Spend
2015 - 2019
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 6 of 414
Electric Replacement and Relocation
Business Case Justification Narrative Page 5 of 7
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
This funding will enable us to relocate/replace facilities in conflict with street and highway
projects where established franchise agreements and/or permits exist. The funding will ensure
we are in compliance with our existing franchise agreements and/or railroad permits.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
If funded, the outcome of this business case will have minimal impact on existing operations.
This funding has been in place for several years to maintain compliance with our franchise
agreements and railroad permits. If not funded, the work is required to maintain compliance with
our franchise agreements and/or railroad permits and will need to occur.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The work covered by this funding is mandatory to maintain compliance with our franchise
agreements and/or railroad permitting. Because the Road Moves business is unplanned work,
contractually obligated, and adds high risk to the company if not completed, no alternative
analysis is considered. This program is demand driven and unplanned work.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
This is an ongoing project. All investments/assets are used and useful at time of install.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This work is required to maintain compliance with our franchise agreements and/or railroad
permits. This work focuses on our Customers and performance (safety and compliance).

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project.
The work covered by this funding is mandatory to maintain compliance with our Franchise
Agreements and/or railroad permitting.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 7 of 414
Electric Replacement and Relocation
Business Case Justification Narrative Page 6 of 7
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Internal customers and stakeholders are the local area operation engineers and area
construction managers
The primary external stakeholders in the business include all state and local
transportation governments as well as customers since they live in the territory governed
by these agencies and use the transportation system.

2.8.2 Identify any related Business Cases
NA
3.1 Steering Committee or Advisory Group Information
The Road Move work is overseen by the local area operations engineers and area construction
managers.
3.2 Provide and discuss the governance processes and people that will
provide oversight
The work is mostly unplanned and non-specific in nature but occurs regularly and historical
averages are used to estimate a quantity. Electric Relocations (Road Moves) are agreed to and
executed per the jurisdictional Franchise Agreement or Permit.
The governance in place over the business case is set by the Operations Roundtable (ORT)
group, which sets forecasted budgets, monitors the incurred costs and submits any additional
funds requests as needed. Oversight of the program is provided by the local area operation
engineers and area construction managers manage the work as it is identified throughout the
given construction season.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
For the funding: Decision making, prioritization and change requests will be documented and
monitored through the Operations Roundtable (ORT).
For the work: Each office will work with their Area Engineer and impacted jurisdiction/Railroad
in determining priority.

The undersigned acknowledge they have reviewed the Electric Replacement and
Relocation (Road Moves) and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 8 of 414
Electric Replacement and Relocation
Business Case Justification Narrative Page 7 of 7

Signature: Date:
Print Name: Amy Jones
Title: Asset Maintenance Business Analyst
Role: Business Case Owner

Signature: Date:
Print Name: David Howell
Title: Director of Operations
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
8/2/20
08/01/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 9 of 414
Joint Use Projects
Business Case Justification Narrative Page 1 of 7
EXECUTIVE SUMMARY

Joint Use is the regulated use of utility poles and other structures by 3rd party
telcommunications companies in order for them to provide their services to the
customers we have in common. Avista licenses 76 unique entities that are attached to
over 150,000 poles across Avista’s service territory and is required by federal, state and
local laws to allow non discriminatory access to those assets. Even though this
relationship is mandated by law, and is compliance driven, Avista agrees that this
practice provides a direct benefit to our customers who desire those services.

Part of this requirement includes the obligation of Avista to replace infrastructure to
taller stronger structures in order to accommodate or “make ready” those facilities for
new attachments. This make ready work falls under capital expense and Avista is
allowed to recover the actual costs from the requesting attacher. Avista is also allowed
to recover a portion of the cost of replacing & maintaining shared infrastructure via a
regulated yearly pole rental fee. Avista would face potential regulatory and or civil legal
action if timelines and obligations are not met due to a lack of funding.The outcome of
these actions could result in significant financial loss and penalties.

VERSION HISTORY
Version Author Description Date Notes
Draft Stephen Schulte Initial draft of original business case 6/302020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 10 of 414
Joint Use Projects
Business Case Justification Narrative Page 2 of 7

GENERAL INFORMATION

1. BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
1.1 What is the current or potential problem that is being addressed? Access to
safe and reliable utility infrastructure by third parties is not only a crucial element of the
connected world in which we live but it is also mandated by regulators at the federal and state
levels. Avista therefore has a duty to repair, replace or add infrastructure to accommodate those
requests.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer. The major
drivers of this business case are the joint use and licensee’s who request new pole attachments
or who must upgrade their existing systems to meet the burgeoning and ever increasing demand
for reliable and cost efficient communication needs. This has a direct benefit to not only Avista
customers but Avista itself as we are also consumers of those same telecommunicaitons
products. As mentioned previously fair and non discriminatory access to investor owned utility
infrastructure is codified in Federal and State laws dating back to the Federal
Telecommunicaitons Act of 1934 which laid the groundwork for the current system of asset
sharing.

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred. This work is needed currently and will be needed on an ongoing
basis not only for existing wired telecommunication providers but for wireless providers who are
more often than not reliant upon existing vertical utility assets to locate their equipment. These
technologies are commonly referred to as 4G, 5G and LTE. The risk of not executing to meet
these demands could result in regulatory action, resultant fines, and possible civil litigation that
could far outweigh any short term savings. Damage to Avista’s reputation and loss of customer
trust could also result whose monetary costs are incalculable.

Requested Spend Amount $2.75m
Requested Spend Time Period Year to year
Requesting Organization/Department Operations/Joint Use
Business Case Owner | Sponsor Stephen Schulte | David Howell
Sponsor Organization/Department Operations/Joint Use
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 11 of 414
Joint Use Projects
Business Case Justification Narrative Page 3 of 7
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above. Avista’s joint use team utilizes several systems to track compliance and
adherence to Federal, State and local regulations.On physical and practical level, success is
more often realized when 2nd and 3rd parties construct their facilities, and follow up quality control
is performed. Anectodally the joint use team has been approached by Avista customers who
are very happy with their new telecommunication service that was made possible solely by the
ability of the provider to attach their cables to Avista utility poles.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem. Tracking,
invoicing and budget information is located on the joint use drive located on Avista network drive
c01m289.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.

[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]

Option Capital Cost Start Complete
Replace capital assets when requested 2.75 Ongoing Ongoing
[Alternative #1] $M MM YYYY MM YYYY
[Alternative #2] $M MM YYYY MM YYYY
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request. Current joint use capital business case amounts were
derived from historic spend data coupled with projected activity that is based on trends seen in
the joint use request tracking sheet. Avista receives a direct benefit of joint use related capital
work by way of receiving a new asset at a decreased cost to rate payers. Due in large part to
the dedication of fair and non discriminatory access to utility infrastructure, and the timeliness
of completing requested capital make ready work.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 12 of 414
Joint Use Projects
Business Case Justification Narrative Page 4 of 7
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
Given the current workload, and requests for capital asset replacement in support of joint use,
current funding levels will be fully spent by the end of the budget year. Similar funding levels will
be required on an ongoing basis with additional funding request sought as conditions warrant.
The majority of assets being replaced should not add any additional operating costs beyond
current levels such as wood pole test and treat, vegetation management etc.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing
reductions to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented. Additional
workload resulting from increased joint use make ready could be experienced by several
workgroups including but not limited to; Distribution Operations, Maximo, Real Estate, GIS,
Asset Management, Transmission Operations.
[For example, how will the outcome of this business case impact other parts of the business?]

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative. No realistic alternatives exist nor were
discussed. The only alternative would be to cease performing this work which would result in
regulatory/legal action and customer dissatisfaction.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year. This capital work related to this business case
are ongoing and immediate. Transfers to plant occur on a monthly basis and the assets become
used and useful immediately following physical construction.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful.
(i.e. if transfer to plant occurs monthly, quarterly or upon project completion).]

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization. The investment that is
made in Avista’s physical plant to accommodate joint use telecommunications benefits the
shared customer base of Avsita and the joint use providers. It places our customer at the center
of our focus and helps Avista to provide a safe, reliable and cost effective services. It also helps
to provide a safe working environment for all workers who require access to the electric
distribution system.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 13 of 414
Joint Use Projects
Business Case Justification Narrative Page 5 of 7
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project. Joint Use requested capital make ready
work is and will always be a prudent investment as the majority of assets that are being replaced
are typically near the end of their life and Avista benefits from a newer, stronger structure. Pole
replacements and new assets are typically the solution of last result and are only offered after
careful consideration and review. High dollar cost replacements such as transmission pole
receive addtitional scrutiny and review for appropriateness and cost effectiveness.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case.
Avista Electric rate payers, Distribution operations, Distribution Engineering, Electric Design.

2.8.2 Identify any related Business Cases. The Joint Use business case was carved out
of the Miscellaneous Capital Overhead Expense business case so that it could be more closely
monitored and tracked.
[Including any business cases that may have been replaced by this business case]

3.1 Steering Committee or Advisory Group Information. The advisory group for this
business case is the Operations Resource Team. It consists of the Manager of Operations
Analytics (Julie Lee), Operations Analyst (Sherry Bentley), Facilitor of the Operations Round
Table (Amy Jones), Manager of Distribution Engineering (Caesar Godinez), Operations
Engineers (Brian Chain and Tim Figart), Operations Director (David Howell), and the Joint Use
Program Adminstorator (Steve Schulte). Meetings are held at least once per quarter and as
needed depending on necessary required changes or requests.
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a
part of your departmental prioritization process.]
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 14 of 414
Joint Use Projects
Business Case Justification Narrative Page 6 of 7
3.2 Provide and discuss the governance processes and people that will
provide oversight. The business case spending levels are tracked and monitored by the
Manager of Operations Analytics (Julie Lee) and Operations Analyst (Sherry Bentley) in Utility
Accounting with monthly spend reporting to the Operations Director (David Howell).

3.3 How will decision-making, prioritization, and change requests be
documented and monitored . Desicision for funding increases will be discussed during
the Operations Resource Team meeting. If additional funding is deemed necessary then the
business case owner Steve Schulte will complete the necessary documentation which will then
be forwarded along to the Capital Planning Group for consideration. All documentation will be
kept on file in the joint use server share in a ‘budget’ folder.

The undersigned acknowledge they have reviewed the Joint Use Projects business
case and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.

Signature: Stephen Schulte Date: 7/2/20
Print Name: Stephen Schulte
Title: Joint Use Administrator
Role: Business Case Owner

Signature: David Howell Date: 7/20/20
Print Name: David Howell
Title: Director of Electric Operations
Role: Business Case Sponsor

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 15 of 414
Joint Use Projects
Business Case Justification Narrative Page 7 of 7
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 16 of 414
Saddle Mountain 230-115kV Station (New) Integration Project
Phase 2
Business Case Justification Narrative Page 1 of 7
EXECUTIVE SUMMARY
This section is reserved to provide a brief description of the business case and high level summary of the projects or
programs included. Please limit to no more than 2 paragraphs. Components that should be included: 1) a synopsis of
the problem, 2) the service code and jurisdiction of customers impacted, 3) the recommended solution, 4) the cost of
the solution, 5) how the solution will benefit customers identified, 6) the significance of the timeline and 7) the risks of
not approving this business case.
<< Both the Executive Summary and Version History should fit into one page >>

Large commercial customers in the Othello area have continued to expand their businesses. The
business expansion has created demands on the electric system that are not able to be
adequately backed up with the reliability that they deserve. Meeting the increased load demands
are possible, but equipment failures could cause outages that would be time consuming and
difficult to restore quickly.

This business case would replace the Othello City substation with a new station having 2-30MVA
transformers. The business case also includes substancial upgrades to the transmission system
in the area to integrate the new Othello City substation with the new Saddle Mountain substation.
This business case is important to customers so that they can continue to have the reliability of
the electric system that they have become accustomed to receiving.

Service: ED – Electric Direct
Jurisdiction: AN – Allocated North
Engineering Roundtable Request Number: ERT_2017-64
Cost of Solution: $25,650,000

VERSION HISTORY
Version Author Description Date Notes
1.0 Unknown Initial Version 2017
2.0 Karen Kusel /
Glenn Madden Update to 202 Template 6/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 17 of 414
Saddle Mountain 230-115kV Station (New) Integration Project
Phase 2
Business Case Justification Narrative Page 2 of 7
GENERAL INFORMATION

1 BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
This business case would replace the Othello City substation with a new station having 2-
30MVA transformers. The business case also includes substancial upgrades to the
transmission system in the area to integrate the new Othello City substation with the new
Saddle Mountain substation.
1.1 What is the current or potential problem that is being addressed?
There are performance issues in the Othello area, it is also difficult to maintain the
equipment at the Othello 115kV Substation due to load deam on all feeders.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Mandatory & Compliance are the main priority of this project due to TPL-001-4 non-
compliance at this time. There are also Performance & Capacity issues that will be
remedied with this project. Overall, this rebuild will relieve load and outage concerns for
large commercial customers.
1.3 Identify why this work is needed now and what risks there are if not approved
or is deferred
Due to increased load in the area, we are risking large customer outages due to equipment
failure.
1.4 Identify any measures that can be used to determine whether the investment
would successfully deliver on the objectives and address the need listed
above.
System Planning Assessments.
Requested Spend Amount $11,000,000
Requested Spend Time Period 4 Years
Requesting Organization/Department Transmission / System Planning
Business Case Owner | Sponsor Glenn Madden | Josh DiLuciano
Sponsor Organization/Department T&D
Phase Planning
Category Project
Driver Mandatory & Compliance
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 18 of 414
Saddle Mountain 230-115kV Station (New) Integration Project
Phase 2
Business Case Justification Narrative Page 3 of 7
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information; do not attach]
Project Report: Saddle Mountain Study.pdf
2016 Avista System Planning Assessment Report (Page 56)
Othello City Substation Area Load Analysis
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.
System Planning Assessments.
2 PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]
Alternative 1: Status Quo. This alternative is not recommended because it does not
mitigate the expected capacity constraints, and does not adhere to NERC Compliance
regulations.
Alternative 2: Build new 115kV Transmission Line. This alternative is not recommended
as it does not mitigate the low voltage issues in the Othello area.
Alternative 3: Close “Star” Points. This alternative is not recommended due to its high cost.
It is anticipated that $75M of reconductoring would be needed to mitigate any potential
violations comparable to the preferred alternative.
Alternative 4: Install Generation. This alternative is not recommended due to its high
financial costs, the potential for must run operation and the lead time on this project will be
well beyond the time this project is needed per NERC requirements.
Alternative 5: Build Saddle Mountain 230/115kV Substation Phase 2 Project with
associated support projects. This alternative is the most cost effective option considered
and provides enough voltage support and capacity into the area for the next 50 years. This
alternative mitigates all identified deficianencies in the Othello area documentes in the 2016
Planning Annual Assessment. This alternative is the best solution for the long term.
Phase 1: See Associated Phase 1 Business Case Narrative.
Phase 2:
1) Rebuild Othello Substation to 115kV Ring Bus with 5 positions.
2) Build new Transmission line from Saddle Mountain 115kV to Othello Substation
115kV.
This alternative is the most cost effective option considered and provides enough voltage
support and capacity into the area for the next 50 years. This alternative mitigates all
identified deficiencies in the Othello area documented in the 2016 Planning Annual
Assessment. This alternative is the best solution for the long term.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 19 of 414
Saddle Mountain 230-115kV Station (New) Integration Project
Phase 2
Business Case Justification Narrative Page 4 of 7
Option Capital Cost Start Complete
Recommended Solution: Build Saddle Mountain
230/115kV Substation Phase 2 Project with
associated support projects
$11M 01 2020 12 2021
Alternative 1: Status Quo $0M
Alternative 2: Build new 115kV Transmission Line
Alternative 3: Close “Star” Points $75M
Alternative 4: Install Generation

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
System Planning Assessments, previous outage information.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the expected
functions, processes or deliverables that will result from the capital spend?). Include any
known or estimated reductions to O&M as a result of this investment.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing
reductions to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
2020 - $2,500,000
2021 – $24,650,000
2022 – $1,000,000
2022 – Closeout
O&M will be comparible to before this project.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
[For example, how will the outcome of this business case impact other parts of the business?]
System Operations will have improved functionality of the electric system in the Othello
area.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
See Section 2.0 for alternative discussion.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 20 of 414
Saddle Mountain 230-115kV Station (New) Integration Project
Phase 2
Business Case Justification Narrative Page 5 of 7
2.5 Include a timeline of when this work will be started and completed. Describe
when the investments become used and useful to the customer. spend, and
transfers to plant by year.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful.
(i.e. if transfer to plant occurs monthly, quarterly or upon project completion).]
Design work was begun in 2020, construction will be completed by 2022 and closout may
continue into 2023. Transfers to plant will occur when the new station is commissioned and
energized.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]
Mission: We improve our customers’ lives through innovative energy solutions.
Vision: Better energy for life
This project will alleviate concerns regarding large customer outages and will provide the
ability to maintain major substation equipment.
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please
explain how the investment prudency will be reviewed and re-evaluated
throughout the project
The scope for the project, which is to increase transformation in the Othello area as well as
to increase reliability by creating the switching station is the least cost option. Adhering to
the scope and project objectives will be reviewed regularly by the project team including the
project engineer and the project manager.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Electrical Engineering, Generation Production/Substation Support, Transmission
Operations and System Planning and Operations
2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]
Saddle Mountain 230/115kV Station (New) Integration Project Phase 1 was completed in
2020.
3 MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a
part of your departmental prioritization process.]
The Engineering Roundtable initially is designated as the Steering Committee for this
project, with a more project-specific Steering Committee to be potentially identified at a later
date.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 21 of 414
Saddle Mountain 230-115kV Station (New) Integration Project
Phase 2
Business Case Justification Narrative Page 6 of 7
3.2 Provide and discuss the governance processes and people that will provide
oversight
Engineering Roundtable meets several times a year to analyze current and future projects.
3.3 How will decision-making, prioritization, and change requests be documented
and monitored
Project folders are saved to Engineering shared drives and Businesss Case Funds
Requests are available on the Finance sharepoint site

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 22 of 414
Saddle Mountain 230-115kV Station (New) Integration Project
Phase 2
Business Case Justification Narrative Page 7 of 7
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Saddle Mountain 230-115kV Station
(New) Integration Project Phase 2 and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.

Signature: Date:
Print Name: Glenn Madden
Title: Manager, Substation Engineering
Role: Business Case Owner

Signature: Date:
Print Name: Josh DiLuciano
Title: Director, Electrical Engineering
Role: Business Case Sponsor

Signature: Date:
Print Name: Damon Fisher
Title: Principle Engineer
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 23 of 414
Electric Storm Business Case
Business Case Justification Narrative Page 1 of 7
EXECUTIVE SUMMARY
The Electric Storm Business Case is focused on restoring Avista’s transmission, substation, and distribution
systems (damaged plant) into serviceable condition during a weather storm event or other natural disaster
where assets are damaged. These storm events are random and often occur with short notice. This
business case is to fund a rapid response to unexpected damages and outages, so customer outages are
minimized. The business case provides funds for replacing poles, cross arms, conductor, transformers, and
all other defined retirement units damaged during weather storm events. The damage can be due to high
winds, heavy ice and snow loads, lightning strikes, flooding, or wildfires as an example. The importance of
quickly replacing damaged facilities is vital to providing reliable service to our customers. This impacts
customers in WA and ID.

The annual budget amount is determined based on the historical average rate of capital restoration work
and excludes major event days (MEDs). If not funded, the work will still occur as needed for outages caused
by weather storm events or other natural disasters and would be absorbed through other business cases.

VERSION HISTORY
Version Author Description Date Notes
Draft Amy Jones Initial draft of Business Case refresh 2020 7/1/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 24 of 414
Electric Storm Business Case
Business Case Justification Narrative Page 2 of 7
GENERAL INFORMATION

1. BUSINESS PROBLEM

1.1 What is the current or potential problem that is being addressed?
The Electric Storm Business Case (BC) is focused on restoring Avista’s transmission, substation,
and distribution systems (damaged plant) into serviceable condition during a weather storm event
or other natural disasters where assets are damaged. These events are random and often occur
with short notice. This business case funds a rapid response to unexpected damages, so customer
outages are minimized. The business case provides funds for replacing poles, cross arms,
conductor, transformers, and other defined retirement units damaged during storm events. The
damage can be due to high winds, heavy ice and snow loads, lightning strikes, flooding, or wildfires.
The importance of quickly replacing damaged facilities is vital to providing reliable service to our
customers.

1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The primary driver for the Electric Storm BC is Failed Plant and Operations. The work is a
key component to minimizing customer outage times and contributes to Avista’s reliability
indices like SAFI and CAIDI. The secondary driver for this business case is Customer
Service Quality and Reliability.

Benefits to Customers
This business case allows funding for a rapid response to unexpected damages and service
interruptions so customer outage times are minimized. The importance of quickly replacing
damaged facilities is vital to providing reliable service to our customers.

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The importance of quickly replacing damaged facilities is vital to providing reliable service to our
customers. The Electric Storm BC is to fund a rapid response to unexpected damages and
Requested Spend Amount $3,200,000 annually
Requested Spend Time Period Ongoing program
Requesting Organization/Department Operations
Business Case Owner | Sponsor David Howell | David Howell
Sponsor Organization/Department Operations
Phase Execution
Category Program
Driver Failed Plant & Operations
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 25 of 414
Electric Storm Business Case
Business Case Justification Narrative Page 3 of 7
outages, so customer outages are minimized. If this business case is not funded the costs to
restoring power to our customers will be absorbed by another business case. The needed work
will continue to occur.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The primary measure that will be used to determine success is outage duration including other
reliability measures such as Avista’s reliability indices like SAFI and CAIDI. These measures will
demonstrate the impact of the work charged to this business case.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem

1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
N/A

Option Capital Cost Start Complete
Fully Funded $3,200,000
annually
Continuous Program
Unfunded: The work would need to be completed if
unfunded and would need to be absorbed by
another business case.
$0

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The annual budget amount is determined based on the historical average rate of capital
restoration work.
Figure 1 shows the historical costs (2010 – 2019) for the distribution storm business case. From
2010 to 2013, the average annual cost for distribution storms was $2.1 million dollars, with a
range of $1.3MM (2011) to $2.7MM (2013). The years of 2014 and 2015 experienced an
anomaly with 2014 having two uncharacteristic major wind events during the summer and
November 2015 was a historic 100-year windstorm event. Consequently, 2014 and 2015
realized record spending on storm related distribution work. The year 2016 had a distribution
storm spend of nearly $4 million, but much of the work was related to clean up of the historic
November 2015 storm event. The proposed funding level does not account for the storm
anomalies that occurred in 2014 and 2015 (Major Event Days).
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 26 of 414
Electric Storm Business Case
Business Case Justification Narrative Page 4 of 7

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
The requested capital cost amount will be spent as needed, driven by customer outages as a
result of a weather storm or natural disaster event. Historical spend is an indication of future
spend.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Work under this business case occurs when repair is needed to facilities that are damaged
during weather storm events or natural disasters. Depending on the severity and the duration
of the specific outages, various business functions and processes may be impacted. Impacted
areas can affect one office area or multiple Avista service territories.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The alternative to this business case request is not funding. The costs associated with repairing
damages as a result of a weather storm event or a natural disaster would be covered through
a different business case. Damages from these events will have to be repaired, regardless of
funding.

Figure 1: Dx Storm Historical Costs
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 27 of 414
Electric Storm Business Case
Business Case Justification Narrative Page 5 of 7
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
Weather storm events or natural disasters are a continuous risk. Work will occur as needed as
a result of damaged facilities related to these events. Many times, multiple events may occur
within one year in different office areas. Past data shows there has not been a year where a
storm has not happened. Since this is often emergency work, assets become used and useful
and transferred to plant immediately.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
The Electric Storm business case aligns with the company’s strategic goal of Safe and
Reliable Infrastructure. The work is a key component to minimizing customer outage times
and thus contributes to Avista’s reliability indices like SAFI and CAIDI.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The importance of quickly replacing damaged facilities is vital to providing reliable service to our
customers. The Electric Storm BC is to fund a rapid response to unexpected damages caused
by weather storm events or natural disasters, so customer outage times are minimized. If this
business case is not funded, the costs to restore power to our customers will be absorbed by a
different business case, as the work will need to occur.

The YTD spend is tracked and reviewed each month during the Electric Operations Roundtable
(ORT) meetings. The ORT reviews monthly spend and manages any additional funds requests.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
The Electric Storm work is overseen by the local area operations engineers and area construction
managers. In the event of larger scale storms or natural disasters, like the historical storm event in
November 2015, a formal Incident Command System (ICS) is created to manage the resources
needed to respond. Leaders will declare Emergency Operating Procedures (EOP) and
Stakeholders from every area of the company are involved on safely restoring power to our electric
customers.

2.8.2 Identify any related Business Cases
N/A

3.1 Steering Committee or Advisory Group Information
The Electric Storm work is overseen by the local area operations engineers and area
construction managers. The work is unplanned and non-specific in nature but occurs regularly.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 28 of 414
Electric Storm Business Case
Business Case Justification Narrative Page 6 of 7
In the event of larger scale storms or natural disasters, like the historical storm event in
November 2015, a formal Incident Command System (ICS) is created to manage the resources
needed to respond. Other large events are managed through an EOP with the Director of
Operations.

3.2 Provide and discuss the governance processes and people that will
provide oversight
The governance in place over the business case is set by the Operations Roundtable (ORT)
group, which sets forecasted budgets, monitors the incurred costs and submits any additional
funds requests as needed. Electric Storm work is overseen by the local area operations
engineers and area construction managers.

3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Decision making, prioritization and change requests will be documented and monitored though
the Operations Roundtable (ORT).

The undersigned acknowledge they have reviewed the Electric Storms Business
Case and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 29 of 414
Electric Storm Business Case
Business Case Justification Narrative Page 7 of 7
Print Name: David Howell
Title: Director of Operations
Role: Business Case Owner

Signature: Date:
Print Name: David Howell
Title: Director of Operations
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
8/2/20
8/2/20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 30 of 414
Meter Minor Blanket
Business Case Justification Narrative Page 1 of 6
1 GENERAL INFORMATION
*Note: 2017 Request includes additional one time request of $205,000 for the A-base meter replacement project. This
work is in support of the AMI project.
1.1 Steering Committee or Advisory Group Information
The determination for how the funds in this business case will be spent is a joint
decision made by the Manager and General Foreman. A meter usage forecast will
be used to guide the decision making process. The forecast will be based on the
past five years of meter installs, current install rates, and manufacturer lead times.
2 BUSINESS PROBLEM
The primary driver for this business case is failed plant and operations. We regularly
experience failed plant when meters and/or metering equipment fails. Meters are a
critical component to supplying our customers with electricity and to accurately
measure their energy consumption. Please refer to Attachment 1 for the most
recent meter failure analysis completed by Asset Management in early 2017. This
analysis shows the failure curves for both digital and mechanical meters. The
analysis suggests that the more digital meters that are installed the higher the meter
failure rate becomes. However, mechanical meters are no longer manufactured by
our meter vendors because they have moved to the digital market.
When meters fail at existing customer service point’s immediate action must be
taken to repair or replace the meter. This is because a failed meter will not provide
accurate consumption data. Funding is necessary to replace or make needed
repairs otherwise the customer billing data will have to be estimated. Billing
estimation lowers the quality of service we provide our customers because
estimated data can be viewed by the customer as inaccurate. Additionally,
estimated billing data can put rate pressure on our customer base if usage is under
estimated. If usage is over estimated it unfairly penalizes the customer whose bill
is being estimated.

Requested Spend Amount $505,000*
Requesting Organization/Department Z08/Electric Meter Shop
Business Case Owner Dan Austin
Business Case Sponsor Bryan Cox
Sponsor Organization/Department Operations
Category
Driver
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 31 of 414
Meter Minor Blanket
Business Case Justification Narrative Page 2 of 6
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capital
Cost
O&M Cost Start Complete
Fully fund new electric
meter purchases
$505,000 $0 01 2017 12 2017
RMA meters 313,994 $278,448.72 01 2017 12 2017
Repair or Refurbish meters 313,994 $281,013.48 01 2017 12 2017

This business case will reduce the O&M required to replace failed meters. As you
can see tabulated in the above table the lowest cost option is to fully fund this
business case. The reduction in O&M is associated with the meter replacement
portion of this business case.
Historically there has been three solutions to replace failed meters:
1.) Refurbish and repair in house
2.) Return Merchandise Authorization (RMA)
3.) Replace failed meter with new meters
3.1 REFURBISH AND REPAIR IN HOUSE
As Avista’s population of digital meters grows and the mechanical meter population
shrinks the less viable this option becomes. This is because digital meters require
special equipment and training to repair, which is not available to our technicians.
Also of note is that mechanical meters are no longer manufactured by our meter
vendors because they have moved to the digital market. It is very rare for our
technicians to remove a mechanical meter from the field as a result of failure. The
majority, if not all, of the meter failures we experience in a given year are from the
digital meter families. Table 1 shows how many digital and mechanical meters we
have installed in WA and ID. This table also shows the average failure rate we
experience annually. This option was not chosen due to the equipment and
technical training required as well as the higher cost associated with the labor to
refurbish meters.

Meter Type
Qty.
Single-Phase Mechanical 172,215
Single-Phase Digital 187,100
Poly-Phase Mechanical 5,781
Poly-Phase Digital 17,346
Total 382,442
Average failures per year 3882
Table 1: Meter Quantities by Type
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 32 of 414
Meter Minor Blanket
Business Case Justification Narrative Page 3 of 6

Charge Type Cost
Refurbish Labor $37.26
Install Labor $35.76
Total $73.02
Table 2: Tabulated Cost to Refurbish Meters
3.2 RETURN MERCHANDISE AUTHORIZATION (RMA)
Option 2 is more costly than purchasing new meters due to the manufacturer’s
costs, shipping costs, and labor associated with the RMA process. Recent repair
costs were quoted from our meter vendor to be between $20 and $40 dollars per
meter. Table 3 shows the total cost to RMA a single meter. This cost was developed
using very conservative values for each charge type and may be higher if more
expensive (Poly-phase) meter types were included. This option was not chosen
due to the high cost.

Charge Type Cost
RMA Labor $9.31
Shipping $7.17
Repair Charges $20.00
Install Labor $35.76
Total $72.74
Table 3: Tabulated Cost to Install RMA Meters
3.3 REPLACE FAILED METERS WITH NEW METERS
The final option is to purchase meters new for meter failure replacements. This is
the lowest cost solution as shown in Table 4. There is a cost savings with new
meters because there is no labor associated with refurbishing and testing and there
is no RMA charges as compared to Options 1 and 2. This business case supports
Options 3 to purchase new meters to replace failed meters.

Charge Type Cost
Purchase Cost $20.43
Labor $35.76
Total $56.19
Table 4: Tabulated Cost to Install New Meters
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 33 of 414
Meter Minor Blanket
Business Case Justification Narrative Page 4 of 6
Do nothing is not an option because at minimum we need functioning meters to
replace failed meters. Doing nothing would keep Avista from accurately billing our
existing customer base.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 34 of 414
Meter Minor Blanket
Business Case Justification Narrative Page 5 of 6
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Meter Minor Blanket and
agree with the approach it presents and that it has been approved by the steering
committee or other governance body identified in Section1.1. The undersigned also
acknowledge that significant changes to this will be coordinated with and approved
by the undersigned or their designated representatives.

Signature: Date:
Print Name: Dan Austin
Title: Electric Meter Shop Manager
Role: Business Case Owner

Signature: Date:
Print Name: Bryan Cox
Title: Sr Dir of HR Operations
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

5 VERSION HISTORY
Version Implemented
By
Revision
Date
Approved
By
Approval
Date
Reason
1.0 Dan Austin 4/13/2017 Bryan Cox 4/14/2017 Initial version

Template Version: 03/07/2017

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 35 of 414
Meter Minor Blanket
Business Case Justification Narrative Page 6 of 6
Attachment 1: Electric Meter Model Review
Electric Meter Model Review.pptx
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 36 of 414
Distribution Grid Modernization
Business Case Justification Narrative Page 1 of 12
EXECUTIVE SUMMARY

Maintaining system reliability is an important part of providing quality service to Avista’s customers. Planned
investments in the distribution system are necessary to efficiently maintain reliability while keeping costs
low for customers. The Grid Modernization Program (GMP) is the largest program focused on planned
maintenance and improvements beyond wood poles driven by a comprehensive engineering analysis
across Avista’s 19,000 miles of electric distribution lines (Avista 2019 Quick Facts). The GMP’s mission is
to replace aging and failing infrastructure within the electric distribution system while also improving
reliability and performance and capturing energy savings through the efficient use of company resources.
Avista’s distribution system has numerous facilities at, or near, the end of their useful life. Over decades,
many of these were built to different construction standards using a wide variety of materials. These factors
contribute to increased outages that take longer to restore and fall short of modern expectations that utilities
face. The program benefits all Washington and Idaho electric customers and is intended to operate on a
60 year cycle averaging 190 circuit-miles addressed per year. The current average cost per mile requires
a $28.88MM annual investment to achieve a 60 year cycle. The 60 year cycle is based on the average
lifespan of distribution infrastructure, and the twenty year cycle of the Wood Pole Management Program
(WPM) (Avista Utilities Electric Distribution Infrastructure Plan June 2017).
A systematic approach is recommended to address the rebuild and upgrade of the distribution
system. This approach utilizes a prioritization method balancing feeder health, performance, and criticality.
Design decisions are made through a consistent process and construction adheres to established overhead
and underground standards. Upon the completed construction of GMP projects, customers benefit from
improved system reliability, safety, and performance. These can be measured by a reduction in outage
frequencies and durations in addition to power quality metrics. As Avista’s distribution facilities continue to
age, it becomes more important to be proactive in their replacement. Delaying the business case increases
the likelihood and severity of various risks including equipment failure, wildfire, and energy losses. A delay
would also impact the cycle time of WPM. Not approving the business case places the responsibility of
rebuilding the system on the individual offices throughout the company which are responsible for daily
maintenance and operations as well as new revenue projects. Additionally, it jeopardizes the ability to
holistically address system wide performance. Overall, not funding or delaying this business case would
reduce the efficiency that the GMP provides to the company and customers while elevating the risk of an
inconsistent application of design and construction standards.

VERSION HISTORY
Version Author Description Date Notes
Draft Initial draft of original business case 2020 7/31/2020
1.0

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 37 of 414
Distribution Grid Modernization
Business Case Justification Narrative Page 2 of 12
GENERAL INFORMATION

1. BUSINESS PROBLEM

1.1 What is the current or potential problem that is being addressed?
The Grid Modernization Program (GMP) addresses the aging and failing infrastructure found
throughout the electric distribution system. Other issues addressed include sub-optimal system
performance and inaccessible facilities that drive increased routine maintenance costs. Outage
durations and frequencies and power quality problems are also evaluated for improvement
through the installation of automated devices. Safety is also a key benefit of the Program as
Grid Modernization projects bring facilities up to current NESC and Avista construction
standards, fulfill the efforts of Wildfire Resiliency, address the Transformer Change Out
Program, and address structures located within the control zone of roadways subject to
Washington State’s Department of Transportation Target Zero requirements.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The GMP business case is driven by asset condition and performance and capacity. Customers
benefit from in the following ways:
 Replacement of aging and failed infrastructure.
 Fewer outages that can be resolved more quickly.
 Automation devices produce results immediately optimizing system performance,
reducing costs, and reducing outages.
 Cost effective work due to program efficiencies and long-term planning.
 Improved safety.
 Providing additional expertise with design and construction resources that are not
available at outlying offices.

Reliability improvements have been quantified that are a direct benefit to the customers in
feeders that the GMP has addressed. The analysis was performed by comparing reliability
metrics in years before and after the GMP for all feeders completed through 2018. Figures
1-4 show these reliability metrics, and the raw data and analysis is located at:
c01m19:\Feeder Upgrades - Dist Grid Mod\~Program Admin\Data\grid mod reliability data
analysis before and after.xlsx
Requested Spend Amount $77,000,000
Requested Spend Time Period 5 years
Requesting Organization/Department Asset Maintenance
Business Case Owner | Sponsor Heather Webster | Alicia Gibbs | David Howell
Sponsor Organization/Department T51/Asset Maintenance
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 38 of 414
Distribution Grid Modernization
Business Case Justification Narrative Page 3 of 12

Figure 1: Average CEMI3 on feeders that have been fully addressed by GMP. This includes
all the feeders completed through the end of 2018.
Figure 1 shows CEMI3 which is the percentage of customers experiencing 3 or more
interruptions per year. The data show that customers on feeders that have been addressed
by the Grid Modernization Program experience a 61% reduction when major event day
(MED) are not included and a 54% reduction when MED are included.

Figure 2: SAIFI before and after Grid Modernization on feeders completed through the end
of 2018.

SAIFI is the sustained average interruption frequency index. The data show that customers
on feeders addressed by the GMP experience a 51% reduction (with MED) and a 64%
reduction in the duration of power interruptions.
0.0%
2.0%
4.0%
6.0%
8.0%
10.0%
12.0%
w/o MED w/ MED
Average CEMI3 Before and After GM
cumulative average before
Grid Mod
cumulative average post Grid
Mod
*Error bars- 1 SD
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
w/o MED w/ MED
SAIFI Before and After GM
cumulative average before Grid
Mod
cumulative average post Grid
Mod
*Error bars- 1 SD
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 39 of 414
Distribution Grid Modernization
Business Case Justification Narrative Page 4 of 12

Figure 3: SAIDI before and after GMP for feeders completely addressed by the end of
2018.

SAIDI is the total duration of interruptions experienced by customers (in this case, the
customers on one feeder). Customers on feeders addressed by the GMP experience a
64% reduction (without MED) and a 73% reduction with MED included. This means that
outages customers experience are shorter in duration.

Figure 4: CAIDI before and after being addressed by the Grid Modernization Program.

CAIDI is the customer average duration index, which indicates the amount of time it takes to
restore service. Customers experience an 11% reduction (without MED) and an 18% reduction
with MED after GMP.

0.0
50.0
100.0
150.0
200.0
250.0
300.0
w/o MED w/ MED
SAIDI Before and After GM
cumulative average before
Grid Mod
cumulative average post Grid
Mod
*Error bars- 1 SD
0.0
20.0
40.0
60.0
80.0
100.0
120.0
140.0
160.0
180.0
w/o MED w/ MED
CAIDI Before and After GM
cumulative average before Grid
Mod
cumulative average post Grid
Mod
*Error bars- 1 SD
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 40 of 414
Distribution Grid Modernization
Business Case Justification Narrative Page 5 of 12
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Delaying the work performed by the GMP would result in an increased risk of equipment failure,
energy losses over time, expanded system maintenance costs, and unplanned outages. There
would also be a lost opportunity to apply holistic and sustainable solutions following an in-depth
engineering analysis to locations that experience recurring unplanned outages.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The previously mentioned performance metrics; SAIFI, SAIDI, CAIDI, and CEMI3 can all be
used to gauge system performance improvements after construction is completed. Voltage
quality at any individual point along the feeder can also serve as an indicator of whether a project
was successful. Across the entire program, an annual total of the feeder miles addressed serves
as a measure of progress toward addressing the entire system across a 60 year cycle as
intended.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem

Feeder Status Report: The feeder status report details the analysis of attributes of the
distribution system in three major categories:
 Performance: Thermal utilization, efficiency, voltage regulation, reliability performance
(MAIFI, CAIDI), power factor, FDR imbalance.
 Health: Age, OH/UG ratio, pole rejection rate, reliability health (CEMI3, SAIFI).
 Criticality: Essential services, commercial account density, customer density, load
density.
c01m19:\Distribution Feeder Status Report\Feeder Status Report
2019\2019FeederStatusReport.xlsm
Using the information that the Feeder Status Report provides, each feeder is prioritized by
a combined score assessing the three categories within a tool in the location below and
selected to maintain a balance between work done in Washington and Idaho.
c01m19:\Feeder Upgrades - Dist Grid Mod\~Program Admin\Feeder Selection
Feeder analysis reports: Once selected, a distribution engineer performs a thorough
analysis on the entire circuit to determine what work is needed to make the feeder most
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 41 of 414
Distribution Grid Modernization
Business Case Justification Narrative Page 6 of 12
efficient and to bring the feeder up to current standards to improve operation, safety, and
support future loads. These reports are located at the following location:
c01m19:\Feeder Upgrades - Dist Grid Mod\~Feeder Analysis\
2017 Distribution Plan: The 2017 Distribution Plan summarizes a variety of topics including
the different drivers for investing in system improvements and planned investments such as
Grid Mod, which is cited often.
Avista Utilities Electric Distribution Infrastructure Plan June 2017: c01m19:\Feeder
Upgrades - Dist Grid Mod\~Program Admin\Data\Distribution Plan FINAL 2017.pdf

1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
The Distribution Feeder Status Report annually quantifies the performance, health, and
criticality as outlined in section 1.5.1. More specifically, Wood Pole Management
commissions inspections on selected Grid Modernization feeders identifying deteriorating,
broken, and/or missing equipment. Individual reports can be found on the c01m19 feeder,
the Feeder Upgrades – Dist Grid Mod folder, the specific feeder folder in question, and
finally the ~Admin and Wood Pole Mgmt folders.

Option Capital Cost Start Complete
[Recommended Solution] The Distribution Grid
Modernization Program provides benefits to
customers, employees, and shareholders by
replacing problematic poles, cross-arms, cut-outs,
transformers, conductor, etc. Additionally,
automated line devices are installed which increase
energy efficiency and system reliability. The 2021
request is $10MM to begin ramping up to the
$28.88MM necessary to maintain a 60 year
program cycle.
$28.88MM
annually
01 2012 12 2072
[Alternative #1] Address issues through the
different specific company initiatives, such as
WPM, TCOP, URD, Segment Reconductor, etc.
This means that a crew would potentially go out to
the same area multiple times. This costs more for
set up, travel time, flagging, etc. which means
higher rates for customers. It also means the
customer could have multiple planned outages and
be impacted by multiple street closures for crews to
address needed work at separate times. The risk
reduction is also cut in half compared to the
comprehensive work completed by GMP.
$UNK
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 42 of 414
Distribution Grid Modernization
Business Case Justification Narrative Page 7 of 12

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The GMP capital request was calculated using a 60 year cycle as a goal while addressing
almost 12,000 circuit-miles of electric distribution facilities. With the average spend rate of
$152,000/mile over the past thirty months, an estimate of $28.88MM is determined.
When considering the prudency of this investment as part of a single program rather than
spread across multiple departments, it is worth considering the design and construction
support experience that GMP resources provide as a dedicated subject matter expert on
projects. Other departments with competing priorities might find it difficult to maintain a
focus on projects of this size. Another important benefit of work done is the O&M savings
of each automated device that is installed. Using a thirty month long span of data over the
past three years, the devices installed by GMP has saved the company an annual amount
of $346,825. (c01m19:\Feeder Upgrades - Dist Grid Mod\~Program
Admin\Data\Automation device activation data and hard O&M costs.xlsx)

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.

[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]

The capital cost of the Program is spread across numerous projects that typically span at least
two years in a process summarized in Figure 5.

Once metrics are gathered, individual feeders are evaluated to determine how they rank in
comparison to the rest of the electric distribution system. Once chosen, the Program Engineer
analyzes the feeder for opportunities to improve its reliability, power quality, potential for energy
savings, and accessibility. That analysis is conveyed in a report to project stakeholders outlining
feeder specific opportunities for improvement that have been agreed upon by individuals with
experience in the area. Design follows the publishing of the report and in addition to feeder
specific improvements, a set of standard criteria are applied to the existing equipment in the
field. Designs are reviewed by subject matter experts evaluating the designs constructability and
Feeder Selection
• Comparison of health, performance, and criticality
Engineering Analysis
• Evaluation of individual feeder needs
• Automated device recommendations
• Feeder Kickoff Meeting
Design
• Incorporation of Grid Mod's standard scope and analysis recommendations
• Correction of mapping inconsistencies
Design Review
• Feasibility
• Constructability
• Real Estate/Env. Review
Construction
• Permitting
• Pre-construction Meeting
• Design construction
Audit & Closeout
• Construction monitoring
• Change management
• Site Restoration
Figure 5: The Grid Modernization Project Life Cycle
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 43 of 414
Distribution Grid Modernization
Business Case Justification Narrative Page 8 of 12
accuracy, real estate needs, and environmental and cultural risks. Construction then takes place
along with an audit evaluating workmanship and accuracy relative to the design. Deviations are
tracked through a design change order process. The project then moves towards completion as
site restoration and accounting activities are completed.

Future O&M costs are reduced by relocating, removing, or converting sections of Avista facilities
that present an opportunity to improve the feeder’s performance. Vegetation Management costs
are reduced by the removal of troublesome species that outpace routine maintenance cycles
and the installation of automated devices reduces the need for servicemen to trouble shoot
outages and performance issues.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
 Wood Pole Management – The GMP incorporates WPM’s scope within its projects
thereby assisting with its 20-year cycle target. Grid Modernization also relies on WPM
for poles inspection reports.
 Vegetation Management – The GMP supports and relies on Vegetation Management
during the course and completion of its projects. After design and prior to construction,
trimming crews address any conflicts that a proposed design might have with existing
vegetation. Upon the completion of a project, the GMP reduces the need for future tree
trimming by targeting the removal of cycle-breaking species or the relocation and
conversion of electric distribution infrastructure.
 Real Estate – Locations throughout the GMP designs are reviewed by the staff within
the Real Estate department for conflicts that would arise during construction. Permitting
is another consideration that is addressed once a design has been completed. The
comprehensive GMP approach that partners with Real Estate’s analysis results in the
mitigation of outstanding issues that have existed in the field, thereby reducing a
litigation risk to the company, and the establishment of sustainable alignments and
corridors for Avista facilities.
 Environmental Compliance – Environmental items of concern are addressed during
design and prior to the construction of proposed GMP work. Examples include avian
and wildlife protection, the avoidance of any impact on cultural and heritage sites, and
the impacts a project may have on public lands managed by tribal, municipal, state, and
federal agencies.
 Segment Reconductor and FDR Tie – The GMP’s holistic approach on feeders
selected after a thorough prioritization process addresses issues that might otherwise
be included on segment reconductor and FDR tie projects. The investment of Grid
Modernization funding on selected feeders improves local office resource availability.
 Distribution Minor Rebuild – GMP’s holistic approach on feeders selected after a
thorough prioritization process addresses issues that might otherwise be included on
minor rebuild projects. The investment of Grid Modernization funding on selected
feeders improves local office resource availability.
 Wildfire Resiliency – The GMP incorporates efforts to reduce the risk of wildfires
caused by electric distribution lines by relocating or converting lines in addition to the
scope of the Wildfire Resiliency program.
 Distribution Transformer Change Out Program (TCOP) – The GMP incorporates the
replacement of PCB transformers into each of its projects fulfilling the objective of the
TCOP and reducing environmental risks and liabilities to the company and customers.
 LED Change-Out Program – The GMP incorporates the replacement of outdated
streetlights to fulfill the mission of the LED Change-Out Program across its projects.
 Primary URD Cable Replacement – The GMP incorporates the replacement of
outdated underground cable to fulfill the objective of Primary URD Cable Replacement
across its projects.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 44 of 414
Distribution Grid Modernization
Business Case Justification Narrative Page 9 of 12

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Replacing equipment upon failure is an alternative to the GMP business case. It would maximize
the value of an individual piece of equipment but result in numerous unplanned outages that
could arise from and be the cause of unsafe situations to employees and customers. To mitigate
the increase of unplanned outages, additional crews would be needed for trouble responses.
Aside from a dedicated resource to respond, a variety of equipment and materials would also
need to be available to minimize the impact of system failures.
GMP’s scope could be addressed through various company initiatives such as WPM, TCOP,
Primary URD Cable Replacement, Segment Reconductor and FDR Tie, etc. Given the poor
condition of selected GMP feeders, it would certainly mean that the different initiatives would
visit the same location multiple times over a short period resulting in elevated mobilization costs
and disturbances to customers and communities as crews complete their work. The additional
costs of working on the same feeder through multiple initiatives would be evident in increased
rates. A possible solution to these issues would be to attempt a large coordination effort with a
single construction resource that would receive all work packages from each initiative and
attempt to carry out their construction simultaneously.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
Work across the program is intended to be completed on a 60 year cycle becoming used and
useful throughout each year as projects are constructed. Figure 5 above (Section 2.2) illustrates
the life cycle of individual projects that can last at least two years.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
GMP aligns with Avista’s mission: We improve our customers’ lives through innovative energy
solutions. Safely, Responsibly, and Affordably. We put those we serve at the center of
everything that we do. GMP directly improves the lives of our customers by improving system
reliability and performance by planning the work to minimize costs of long-term maintenance or
unplanned work to maintain the distribution system. The collaboration that takes place
throughout the program improves results upon the completion of each project: an efficient
delivery experienced by customers and communities and a reduced risk to Shareholders.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
 By addressing necessary work on the distribution system through the work of one program,
there are reduced costs to the customer due to mobilizing crews one time, closing roads,
and having planned outages one time instead of many times.
 The GMP plans work ahead of time and invests in the feeders that will receive the highest
benefit from the scope of the program. The efficiency of this work is planned through earned
value measurements which track the cost and schedule efficiency of the work compared to
plan. The planning and tracking of the program use best project management practices.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 45 of 414
Distribution Grid Modernization
Business Case Justification Narrative Page 10 of 12
 The work that will be performed on the program is planned through a thorough engineering
analysis and the designs go through a full design review process to ensure that any
replacements are prudent and in the best interest of the customer. This prevents work that
is out of scope or does not provide adequate benefit from being added to the plan.
 Auditing the completed work ensures that the work performed and charged for was included
in the plan or managed and tracked through the approved design change order process.
 Competitive bidding ensures that the work is awarded in a manner that reduces risks and
keeps costs lower.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Internal Customers/Stakeholders: Real Estate, Transmission Engineering, Distribution
Engineering, Environmental Compliance, Construction Services, Electric Shop, Meter Shop,
Area offices, Account Executives, Regional Business Managers, Avista line crews, WPM,
Supply Chain, and Vegetation Management.
External Customers/Stakeholders: Electric distribution customers, Municipalities, State DOT’s,
US Army Corps of Engineers, Public Land Management agencies, Joint Users, Adjacent
Utilities, Native Tribes, Community action groups, Contract line crews.

2.8.2 Identify any related Business Cases
Wood Pole Management, Primary URD Cable Replacement, LED Change-Out Program,
Wildfire Resiliency, Distribution Transformer Change Out Program, Distribution Minor Rebuild,
Segment Reconductor and FDR Tie

3.1 Steering Committee or Advisory Group Information
The steering committee is comprised of the project sponsor, Asset Maintenance Manager,
Director of Operations, and the Asset Management Manager. This group meets as needed,
usually annually, for an update on the program or when key program decisions or changes in
scope need to be discussed. The members of this group are called out in the Grid Modernization
Communication Management Plan.
Provide and discuss the governance processes and people that will
provide oversight
The Grid Modernization Communication plan details the individuals that receive communication,
the type of communication, and the frequency of communication. This document is located at:
c01m19:\Feeder Upgrades - Dist Grid Mod\~Program Admin\Admin\Project Management Plan
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 46 of 414
Distribution Grid Modernization
Business Case Justification Narrative Page 11 of 12
Documents\03 Communication Management Plan.docx

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 47 of 414
Distribution Grid Modernization
Business Case Justification Narrative Page 12 of 12
How will decision-making, prioritization, and change requests be documented
and monitored
 Decision making is documented in meeting minutes in the Program Onenote folder.
o c01m19:\Feeder Upgrades - Dist Grid Mod\~Program Admin\Meetings &
Presentations\~1Shared Grid Mod Program notebook
 The prioritization of feeder work is managed in the Feeder Selection management tool which
is stored in the Grid Modernization drive. The prioritization is updated every one to two years
with updated data from the Feeder Status Report. The feeders are then ranked based on
equally weighted health, performance, and reliability scores. The top feeders may undergo an
engineering analysis and gather feedback from area engineers to determine which order these
feeders are selected in.
 Change requests are managed through a change order process. Any proposed changes that
occur during construction to the approved designs are first evaluated, then approved, and
tracked through the change order process.
The undersigned acknowledge they have reviewed the Distribution Grid
Modernization business case and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.

Signature: Heather Webster Date: 7/31/2020
Print Name: Heather Webster
Title: Asset Maintenance Project Mgr.
Role: Business Case Owner

Signature: David Howell Date: 7/31/2020
Print Name: David Howell
Title: Director of Operations
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 48 of 414
Minor Rebuild
Business Case Justification Narrative Page 1 of 9
EXECUTIVE SUMMARY

The Distribution Minor Rebuild business provides a solution for the utility to address small unplanned asset
failures and customer driven modifications to the distribution system but excludes fixes to the system
considered to be maintenance. Distribution Minor Rebuild is an ongoing program that focuses on keeping
the distribution system in reliable condition for customers, maintaining safe conditions for the workers,
providing response to unplanned damages to distribution assets not related to weather events, as well as
responding to small customer driven rebuilds. Throughout the entire distribution system, minor rebuilds, or
replacements of asset units need to be completed to maintain system reliability and safety. This work
impacts customers in WA and ID. By not funding, various types of work will need to be absorbed into some
other funding due to the necessity of the work (i.e. the replacement of a car-hit pole in the alley, a broken
cross-arm, a failed transformer, and other safety related projects.) Some minor rebuilds left unrepaired
may not result in an immediate catastrophic failure. Over time an adverse accumulation of unrepaired
assets would greatly put line workers and the general public at risk as minor asset failures begin to
deteriorate pockets of the distribution system.

Historically costs for unplanned minor rebuild work have increased for several reasons. Many assets on the
distribution system are past their end of life cycle and contributing to this increase. The 3-year average
actual spend for minor rebuild work is $11,900,000 per year. This is expected to continue for the next 5
years. On average, Minor Rebuild spends approximately $1,000,000/month.

VERSION HISTORY
Version Author Description Date Notes
Draft Amy Jones Draft of 2020 Business Case Refresh update 6/30/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 49 of 414
Minor Rebuild
Business Case Justification Narrative Page 2 of 9
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Distribution Minor Rebuild is an ongoing program that focuses on: keeping the distribution
system in reliable condition for customers, maintaining safe conditions for the workers, provides
providing responsiveness response to unplanned damages to distribution assets not related to
weather events, as well as responding to small customer driven rebuilds. Throughout the entire
distribution system, minor rebuilds or replacement of asset units need to be completed to
maintain system reliability and safety.
The work includes; Asset Condition, NESC/Operating Standard Violation, Facility Upgrades,
Facility Route Location Modification, Trouble and customer requests. Occasionally, larger
projects with an identified need and short timeframe for implementation are constructed under
the Distribution Minor Rebuild business case. Even though the work is unplanned, Minor Rebuild
work occurs regularly due to the nature of the utility business and numerous assets in the field
spread over a wide geographical area.

1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The primary driver for the work is Asset Condition. This work focuses on keeping the distribution
system in reliable condition for customers, maintaining safe conditions for the workers, providing
response to unplanned damages to distribution assets not related to weather events, as well as
responding to small customer driven rebuilds. Throughout the entire distribution system, minor
rebuilds or replacements of asset units need to be completed to maintain system reliability and
safety which are a benefit to customers.

Requested Spend Amount $10,000,000 annually
Requested Spend Time Period Ongoing Program
Requesting Organization/Department Electric Operations
Business Case Owner | Sponsor Amy Jones | David Howell
Sponsor Organization/Department Operations
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 50 of 414
Minor Rebuild
Business Case Justification Narrative Page 3 of 9
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred

Distribution Minor Rebuild work is one of the many components that support the overall reliability
of the distribution system as well as responsiveness to customer requested service demands
and system safety. Safety is of utmost concern for linemen and the general public and the minor
rebuild business case provides the funding for work such as; replacement of a car-hit pole in the
alley, a broken cross-arm, a burned-up transformer, and other safety related projects. In
addition, if the business case is not funded, this will also affect the ability to respond to
customers’ needs for modifications to their electrical service. It is acknowledged some minor
rebuilds left unrepaired will not result in immediate catastrophic failures to the distribution
system, but over time an adverse accumulation of unrepaired assets would greatly put line
workers and the general public at risk as minor asset failures begin to deteriorate within areas
of the distribution system.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Historical information and the continuance of tracking spend by categories will be useful in
determining the effectiveness of the program and meeting its original objectives.
In 2020, Distribution Minor Rebuild transitioned to an activity-based structure that divided the
business case into six general activities, which embody the major types of work performed. This
division will allow for improved reporting on spend. Below is a categorical breakdown for the six
general activities.
 Customer Requested Rebuilds – Work is initiated by an existing customer or property
owner, and the costs associated with the work are typically reimbursed by the
requesting party. Examples could be a customer requested reroute, overhead to
underground line conversion, or customer load increase.
 Trouble Related Rebuilds – Emergency work required to repair damaged facilities
related to non-storm and non-fire related outages. Activities include a car hit pole, car-
hit padmount enclosure, copper theft, or unforeseen failed equipment that needs
immediate response.
 NESC / Operating Standard Violations – Activities include, but are not limited to,
NESC violations (not related to Joint Use clearances), secondary/service-related
voltage mitigation, fusing protection mitigation, aerial trespass, and undersized
equipment (transformers, regulators, etc.).
 Asset Condition– Activities include, but are not limited to, deteriorated wood poles,
leaking transformers, condition related replacement (not outage related) of line devices
and equipment.
 Facility Upgrades/Efficiency Improvements – Activities include, but are not limited
to, small scale reconductors, small scale feeder ties, installation of new switches or
sectionalizing devices, feeder balancing, installation of new regulators, reclosers, or
capacitor banks, and removal of open wire secondary.
 Facility Route / Location Modifications – Activities include, but are not limited to,
overhead to underground conversions, facility re-route, or relocation of midline devices
to facilitate future maintenance and optimize sectionalization.

Figure 1 shows a chart of the estimated spend by general activity. The new general activities
were implemented in January 2020.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 51 of 414
Minor Rebuild
Business Case Justification Narrative Page 4 of 9

Figure 1: Estimated General Activity split by cost

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem

1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
NA

Option Capital Cost Start Complete
Fund Unplanned Work (based on historical
quantities)
$10,000,000 Continuous Program
Some other Program covers the needed work. $10,000,000 Continuous Program
Unfunded $0 NA

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Historical spend was used to determine the requested amount. A steady increase in
costs for unplanned minor rebuild work has occurred for several reasons. Many assets on
the distribution system are past their end of life cycle and contributing to this increase.
The 3-year average actual spend for minor rebuild work is $11.9MM per year. This is
expected to continue for the next 5 years. Minor Rebuild spends approximately $1MM per
month. Figure 3 shows the historical spend amount by year. Starting in 2020, the Joint
Use spend is no longer included in the Minor Blanket Business Case as it now has its
own business case.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 52 of 414
Minor Rebuild
Business Case Justification Narrative Page 5 of 9

Figure 2: Minor Rebuild Historical Spend

In 2019 2,481 work orders were created with the average cost equaling $4,398, which
demonstrates the work is made up of thousands of small dollars, critical non-discretionary
jobs. Occasionally, larger rebuild projects such as small reconductor projects, are
undertaken as a Distribution Minor Rebuild project if prioritized by the Area Operations
Engineer. Only 53 of the 2,481 work orders created in 2019 were over $25,000. Those 53
work orders averaged $52,662.

Figure 2 displays a breakdown of the different types of charges that occur in the Minor
Rebuild business case. The majority of charges are from specific work orders. Distribution
Minor Rebuild work often consists of isolated replacement of failed asset(s) that do not lend
themselves to a specific project (i.e. trouble related work), which are charges falling under
craft and non-craft expenditures.

Figure 3: Types of Charges to Minor Rebuild (2019)

The following is a brief description of each type of charge.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 53 of 414
Minor Rebuild
Business Case Justification Narrative Page 6 of 9
• Craft Related Project Expenditures: Craft labor (servicemen, general
foremen, local rep), associated vehicle usage, trouble related work charges
• Non-Craft Related Project Expenditures: Non-craft labor, associated vehicle
usage, contribution reimbursables (credits), and material issues/returns
• Specific Work Order Charges: The work order number is referenced on
timesheets, material requests, invoices, and vehicle charges/loadings
The Non-Craft Project expenditures show a negative value due to customer contributions
being greater than charges.

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
Distribution Minor Rebuild is an ongoing program that focuses on keeping the distribution system
in reliable condition for customers, maintaining safe conditions for the workers, provides
providing responsiveness response to unplanned damages to distribution assets not related to
weather events, as well as responding to small customer driven rebuilds. Throughout the entire
distribution system, minor rebuilds, or replacement of asset units need to be completed to
maintain system reliability and safety. Spend will continue as it has in previous years.
The work includes; failed asset replacements, small mandatory and compliance work, slight
performance and capacity improvements, or unplanned customer requests. Occasionally, larger
projects with an identified need and short timeframe for implementation are constructed under
the Distribution Minor Rebuild business case. Even though the work is unplanned, Minor Rebuild
work occurs regularly due to the nature of the utility business and numerous assets in the field
spread over a wide geographical area.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
The Distribution Minor Rebuild business case has been in operation for several years so there
will be minimal impact to other business functions and processes with funding this business
case. Distribution Minor Rebuild reaches across multiple departments in Engineering and
Operations. The business involves operation area engineers, local customer project
coordinators, and construction technicians who work directly with customers and perform all
the designs for the business. Once the minor projects are designed and ready for construction,
field personnel such as a Foremen, Journeyman Linemen, Line Servicemen, Meter men,
Equipment Operators execute the work.

Not funding would have a significant impact on business functions and processes as other areas
would be responsible for the work and it would also impact the ability to respond to customers’
needs for modifications to their electrical service.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The other alternative that was considered is not funding the business case however, the needed
work will continue to occur. These costs would be covered under other business cases. The
body of work within the Distribution Minor Rebuild business case consists of very small
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 54 of 414
Minor Rebuild
Business Case Justification Narrative Page 7 of 9
unplanned projects across the entire distribution system in response to a variety factors
(customer requested, trouble related work, deteriorated pole replacements, and general
rebuilds), therefore the alternatives are generally not available to analyze. Typically, as each
project arises, any alternatives available for individual rebuild projects are evaluated during the
design phase by the designer.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
The Distribution Minor Rebuild business case is an on-going program, and assets typically go
into service at the time the project (service order/ job) is completed and does not have a final
cost. The program has an average annual cost around $11.5MM. The minor rebuild projects are
so small in nature they almost always go into service the same day as constructed

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
The Distribution Minor Rebuild business aligns with the company’s focus of Our Customers, Our
People, and Perform by investing in our infrastructure to achieve optimum life-cycle performance
– safely, reliably and affordably. This business case provides a solution to address those small
unplanned asset failures and customer driven modifications to the distribution system.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The Distribution Minor Rebuild business maintains flexibility for the utility to address small,
unplanned asset failures and customer driven modifications to the distribution system but,
excludes fixes to the system considered to be maintenance. While the work is unplanned, minor
rebuilds to the distribution system occur on a regular basis every year to maintain system
reliability and safety. The Distribution Minor Rebuild business case provides a solution for the
utility to address those small unplanned asset failures and customer driven modifications to the
distribution system. Safety is of utmost concern for linemen and the general public and the minor
rebuild business case provides the funding for work. Some minor rebuilds left unrepaired may
not result in an immediate catastrophic failure. Over time an adverse accumulation of unrepaired
assets would greatly put line workers and the general public at risk as minor asset failures begin
to deteriorate pockets of the distribution system.

The YTD spend is tracked and reviewed each month during the Electric Operations Roundtable
(ORT) meetings. The ORT, reviews monthly spend and manages any additional funds requests.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Stakeholders that interface with the Distribution Minor Rebuild work are the local area
operations engineers, general foremen, and area construction managers.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 55 of 414
Minor Rebuild
Business Case Justification Narrative Page 8 of 9

2.8.2 Identify any related Business Cases
None

3.1 Steering Committee or Advisory Group Information
The Operations Roundtable (ORT) acts as the Advisory Group for this business case. The
Distribution Minor Rebuild work is managed by the local area operations engineers, general
foremen, and area construction managers.
3.2 Provide and discuss the governance processes and people that will
provide oversight
The governance in place over the business case is set by the Operations Roundtable (ORT)
group, which proposes annual budgets, monitors the incurred costs and submits any additional
funds requests as needed.
The work done under Minor Rebuild, by way of projects, is overseen by Area Engineers. Area
Engineers receive a weekly report on all active work orders under the business and managed
which projects get done according to current needs and priorities. The local customer project
coordinators (CPCs), who design the projects, are required to seek Area Engineer approval for
projects above a $10,000 threshold before performing the work.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Decision making, prioritization and change requests will be documented and monitored though
the Operations Roundtable (ORT).

The undersigned acknowledge they have reviewed the Minor Rebuild and agree
with the approach it presents. Significant changes to this will be coordinated with
and approved by the undersigned or their designated representatives.

Signature: Date:
Print Name: Amy Jones
Title: Asset Maintenance Business
Analyst

Role: Business Case Owner

08/01/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 56 of 414
Minor Rebuild
Business Case Justification Narrative Page 9 of 9
Signature: Date:
Print Name: David Howell
Title: Director of Operations
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
8/2/20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 57 of 414
Distribution Transformer Change Out Program
Business Case Justification Narrative Page 1 of 8
EXECUTIVE SUMMARY

The Transformer Change Out Program (TCOP) was originally implemented in 2011. The Program is
focused on removing or replacing transformers containing, or potentially containing, Polychlorinated
Biphenyls (PCB) oil. In 2020, there were 284 targeted transformers remaining. This impacts customers in
WA and ID.

In 2020, the program was funded at $541,000, for 2021 we are requesting $500,000. The benefit to
customers is decreasing environmental risk. This program is anticipated to be completed by the end of
2021. If not funded or if deferred, it does increase the risk of environmental hazards (i.e. oil spill).

VERSION HISTORY
Version Author Description Date Notes
Draft Amy Jones Initial draft for 2020 business case refresh 6/30/2020
1.0
1.1
2.0

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 58 of 414
Distribution Transformer Change Out Program
Business Case Justification Narrative Page 2 of 8
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The Transformer Change Out Program (TCOP) was originally implemented in 2011. The
Program has focused on eliminating transformers containing or potentially containing
Polychlorinated Biphenyls (PCB) oil. The areas initially targeted were near the Spokane and
Pend Oreille River watersheds and has since moved to all transformers containing PCBs. These
transformers have specific work plans for removing them from the system. At the start of 2020,
there were 284 targeted transformers remaining and scheduled to be replaced by the end of
2020. However, over the past two (2) years, the carryover from the previous year has been
approximately 50%. For 2021, an estimated carryover-total of 150 targeted transformers is
expected.
BACKGROUND:
PCBs and PCB wastes are regulated by both the Washington Department of Ecology (Ecology),
through the Dangerous Waste Regulations, Chapter 173-303 WAC, and by the U.S.
Environmental Protection Agency (EPA) under 40 CFR Part 761, the Toxic Substances Control
Act (TSCA). The transformers to be removed early in the program are those that are most likely
to have PCB-containing oil and their replacement will reduce the risk of PCB-containing oil spills
which are a public safety, environmental, and a public relations concern.
On April 10, 2010, the EPA had issued an Advanced Notice of Proposed Rulemaking (ANPR)
on new PCB regulations. Washington State Department of Ecology created an “urban waters
initiative” to investigate persistent and bio-accumulative toxins; this initiative included the
Spokane River watershed. The Spokane River is listed on the Clean Water Act “impaired” list
for PCB contamination. The City of Spokane began a storm water study to find and reduce
sources of PCBs in its storm water system. In addition, PCB cleanup is very difficult in any
environment and nearly impossible in aqueous environments. These and other efforts reflect
how important it is to keep PCBs from entering the environment. As a result, Avista is
determined to aggressively remove PCBs from its electrical distribution system in a disciplined
manner.

Requested Spend Amount $500,000
Requested Spend Time Period 1 Year (2021)
Requesting Organization/Department Asset Maintenance
Business Case Owner | Sponsor Amy Jones | David Howell
Sponsor Organization/Department Operations
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 59 of 414
Distribution Transformer Change Out Program
Business Case Justification Narrative Page 3 of 8
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The driver for TCOP is Asset Condition. However, by removing these targeted transformers, the
environmental and public safety risks associated with these transformers will also be addressed.

Customer Benefit: Avista customers will be impacted by this program positively through safe
equipment.

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Currently there are 264 targeted transformers remaining (as of May 30, 2020). There are
environmental risks associated with these transformers (large volume transformer oil spill,
hazardous waste cleanup, moderate to low volume or level of PCBs, impacts to waterways,
repeated or moderate air emission exceedance). PCB cleanup is very difficult in any
environment and nearly impossible in aqueous environments. These and other efforts reflect
how important it is to keep PCBs from entering the environment. In addition, environmental spill
cleanup for PCBs can be costly. If not funded or deferred, the risk is low due to the small
number of remaining transformers.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
This Program has been successful throughout previously funded years. It is anticipated that all
transformers will be replaced by the end of 2021.
Metrics that will be used to determine successful delivery throughout the program year include:
 Planned vs replaced transformers
 Count of remaining transformers
 Budget to actual spend

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
References:
 “Distribution Transformer PCBs” report, February 2010
 Electric Distribution System, 2016 Asset Management Plan

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 60 of 414
Distribution Transformer Change Out Program
Business Case Justification Narrative Page 4 of 8
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.

Option Capital Cost Start Complete
Continue to replace targeted transformers. $500,000 01 2021 12 2021
17,241 transformers have been replaced
since the start of the program. As of
5/30/2020, there are 264 pending
replacement due to PCB containing oils.
We anticipate 150 remaining at the end
of 2020.
This program has been successful in
meeting its objective.
Remaining TCOP transformers are
included in the All System Active count.
The remaining targeted transformers
represent .02% of all active transformers.
All targeted transformers (retired and
remaining) represent approximately 14% of
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 61 of 414
Distribution Transformer Change Out Program
Business Case Justification Narrative Page 5 of 8
No planned replacement program for distribution
transformers and the replacement would occur
organically through storm replacement or as
projects occur on the pole. Substantially higher risk
of a PCB containing oil spill occurring.
$0 NA
Planned replacement of PCB transformers only
through programmatic work over the next 20 years.
$670,000 01 2021 12 2041

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.

When the program began in 2011, there were over 17,000 targeted transformers. Currently,
.02% of the 17,000 are remaining. This program has been successful in replacing targeted
transformers.
Metrics considered during the analysis of this program included;
 Count of remaining transformers
 Historical review of yearly planned vs. actual transformers
 Yearly budget to actual spend

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
The requested capital cost amount will be spent on replacing targeted TCOP transformers for
newer models that do not contain PCBs. The costs associated with the change outs will be for
designs, labor, and material associated with each replacement.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
The outcomes of this business case impact each construction office and their remaining TCOP
transformers. The work to replace the targeted transformers is widely used for fill-in work for
crews. There is also an environmental impact if spills were to occur.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
This Program has been funded since 2011. There were several alternatives that considered
different implementation schedules. The current approach is considered the best solution for
mitigating environmental risk.

Two alternatives exist as mentioned above.
1. No planned replacement program for distribution transformers. Substantially higher risk of
a PCB-containing oil spill occurring. Transformers would be replaced through a reactionary
method either through a spill that may occur, through storm or other type of damage
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 62 of 414
Distribution Transformer Change Out Program
Business Case Justification Narrative Page 6 of 8
replacement or through random projects. Transformers containing PCB oils would remain
active in our system for years through this method.
2. Planned replacement of PCB transformers only through programmatic work. This method
would be a very slow pro-active progression. Through this method, transformers containing
PCB oils would also remain active in our system for years.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
This program has been in operation since 2011 and is set to be completed by the end of 2021.
The newly installed transformers and other materials become used and useful immediately at
the time of install. Transformers are replaced throughout the year.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This program aligns with the company’s strategic vision, goals, objectives and mission
statement with its focus on customers by reducing environmental impacts through replacement
of older transformers containing PCBs.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
This project has been in operation since 2011. Currently there are 264 targeted transformers
remaining (as of May 30, 2020). The Transformer Change-Out Program (TCOP) work is needed
for the following reason. Asset Management periodically reviews maintenance strategies.

The targeted transformers contain, or have the potential to contain, Polychlorinated Biphenyls
(PCB) oil. PCBs and PCB wastes are regulated by both the Washington Department of Ecology,
through the Dangerous Waste Regulations, Chapter 173-303 WAC, and by the U.S.
Environmental Protection Agency under 40 CFR Part 761, the Toxic Substances Control Act.
The transformers to be removed early in the program are those that are most likely to have PCB
containing oil and their replacement will reduce the risk of PCB containing oil spills which are a
safety, environmental, and a public relations concern.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Avista stakeholders include;
 The Asset Maintenance Department who is responsible for the work.
 The Environmental Department that is responsible for our environmental footprint in our
service territory.
 Electric Operations that will perform the construction work.
 Asset Management for tracking system reliability and risk.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 63 of 414
Distribution Transformer Change Out Program
Business Case Justification Narrative Page 7 of 8

2.8.2 Identify any related Business Cases
None

3.1 Steering Committee or Advisory Group Information
This program is managed by the Asset Maintenance Department and progress is overseen by
the Operations Round Table

3.2 Provide and discuss the governance processes and people that will
provide oversight
Early in the program, asset condition and outage information were collected and analyzed by
Asset Management. This information was reviewed with Asset Maintenance to establish an
effective risk mitigation plan that prioritizes work by frequency and duration of outages.
Currently, the Environmental group provides prioritization guidance as needed. Asset
Maintenance manages the program and collaborates with Electric Operations and Contractors
to coordinate the work. Asset Maintenance tracks the work budget, scope, and schedule.

3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Through existing work planning documentation and through recommendations from the ORT.

The undersigned acknowledge they have reviewed the Distribution Transformer
Change Out Program and agree with the approach it presents. Significant changes
to this will be coordinated with and approved by the undersigned or their designated
representatives.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 64 of 414
Distribution Transformer Change Out Program
Business Case Justification Narrative Page 8 of 8

Signature: Date:
Print Name: Amy Jones
Title: Asset Maintenance Business
Analyst

Role: Business Case Owner

Signature: Date:
Print Name: David Howell
Title: Director of Operations
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
8/2/20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 65 of 414
LED Street Lights
Business Case Justification Narrative Page 1 of 9
EXECUTIVE SUMMARY
Any local or state government which has jurisdiction over streets and highways has an obligation to the
general public they serve to provide acceptable illumination levels on their streets, sidewalks, and/or
highways intended for vehicle driver and pedestrian safety. Avista manages streetlights for many local and
state government entities to provide such street, sidewalk, and/or highway illumination for their streets by
installing overhead streetlights. Upon light burn-out, lights are converted to LED. This work occurs in WA
and ID.

Since this is a service our customer’s pay for, they benefit from lighting service being restored upon light
burn-out. Based on our historical burn-out rate, a spend of approximately $750,000 is needed. If this
business case is not approved, failed lighting may not get replaced, resulting in customer dissatisfaction
and increased public safety risks.

VERSION HISTORY
Version Author Description Date Notes
Draft Amy Jones Business Case Refresh Draft 7/2/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 66 of 414
LED Street Lights
Business Case Justification Narrative Page 2 of 9
GENERAL INFORMATION

1. BUSINESS PROBLEM

1.1 What is the current or potential problem that is being addressed?
Any local or state government which has jurisdiction over streets and highways has an obligation
to the general public they serve to provide acceptable illumination levels on their streets,
sidewalks, and/or highways intended for driver and pedestrian safety. Because they have an
overhead distribution system in most urban areas, Avista provides a convenient streetlight
service in almost every local and state government entity they serve, and manages the
streetlights to provide street, sidewalk, and/or highway illumination.
Initially, the LED Change-Out Program was on an accelerated five-year schedule (2015 – 2019)
to change-out all existing Avista owned streetlights to LED (Light Emitting Diode).
In the spring of 2018, upon Asset Management review, Avista executives, directors, and team
leaders decided to adapt the replacement strategy to replace lights as they burned out.
Background:
The desire to begin the LED Change-Out Program in 2015 stems from a delay in energy savings,
negative financial impacts, associated personal injury and property theft risks, and resource
needs. Benefits are also found in the 2013 Asset Management Street Light Plan.
 Each 100 watt and 200-watt HPS light replaced will save 65 watts and 128 watts,
respectively, per fixture. Once all the 100 watt and 200-watt HPS streetlights are
replaced, the annual energy savings will be 9,903 MWH each year.
 With respect to the financial impacts of converting to LED streetlight technology, the
customer internal rate of return is 8.46%, assuming the current cost of materials and life
expectancy of the photocells and LED streetlight fixtures.
 From a public safety perspective, the consequence of converting to LED streetlights in
lieu of replacing burned-out HPS bulbs shows a risk reduction of nearly eight times less
for potential injury, a serious fatal accident, and property theft.
 Lastly, company resource demands are reduced after the initial conversion to LED
technology. The average annual labor man-hours for current practices of changing
burned-out HPS bulbs is estimated at 5,200 man-hours and 2,600 equipment hours,
while the average man-hours required during the life of the LED fixtures are 3,200 man-
hours and 1,800 equipment hours.
Requested Spend Amount $750,000 annually
Requested Spend Time Period Ongoing program
Requesting Organization/Department Electric Operations
Business Case Owner | Sponsor Amy Jones | David Howell
Sponsor Organization/Department Operations
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 67 of 414
LED Street Lights
Business Case Justification Narrative Page 3 of 9
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The primary driver for converting overhead streetlights from High-Pressure Sodium (HPS) lights
to LED lights is Asset Condition. By focusing on Asset Condition, there will be a significant
improvement in energy savings, lighting quality for customers, and resource cost savings.
Secondly, converting streetlights to LED technology helps bring Avista in compliance with the
Washington State Initiative 937 (or the Clean Energy Initiative), which ensures that at least
fifteen percent of the electricity Washington state gets from major utilities comes from clean,
renewable sources, and that Washington utilities undertake all cost-effective energy
conservation measures. LED streetlight technology is part of the mentioned energy conservation
measure.

1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Any local or state government which has jurisdiction over streets and highways has an obligation
to the general public they serve to provide acceptable illumination levels on their streets,
sidewalks, and/or highways intended for driver and pedestrian safety. Due to having an
overhead distribution system in most urban areas, Avista provides a convenient streetlight
service in almost every local and state government entity they serve, and manages the
streetlights to provide street, sidewalk, and/or highway illumination.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Measures to determine success include:
 Count of Replacements per year.
 Energy savings per year.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
 LED Replacement Analysis - One Pager
 2013 Street Light Asset Management Plan - Final

1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
A lifetime material usage analysis on the HPS light fixtures estimated a mean time to
failure (MTTF) for the various light fixture components. Table 1 shows the results for
each streetlight component.
Component Groups Material Usage
Quantities
Replacement
Ratio MTTF (Years)
fuse 641 1% 84
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 68 of 414
LED Street Lights
Business Case Justification Narrative Page 4 of 9
Lamp 7,930 15% 7
photocell 5,151 10% 10
starter board 1,126 2% 48
streetlight fixture 683 2% 55
Table 1: 2011 Mean Time to Failure (MTTF) for HPS Streetlights

Upon completion of all streetlights changed out to LED fixtures, energy savings can be
measured on an individual light fixture basis and then extrapolated to the entire system.
Also, once all the streetlights are converted to LED, the number of service requests for
streetlight burn-out should drop from the number of service requests prior to 2015.

Option Capital Cost Start Complete
RECOMMENDED: Base Case (current practice of
replacing burned-out HPS bulbs or replacing a
fixture if broken)
$750,000 Ongoing program
ALT #1: Optimized Case (planned replacement of
HPS bulbs and photocells)
$1.67M 1/1/2015 Ongoing -
15-year
cycle
replacement
ALT #2: LED Case (change-out all fixtures to
LED)
$2.32M 1/1/2021 5- or 10-
years cycle
bulb vs
photocell.

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Three alternative cases were initially considered in the analysis of converting the streetlight to
LED technology. Base Case replaces failed streetlight components only when they fail. The
second case, called the LED Case, replaces the current HPS streetlights with new LED fixtures
and implements a planned replacement at fifteen years for the fixture and photocell. At the time
of the initial analysis, a fifteen-year replacement strategy proved more cost effective over the
lifecycle than running LED lights to failure. Thirdly, the Optimized Case represents keeping the
current HPS light fixtures and performing planned replacements of the bulbs and photocells at
five-year cycles for the bulbs and ten-year cycle for the photocells.
In 2018, the replacement strategy moved from a five-year proactive program strategy to a run
to failure (or “burn-out”) strategy. A run to failure strategy is the same as the Base Case
mentioned above. By the end of 2018, nearly all Avista owned cobrahead streetlights had been
converted to LED, with the majority of the remaining HPS streetlights in Idaho; mainly Coeur d
Alene, Lewiston, Moscow, and Grangeville. However, thousands of customer area lights and
thousands of decorative streetlights remained as HPS throughout the entire service territory and
were being converted to LED on a burn-out replacement strategy. Because LED conversions of
area lights and decorative streetlights have nearly the same cost savings and energy savings
as the cobrahead streetlights, the program sponsors supported Asset Maintenance’s proposal
to expand the scope of the program to include both types of lights. Starting in 2019, all area and
decorative streetlights changed out will be charged to the LED Change Out Program.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 69 of 414
LED Street Lights
Business Case Justification Narrative Page 5 of 9

Key assumptions made in the alternative’s analysis are outlined below.
 The Base Case and the Optimized Case, because they propose using HPS fixtures,
have the same failure characteristics shown in Table 2.

Table 1, HPS Light Component Failure Characteristics
Component
Initial Population
Failure Rate (10%) by
Year___
Initial Population
Failure Rate (20%) by
Year___
Mean Time to Failure
(50% of the initial
population will have
failed by ____ Years)
100-Watt Bulb 3.4 4.4 6.7
Photocells 5.7 7.3 10.6
Starter Board 7.4 10.5 16.3

Table 2 shows the failure characteristics assumed for LED fixtures and components based on
manufacturer’s information and an assumed failure shape characteristic.

Table 2, Assumed LED Light Component Failure Curves
Component
Initial Population
Failure Rate (10%) by
Year___
Initial Population
Failure Rate (20%) by
Year___
Mean Time to Failure
(50% of the initial
population will have
failed by ____ Years)
New Style Photocell 7.9 10.2 14.9
LED Light Fixture 12.1 15.5 22.6

For each of the cases, a model was created to help compare the risks, resource needs, potential
energy savings, and financial impacts of each case. In the end, the LED Case will save customers
money over the Base Case. While the Optimized Case provides a better financial return to our
customers compared to both the Base Case and LED Case. The customers will still see savings
over the life of the LED fixtures compared to today’s practices in the Base Case and eliminate
the need for 2.3 Megawatts of generation at night.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
The LED Change Out Program currently replaces LED lights upon failure (burn-out). Funding
calculations are based on historical spend (2019 spend was approx. $678,000).

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 70 of 414
LED Street Lights
Business Case Justification Narrative Page 6 of 9
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
The impacts of the LED Change-Out Program span across many departments at Avista.
Operations is responsible for managing the work and executing the light change-outs in the field,
primarily by Avista’s servicemen and local reps. Avista’s Operations Support Group (Mobile
Dispatch) and EAM Technology are responsible for creating work orders for all change-outs and
dispatching them to the field. The Customer and Shared Services department, particularity the
Enterprise Systems – CC&B, is impacted by the project because the customer billing changes
upon converting to LED light fixtures.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Three alternative cases were initially considered in the analysis of converting the streetlight to
LED technology. Base Case replaces failed streetlight components only when they fail. The
second case, called the LED Case, replaces the current HPS streetlights with new LED fixtures
and implements a planned replacement at fifteen years for the fixture and photocell. The
analysis noted that inside the new LED Case model, a fifteen-year replacement strategy proved
more cost effective over the lifecycle than running LED lights to failure. Thirdly, the Optimized
Case represents keeping the current HPS light fixtures and performing planned replacements
of the bulbs and photocells at five-year cycles for the bulbs and ten-year cycle for the photocells

For each of the cases, a model was created to help compare the risks, resource needs, potential
energy savings, and financial impacts of each case. In the end, the LED Case will save
customers money over the Base Case. While the Optimized Case provides a better financial
return to our customers compared to both the Base Case and LED Case. The customers will
still see savings over the life of the LED fixtures compared to today’s practices in the Base Case
and eliminate the need for 2.3 Megawatts of generation at night.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
This is an ongoing program that started in 2015.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
The LED Change-Out Program is in alignment with the company’s strategic vision of delivering
reliable energy service and the choices that matter most to our customer’s. As part of the
program, infrastructure is replaced with longer lasting equipment. By providing more efficient
equipment and quality lighting, this results in an energy savings and an increase in driver and
pedestrian safety for our customers and communities we serve.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 71 of 414
LED Street Lights
Business Case Justification Narrative Page 7 of 9
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Any local or state government which has jurisdiction over streets and highways has an obligation
to the general public they serve to provide acceptable illumination levels on their streets,
sidewalks, and/or highways intended for driver and pedestrian safety. Due to having an
overhead distribution system in most urban areas, Avista provides a convenient streetlight
service in almost every local and state government entity they serve, and manages the
streetlights to provide street, sidewalk, and/or highway illumination.
Results of this program include; significant improvement in energy savings, lighting quality for
customers, and resource cost savings.
Secondly, converting streetlights to LED technology helps bring Avista in compliance with the
Washington State Initiative 937 (or the Clean Energy Initiative), which ensures that at least
fifteen percent of the electricity Washington state gets from major utilities comes from clean,
renewable sources, and that Washington utilities undertake all cost-effective energy
conservation measures. LED streetlight technology is part of the mentioned energy conservation
measure.
The YTD spend is tracked and reviewed each month during the Electric Operations Roundtable
(ORT) meetings. The ORT reviews monthly spend and manages any additional funds requests.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
The LED Change-Out Program extends across multiple departments at Avista impacting
them directly or indirectly. Each department identified as a stakeholder will nominate an
engaged representative to act as the liaison between the program and their department.
The department stakeholder representative will also take part to promote their
department’s interests in the business. Some internal departments include; Construction
Services, Distribution Engineering, Warehouse and Investment Recovery, Supply Chain,
External Communications, Mobile Dispatch, Enterprise Asset Management, Customer
Enterprise Technology, and Regional Business Managers.
External stakeholders in the program include all state, county, and local agencies that have
a streetlight account with Avista, as well as neighborhood councils, and local law
enforcement agencies. All external stakeholders have a vested interest in the business
because the streetlights illuminate their streets and sidewalks for the purpose of public
safety.

2.8.2 Identify any related Business Cases
 Grid Modernization: With HPS lights changed out as they fail, Grid Modernization is
likely to find and convert more HPS lights on selected feeders. (The System Wide DFMP
says on page 34 that designers should change HPS lights when performing work in the
supply space of a pole.)
3.1 Steering Committee or Advisory Group Information
The ORT acts as the advisory group for the LED Change Out Program.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 72 of 414
LED Street Lights
Business Case Justification Narrative Page 8 of 9
3.2 Provide and discuss the governance processes and people that will
provide oversight
The governance in place over the business case is set by the Operations Roundtable (ORT)
group, which sets forecasted budgets, monitors the incurred costs and submits any additional
funds requests as needed. LED Change Out Program work is overseen by the local area
operations engineers and area construction managers.

3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Decision making, prioritization and change requests will be documented and monitored though
the Operations Roundtable (ORT).

The undersigned acknowledge they have reviewed the LED Street Lights and
agree with the approach it presents. Significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.

Signature: Date:
Print Name: Amy Jones
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 73 of 414
LED Street Lights
Business Case Justification Narrative Page 9 of 9
Title: Asset Maintenance Business
Analyst

Role: Business Case Owner

Signature: Date:
Print Name: David Howell
Title: Director of Operations
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
8/2/20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 74 of 414
Primary URD Cable Replacement 2017
Requested Spend Amount $1,000,000
Requesting Organization/Department Asset Maintenance
Business Case Owner Cody Krogh
Business Gase Sponsor Bryan Cox
Sponsor Organization/Department Asset Maintenance
Gategory Program
Driver Asset Condition
I GENERAL INFORMATION
1.1 Steering Committee or Advisory Group lnformation
Cable condition and outage information is collected and analyzed by Asset
Management. This information is reviewed with Asset Maintenance to establish an
effective construction plan that prioritizes work based on faults and number of
customer impacted. Asset Maintenance then collaborates with Electric Operations
to coordinate the work. Asset Maintenance tracks the work budget, scope, and
schedule.
2 BUS¡NESS PROBLEM
The primary driver for the Underground Residential Development (URD) Cable
Replacement Program is to improve system reliability by removing URD cable with a high
failure rate. The other driver is to reduce O&M costs related to responding to customer
outages caused by the failed cable.
This work is needed to complete the replacement of the un-jacketed first generation
underground primary distribution cable referred to as URD cable. This first generation
URD cable was installed from 1971to 1982. There was over 6,000,000 feet of URD cable
installed during this time period. Subsequent to installation the URD cable began to
experience an increasing failure rate. From 1992 to 2005 the cable failure rates
quadrupled from 2 faults to I faults per 10 miles of cable. The faults reached a peak of
238 annual failures in 2007. lncreased capital funding to replace this URD cable from
2OO5 through 20Og helped stabilize the failure rates. Continued funding and replacement
of the cable has enabled a downward trend in failures as shown below in table 1. Cable
installed after 1982 has not shown the high failure rate.
This work is required to continue to reduce primary URD cable failures and increase
reliability. Historically there have been over 200 cable faults per year. The average cost
to respond to a fault in 2015 was about $3000 per event due to the challenging nature of
the work to locate and repair the cable underground. The estimated remaining pre-1982
cable is around 1,000,000 circuit feet.
Business Case Justifìcation Narrative Page 1 of4
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 75 of 414
Primary URD Cable Replacement 2017
The tables below demonstrate the effectiveness of this program to reduce faults and
outage expenses through the replacement of the defective cable. The trend of cable
faults and expenses decrease over time as the older cable is removed from the system.
Tablel: URD Cable Replacement Results
Projected
URD
Cable -
Primary
OMT
Events
Actual
URD
Cable -
Primary
OMT
Events
Projected
Number
of Feet
Replaced
Actual
Number
of Feet
Replaced
KPI
Description
2009
20LO
20LL
20L2
20L3
20L4
20L5
L43
119
94
70
45
45
45
Table 2: URD Cable Replacement Cost lmpact
S1,03a,613
sr,229,275
$1,368,561
S1,516,159
$L,74r,s99
S1,998,311
$t,997,o52
136
93
95
72
93
88
64
178,000
178,000
178,000
178,000
0
0
0
213,000
2I7,883
225,823
L17,247
35,874
35,515
24,155
S1,056,113
st,295,225
St,ïsz,6qg
$1,481,504
$1,494,799
$1,580,379
$t,7zo,ozo
Reference:
Electric Distribution System, 2016 Asset Management Plan
Projected Avoided
Outage Benefit due
to URD Cable - Pri
Caused Outages
ActualAvoided
Outage Benefit due
to URD Cable - Pri
Outages
Metric
Description
2009
2010
20LL
20t2
20t3
20L4
20L5
Business Case Justification Narrative Page 2 of 4
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 76 of 414
Primary URD Cable Replacement 2017
3 PROPOSAL AND RECOMMENDED SOLUTION
Gapital Cost Start Complete
Do nothing $o
[Recommended Solution] Continue to Replace $1M 04 2017 122037
The Primary URD Cable Replacement Program requires design resources and
construction labor to complete the field work. There is also some analytics/engineering
to identify remaining cable segment locations. Given the projected low capital spend
level, the majority of the construction labor will be performed by Avista Crews. Contract
crews are typically used to plow in the cable, bore conduit or trench and install conduit in
the trench. Avista crews then pullthe cable into the conduit and complete the installation.
The Do Nothing approach presents significant reliability risk and added O&M cost. The
historic positive results from the URD cable replacement program shown above in section
two provide strong justification for continuing the current funding plan.
Over 6,000,000 feet of URD was installed before 1982. Programmed replacement of the
problem cable has been on-going at varying funding levels. The estimated remaining
pre-1982 cable is around 1,000,000 circuit feet. At the current proposed funding rate of
$1M per year this program is planned for the next 20 years. Reduced funding would
extend this time and result in additional outages and O&M expenses.
The URD Cable Replacement Program aligns with Avista's strategic vision by increasing
reliability to the electric distribution system. Safe and Reliable infrastructure is the focus
area for this program.
The projected annual capital spend of $1M per year is reasonable based on the realized
reduction in faults from previous work and this spend level enables continued
replacement of the high failure rate cable. Repair of the cable has not shown to be cost
effective because the cable typically faults in another location.
Avista customers will be positively impacted by this program by realizing fewer outages
from the URD cable failure. This results in improved system reliability. Avista electric
operations is positively impacted through converting this work to planned work that
enables more efficient use of labor. lt also reduces O&M expenses. Asset Management
is responsible for tracking URD cable outages from Outage Management Tool (OMT) and
tracking replacement locations and cost. The Asset Maintenance group is responsible
for identifying cable segments and managing the coordination of work.
Business Case Justification Narrative Page 3 of 4
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 77 of 414
Primary URD Cable Replacement 2017
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Primary URD Cable
Replacement and agree with the approach it presents and that it has been approved
by the steering committee or other governance body identified in Sectionl.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Business Case Owner
Cody
Mgr Asset Maintenance
Date: 4- l4- ?et
? *\7 -\1
Bryan Cox
Sr Dir of HR Operations
Date:
Tem pf ate Version : 03107 l2O1 7
Business Case Sponsor
5 VERS¡ON HISTORY
Vereion lmplemented
By
Revlsion
Date
Approved
By
Approval
Date
Reason
1.0 Cody Krogh 4t1412017 Bryan Cox 4t14t2017 lnitialversion
Business Case Justification Narrative Page 4 of 4
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 78 of 414
Substation – Station Rebuilds Program
Business Case Justification Narrative Page 1 of 7
EXECUTIVE SUMMARY
This section is reserved to provide a brief description of the business case and high level summary of the projects or
programs included. Please limit to no more than 2 paragraphs. Components that should be included: 1) a synopsis of
the problem, 2) the service code and jurisdiction of customers impacted, 3) the recommended solution, 4) the cost of
the solution, 5) how the solution will benefit customers identified, 6) the significance of the timeline and 7) the risks of
not approving this business case.
<< Both the Executive Summary and Version History should fit into one page >>

Replacing and upgrading major substation apparatus and equipment as it approaches end of
life or becomes obsolete is necessary to maintain safe and reliable operation of Avista's
transmission and distribution systems. Rebuilding significant portions of stations may be
necessary to accommodate the replacement of failing or obsolete equipment since new standard-
use apparatus and equipment is often of higher capacity and newer technology and may need
to meet updated equipment spacing and operating standards.
Failure to replace old and obsolete equipment will increase the risk of more frequent and/or
extended duration of outages due to major equipment failure and inability to maintain major
apparatus. Substation outages may have significant consequences as they tend to impact a
large number of customers. This Business Case is important for customers because it is critical
toward Avista’s ability to continue to provide the reliable electrical service that customers have
grown accustom to receiving.
Service: ED – Electric Direct
Jurisdiction: Various. Each rebuild project has its own Jurisdiction.
Engineering Roundtable Request Number: Various. Each rebuild project has its own ERT
Request.
2020 Expected Spend: $18,900,000

VERSION HISTORY
Version uthor Description Date Notes
1.0 Ken Sweigart Initial Version 4/14/2017
2.0 Jeff Schlect
Consolodation of capital
maintenance and major rebuild
business cases
5/19/2017
3.0 Karen Kusel /
Glenn Madden Update to 2020 Template 6/30/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 79 of 414
Substation – Station Rebuilds Program
Business Case Justification Narrative Page 2 of 7
GENERAL INFORMATION
1 BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
Replacing and upgrading major substation apparatus and equipment as it approaches end
of life or becomes obsolete is necessary to maintain safe and reliable operation of Avista's
transmission and distribution systems. Rebuilding significant portions of stations may be
necessary to accommodate the replacement of failing or obsolete equipment since new
standard-use apparatus and equipment is often of higher capacity and newer technology
and may need to meet updated equipment spacing and operating standards. While asset
condition is the primary driver triggering the need to replace major apparatus and
equipment, additional factors that may contribute to the need to broaden the scope of a
station rebuild project include operational and maintenance requirements, updated design
and construction standards, SCADA communications, future customer load-service needs,
and other programs (e.g. Grid Modernization).
Major apparatus include high-voltage circuit breakers, lower voltage circuit breakers and
reclosers, circuit switchers, capacitor banks, power transformers and step voltage
regulators. Associated equipment includes relays, meters, surge arrestors, station rock and
fencing, panel houses, instrument transformers, high voltage fuses, air switches,
autotransformer diagnostic equipment, batteries and chargers, and panel houses.
Failure to replace old and obsolete equipment will increase the risk of more frequent and/or
extended duration of outages due to major equipment failure and inability to maintain major
apparatus. Substation outages may have significant consequences as they tend to impact
a large number of customers.
1.1 What is the current or potential problem that is being addressed?
Aging apparatus and equipment plus changes in customer needs and compliance
requirements.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer Service
Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset Condition, or
Failed Plant & Operations) and the benefits to the customer
The major driver of the business case is Asset Condition. Good asset condition leads to
fewer customer outages.
Requested Spend Amount $20,000,000 per year
Requested Spend Time Period On Going
Requesting Organization/Department T&D – Substation Engineering
Business Case Owner | Sponsor Glenn Madden | Josh DiLuciano
Sponsor Organization/Department T&D
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 80 of 414
Substation – Station Rebuilds Program
Business Case Justification Narrative Page 3 of 7
1.3 Identify why this work is needed now and what risks there are if not approved or is
deferred
This is an on-going program to stay ahead of the curve of asset age and condition.
1.4 Identify any measures that can be used to determine whether the investment would
successfully deliver on the objectives and address the need listed above.
General age of all major substation equipment.
System Planning Assessments.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information; do not attach]
System Planning Assessments, Maximo Work Orders.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.
As of July 2020, here are samples of data we use to view asset information used to
determine viable options for substation rebuilds.

Equipment Type Average Manuf Year
Air Switch 2005
Breaker Recloser 2000
Circuit Switcher 1991
HV Circuit Breaker 1996
Power Transformer 1986
Switchgear Breaker 1985
Voltage Regulator 2002

Equipment Type Oldest Mfg Yr and Substation
Air Switch 1930 - Leon Jct
Breaker Recloser 1924 - South Lewiston
Circuit Switcher 1968 - Osburn
HV Circuit Breaker 1952 - Sunset
Power Transformer 1946 - Garfield
Switchgear Breaker 1963 - Chester
Voltage Regulator 1960 - Bunker Hill

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 81 of 414
Substation – Station Rebuilds Program
Business Case Justification Narrative Page 4 of 7
Location Avg Age of Major
Equipment
Coeur Shaft Mine 13kV 1961
Chester 115kV 1974
Rockford 115kV 1975
Post Falls 115kV 1977
Dry Gulch 115kV 1978
Wallace 115kV 1979
Metro 115kV 1979
South Lewiston 115kV 1980
Roxboro 115kV 1981
Leon Jct. 115kV 1981

2 PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]
The recommended approach is to replace station apparatus and equipment as needed due
to asset condition and consider broader station rebuilds when the majority of assets in the
impacted area of a station have been determined to have reached their end of life.
This business case aligns with the Company's mission to deliver safe and reliable electric
service to customers by preventing the degradation of reliability and mitigating the
frequency and duration of outages due to equipment failure.
Option 1: Do nothing - Not recommended
Option 2: Maintain current funding level - Current spending on the Asset Condition risk
category is $12.85 million annually. Project prioritization will be supported by Asset
Management and substation subject matter experts for prioritization of work within this risk
category. Project and funding levels will be reviewed on an annual basis.
Option 3: Reduce current Asset Condition capital improvements. Not recommended. May
lead to a reduction in the level of reliability and or operating flexibility that can be achieved
by the transmission and distribution systems.
Option Capital Cost Start Complete
Maintain present level of Station Rebuilds $20M On Going On Going
Alternate 1: Do nothing $0M
Alternate 2: Maintain minimum level of Station
Rebuilds
$0-12M -
2.1 Describe what metrics, data, analysis or information was considered when preparing
this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
-
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 82 of 414
Substation – Station Rebuilds Program
Business Case Justification Narrative Page 5 of 7
Reference key points from external documentation, list any addendums, attachments etc.
System Planning Assessments and Asset Management information.

2.2 Discuss how the requested capital cost amount will be spent in the current year (or
future years if a multi-year or ongoing initiative). (i.e. what are the expected functions,
processes or deliverables that will result from the capital spend?). Include any known or
estimated reductions to O&M as a result of this investment.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing
reductions to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
Ongoing improvements to the BES via substation rebuilds will result in system reliability,
fewer customer outages and smaller O&M costs.

2.3 Outline any business functions and processes that may be impacted (and how) by
the business case for it to be successfully implemented.
[For example, how will the outcome of this business case impact other parts of the business?]
System Operations will have improved functionality of the electric system.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation
strategies for each alternative.
Reduce the numbers of capital improvements or Doing Nothing causes equipment to age
and become obsolete and difficult to maintain.
2.5 Include a timeline of when this work will be started and completed. Describe when
the investments become used and useful to the customer. spend, and transfers to
plant by year.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful. (i.e. if
transfer to plant occurs monthly, quarterly or upon project completion).]
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 83 of 414
Substation – Station Rebuilds Program
Business Case Justification Narrative Page 6 of 7
Ongoing average of two rebuilds per year with multiple projects being in various stages of
design, construction and closeout.
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives
and mission statement of the organization.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]
Mission: We improve our customers’ lives through innovative energy solutions.
Vision: Better energy for life
These projects will help Avista stay ahead of the curve of load growth and equipment age
to prevent customer outages.
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please explain
how the investment prudency will be reviewed and re-evaluated throughout the
project
Customer outages are longer and larger when older equipment fails.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Electrical Engineering, Generation Production/Substation Support, Transmission
Operations and System Planning and Operations
2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]
Not Applicable.
3 MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a part
of your departmental prioritization process.]
The Engineering Roundtable manages the prioritization of projects within this business
case as supported by Asset Management studies and input from company subject matter
experts. The Engineering Roundtable is comprised of representatives from the following
departments: Asset Management, Compliance, System Planning, System Operations,
Telecommunications, Transmission Contracts, Protection Engineering, Substation
Engineering, Transmission Engineering, and Substation Support.
3.2 Provide and discuss the governance processes and people that will provide
oversight
Engineering Roundtable meets several times a year to analyze current and future projects.
3.3 How will decision-making, prioritization, and change requests be documented and
monitored
Project folders are saved to Engineering shared drives and Businesss Case Funds
Requests are available on the Finance sharepoint site

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 84 of 414
Substation – Station Rebuilds Program
Business Case Justification Narrative Page 7 of 7
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Substation - Station Rebuild Program
and agree with the approach it presents. Significant changes to this will be coordinated with
and approved by the undersigned or their designated representatives.

Signature: Date:
Print Name: Glenn Madden
Title: Manager, Substation Engineering
Role: Business Case Owner

Signature: Date:
Print Name: Josh DiLuciano
Title: Director, Electrical Engineering
Role: Business Case Sponsor

Signature: Date:
Print Name: Damon Fisher
Title: Principle Engineer
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Damon Fisher 1/5/2021
1/5/2020 1/5/2021
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 85 of 414
Wood Pole Management
Business Case Justification Narrative Page 1 of 12
EXECUTIVE SUMMARY

Asset Management and Distribution Engineering provide ongoing analysis of distribution assets
and their condition. This analysis is used to direct the Wood Pole Management (WPM) work that
includes inspecting and maintaining Avista’s poles, hardware, and equipment on a twenty-year
cycle. The operating guidelines are documented in the Structure Specific Distribution Feeder
Management Plan. Asset Maintenance collaborates with Electric Operations and contractors to
coordinate and complete the work. Asset Maintenance manages and tracks the work, budget,
scope, and schedule. Starting in 2020, WPM is integrating the Wildfire Urban Interface (WUI)
program scope into its work plan. The goal is to complete the WUI work by 2030. The major
drivers for the program are system reliability, improved cost performance, reduced customer
outages, and reduction in fire risk. These drivers are achieved by replacing defective poles,
associated hardware, and equipment at the end of its useful life or if the condition of the asset
requires replacement. The National Electrical Safety Code (NESC) is adopted as Washington Law
under WAC 296-45-045. Part 013C of this code describes the application, Part 121 defines the
inspection interval, and Part 214A details documentation and correction of the pole inspection
results.

WPM work encompasses Avista’s electric distribution overhead facilities in Washington, Idaho,
and Montana. In order to maintain a twenty-year cycle, approximately 11,400 poles need to be
inspected annually. The work plan is developed to complete 66% of the poles in the state of
Washington and 34% of the poles in Idaho each year. For the past three years, the spend has been
approximately $10.5M; however, the anticipated spending level needs to be increased to the $17M
range due to inclusion of the WUI program into the WPM work plan. This increase accelerates the
twenty-year WPM inspection cycle in order to meet the required ten-year WUI cycle. In addition,
with current costs, the historical $10.5M funding level does not support completing the identified
component replacements on a twenty-year cycle. In 2019, the average cost to mitigate defective
items identified during the inspection process was $1,093.49 per pole. As utilities become more
susceptible to wildfire litigation it is imperative that the system is inspected, and the defective
assets mitigated in a timely fashion. Keeping WPM on a $10.5M annual budget will push work
further into the future which increases safety and fire risks to the community and the reliability to
our customers.

Version Author Description Date Notes
1.0 Mark Gabert Initial draft of original business 7/1/2020
2.0 Mark Gabert Final draft of the original business 7/31/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 86 of 414
Wood Pole Management
Business Case Justification Narrative Page 2 of 12
GENERAL INFORMATION
1. BUSINESS PROBLEM
The current Wood Pole Management (WPM) program inspects and maintains the existing
distribution wood poles on a twenty-year cycle and the transmission poles on a fifteen-year cycle.
Avista has 7,702 overhead distribution circuit miles. According to the 2017 Wood Pole
Management Review and Recommendations the average age of a wood pole is twenty-eight years
with a standard deviation of twenty-one years. Nearly 20% of all poles are over fifty years old and
there are an estimated 230,000 distribution poles in the system. This means approximately 46,000
poles are currently over fifty years old. Our current inspection cycle allows us to reach
approximately 11,400 poles each year. Starting in 2021, 14,854 poles need to be inspected each
year because the Wildfire Urban Interface (WUI) program is being integrated into the inspections.
This increase in inspections will ensure the poles are inspected and maintained on a twenty-year
cycle. Along with inspecting the poles, WPM inspects distribution transformers, cutouts,
insulators, wildlife guards, lightning arresters, crossarms, pole guying, and pole grounds. The
average asset life of this equipment is fifty-five years and requires replacement along with the pole
work. The inspections document the asset condition and indicate what work is required to be
replaced, and assets that are damaged or near their failure point. The asset condition is observed
and documented during the pole inspection process as indicated in both the S-622 Specification
for the Inspection of Poles, and the Structure Specific Distribution Feeder Management Plan
(DFMP) located on the Asset Maintenance Sharepoint Site Designs and work plans are then
created to replace the aging infrastructure. The construction work to replace the assets is also part
of this program.
1.1 What is the current or potential problem that is being addressed?
This program addresses issues such as outages, safety risks, fire risks, and unplanned
maintenance. This is accomplished by inspecting, documenting, and maintaining our
overhead facilities in a useful condition on a twenty-year cycle. This keeps our poles
safe for employees and the general public while maintaining a high level of customer
satisfaction. As of 2020, WPM is tracking on a twenty-year cycle, however, as the Grid
Modernization Program (GMP) budget is reduced, there is an impact on the
recommended twenty-year cycle. GMP contributes to WPM’s ability to maintain the
Requested Spend Amount $88,871,382
Requested Spend Time Period 5 years
Requesting Organization/Department Asset Maintenance/WPM
Business Case Owner | Sponsor Mark S. Gabert | Alicia Gibbs | David Howell
Sponsor Organization/Department M51/WPM
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 87 of 414
Wood Pole Management
Business Case Justification Narrative Page 3 of 12
required poles needed to remain on the twenty-year cycle. The WUI Program is another
impact to maintaining the twenty-year cycle. With the addition of the WUI program,
WPM will need to re-inspect some poles in the system sooner than the twenty-year cycle
so the required WUI work can be completed. If unfunded to expedite the plan, poles
will be pushed past the twenty-year cycle in order to meet the demand from the WUI
program and with the reduction of GMP budget.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer Service
Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset Condition, or Failed
Plant & Operations) and the benefits to the customer
From an Asset Condition perspective, the major drivers for the program include safety,
system reliability, improved cost performance, reduced customer outages, and decreased
fire risk. These drivers are addressed by replacing defective poles, associated hardware,
and equipment at its end of life or as required by asset condition. This program also has
a mandatory and compliance component to it because the National Electrical Safety
Code (NESC) is adopted as Washington Law under WAC 296-45-045. Part 013C of this
code describes the application, Part 121 defines the inspection interval, and Part 214A
details documentation and correction of the pole inspection results.
1.3 Identify why this work is needed now and what risks there are if not approved or
is deferred
The work is required now to keep pace with the aging assets and expected failure rate.
Figure 1 below shows the increased rate at which the poles are reaching the seventy-five
year-end of life. If this work is not maintained, this aging infrastructure will cause an
increasing number of failures leading to increased outages and higher construction costs
as it is much more expensive to respond to an asset failure than to have it replaced in a
planned program.

In addition to the risks of fires, outages, and failures with the aging equipment, the
additional risks associated with this program pertain to the following:

Environmental: Risks include potential large volume transformer oil spill,
difficult hazardous waste cleanup, impact to waterways, and repeated or
moderate air emission exceedance. According to the 2017 Wood Pole
Management Review and Recommendations if the program is unfunded the
potential occurrence is greater than four spills per year. If funded, the potential
occurrence is less than one per fifty years.

Public Safety and Health: Risks include a potential for serious injury for crews
or the public, significant damage to equipment, property or businesses, public
health infrastructure impact up to forty-eight hours. If the program is unfunded,
the potential occurrence is less than one per ten years. If funded the potential
occurrence is less than one per fifty years.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 88 of 414
Wood Pole Management
Business Case Justification Narrative Page 4 of 12
Figure 1- Pole Age Profile

The Outage Management Tool (OMT) is used by Asset Management to track asset conditions and
show trends of failures of specific equipment that should be targeted for replacement. This
information is also used to track key program performance as shown in Table 1 below. The
number of outage type events has been reduced by over 36% from 2009 through 2017. This
reduction in outage events results in significant customer benefit. This reduction also demonstrates
increased reliability and safety along with a reduction in outages. The original goal for this KPI
was to stay below the number of events averaged over 2005-2009 for WPM Related OMT Events.
The goal will be re-evaluated by Asset Management in the future.

Table 1: Event Reduction Results

WPM Goal Related
Number of OMT
Events
Actual WPM
Related Number of
OMT Events
Projected Miles
Follow-Up Work
Actual Miles Follow-
Up Work
2009 1460 1320 500 372
2010 1460 1004 450 435
2011 1460 1004 459 333
2012 1460 1013 416 435
2013 1460 816 445 329
2014 1460 905 412 385
2015 1460 760 390 364
2016 1460 717 389 423
2017 1460 888 389 492

0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
1910 1920 1930 1940 1950 1960 1970 1980 1990 2000 2010 2020
Pe
r
c
e
n
t
a
g
e

o
f

P
o
l
e

P
o
p
u
l
a
t
i
o
n
Year Installed
Wood Pole Age Profile
Over 75 years old
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 89 of 414
Wood Pole Management
Business Case Justification Narrative Page 5 of 12
Figure 2: OMT Events
The type of OMT events are broken down into more detail in Figure 2. Note there are
significant improvements to some events such as annual squirrel events being reduced from
nearly 750 to around 240 events. This improvement has been realized by adding wildlife
guards to the top of transformer bushings in order to prevent squirrels from touching
exposed power connections which can result in outages. Both the transformer and
cutout\fuse events have been reduced by over 50% through the replacement of aged
equipment. Figure 2 also reveals a concerning upward trend of pole-rotten events that
indicate the impact of the aging poles. Note that the calculated cost to customers for a pole
failure is $24,400 based on an average duration of 4.8 hours for 80 customers1. Other key
OMT events that have been significantly reduced from 2009 to 2016 include Transformer,
Cutout/Fuse, and Squirrel. The combined cost impact to customers in 2015 alone for those
events was $2,265,600. See Figure 2.

1 Source: 2017 Wood Pole Management Review and Recommendation)
0
50
100
150
200
250
300
350
400
Nu
m
b
e
r

o
f

E
v
e
n
t
s
Wood Pole Management Events by OMT Sub-Reason and Year
2011 2012 2013 2014 2015 2016 2017
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 90 of 414
Wood Pole Management
Business Case Justification Narrative Page 6 of 12
1.4 Identify any measures that can be used to determine whether the investment would
successfully deliver on the objectives and address the need listed above.
Ultimately the impact of this Program can be associated with our Electric Systems
Reliability metrics. The System Average Interruption Frequency Index (SAIFI)
represents the average number of sustained interruptions per customer for the year
across Avista’s entire system. Avista reported a SAIFI score of 1.05 for the year 2015.
The Asset Management group created Table 2 below to show the impact of this
Program to our overall SAIFI score. The predicted contribution is about 0.211, which
has a significant impact on the customer, whereas without WPM the contribution to
SAIFI would be 0.57. This means the customer would experience 0.36 more outages
per year without WPM. Without WPM, the contribution to SAIDI would be 1.27
(hours).

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
The 2017 Wood Pole Management Program and Review which is located in the
c01m570 drive.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.

Based on the analysis in 2017, the current twenty-year WPM cycle delivers the best life cycle
value for the funding level. Asset Management and Distribution Engineering monitor system
Table 2: SAIFI Metrics
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 91 of 414
Wood Pole Management
Business Case Justification Narrative Page 7 of 12
reliability to determine if adjustments are needed in the future. For perspective the industry
average for inspecting and maintaining distribution assets is ten years.
WPM is an ongoing cyclical program that proactively replaces aging assets. By replacing
assets before they fail, outage risks are reduced, and replacement costs are reduced through
planned work. Investing in the infrastructure increases life-cycle performance and is cost
effective using unit-based pricing. Figure 3 below shows the significant improvement in
“events per mile of feeder” resulting from this program. The peak of events per mile shown
in the graph is from approximately six years ago when there were nearly 1.5 events per mile.
The results after the program show performance as low as .3 events per mile of feeder, a
significant improvement.
If funding were to be reduced, expected outages would increase. The team would need to
prioritize which components would be replaced and which would be left. This would increase
the likelihood that crews would need to revisit the same pole later if a remaining component
were to fail. While the five-year cycle does provide a better Customer Internal Rate of Return
of 8.85%, the five-year cycle O&M costs exceeded our historical spending constraint. The
internal rate of return for a twenty-year cycle is 8.00%.

Option Capital Cost Start Complete
0.000
0.050
0.100
0.150
0.200
0.250
0.300
-10 -9 -8 -7 -6 -5 -4 -3 -2 -1 0 1 2 3 4 5 6 7 8 9 10
WP
M

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S
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o
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F
e
e
d
e
r

(
#
/
M
i
l
e
)
Years Before and After WPM Work Completed
Average WPM Related Sustained Outage Events per
Mile Before and After WPM Work Completed
Average WPM Related Event per Mile
Ty
p
i
c
a
l

P
e
r
i
o
d

o
f

W
P
M

W
o
r
k

o
n

a

F
e
e
d
e
r
Year WPM Work was
Completed
Number of Years After WPM Work Number of Years Before WPM
Work Completed
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 92 of 414
Wood Pole Management
Business Case Justification Narrative Page 8 of 12
[Recommended Solution]:
Distribution Wood Pole Management
Program inspects all feeders on a
twenty year cycle and replaces wood
poles, crossarms, missing lightning
arresters, missing/stolen grounds, bad
cutouts, bad insulators, leaking
transformers, replace guy wires not
meeting current code requirements
when the pole is replaced. This includes
increasing the pole inspections and
replacement work for the next ten years
to meet the requirements of the WUI
program.
$16,739,331 01 2021 12 2030
[Alternative #1] Distribution Wood
Pole Management Program inspects all
feeders on a twenty year cycle and
repairs and replaces wood poles,
crossarms, missing lightning arresters,
missing/stolen grounds, bad cutouts,
bad insulators, leaking transformers,
replace guy wires not meeting current
code requirements when the pole is
replaced. This alternative will push the
WPM cycle out to twenty-three years
until 2030 as WUI will compete for the
same inspection and replacement costs
for the next ten years.
$12,847,800 01 2021 Annually/indefinite
[Alternative #2] Do nothing-increase
OMT events by 1,700 per year and
increased fire risk.
$0 MMYYYY MM YYYY
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
In Asset Management’s 2017 Wood Pole Management Review and Recommendations
several alternatives were examined that included a five-year, ten-year, twenty year, and
twenty-five year inspection cycle time as well as the impact of GMP work on the related
WPM work. While the five-year cycle did provide a better Customer Internal Rate of
Return of 8.85%, the five-year cycle O&M costs exceeded our historical spending
constraint.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 93 of 414
Wood Pole Management
Business Case Justification Narrative Page 9 of 12

2.2 Discuss how the requested capital cost amount will be spent in the current year (or
future years if a multi-year or ongoing initiative). (i.e. what are the expected
functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
The WPM program is an ongoing process of inspecting, designing, and completing
replacement work of assets identified for replacement during the inspection process. The
poles on the feeders in the work plan are at various phases of the process throughout the
year. The goal is to complete any identified work on a feeder within eighteen months of
inspection, and we currently average about one year from start to finish. This work is
incorporated into workplans and allows the company to efficiently utilize resources.
2.3 Outline any business functions and processes that may be impacted (and how) by
the business case for it to be successfully implemented.
Additional WUI design demand, plus increasing the work to meet the twenty-year cycle
goal increases the need for additional WPM design, tech, and construction resources.
Material availability can also impact the ability to execute on the plan.
Additional departments the WPM program interfaces with will also see some increase
in workload which includes: Distribution Engineering, Supply Chain, Environmental,
Real Estate, and out-of-cycle Vegetation Management response. There is also a strong
need for Asset Management to continue reviewing and analyzing the data that supports
this program.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 94 of 414
Wood Pole Management
Business Case Justification Narrative Page 10 of 12
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation
strategies for each alternative.
In Asset Management’s 2017 Wood Pole Management Review and Recommendations:
“Asset Management examined several alternatives that included a 5-year, 10-year,
20 year, and 25-year inspection cycle time as well as the impact of Grid
Modernization work on the related Wood Pole Management work. While the 5-year
cycle did provide a better Customer Internal Rate of Return of 8.85%, the 5-year
cycle Operations and Maintenance costs exceeded our historical spending
constraint. The 20-year inspection cycle provided the best Customer Internal Rate
of return and our current practice of replacing transformers that functionally have
failed while meeting the Operating and Maintenance budget constraints.
Any delays in implementing the Wood Pole Management program strategy as
envisioned will delay the immediate benefits and take 20 years based on the current
inspection cycle to recover the long-range value of the strategy.
We recommend continuing the Wood Pole Management program on its 20-year
inspection cycle and follow-up work strategy. Any delays in the work will impact
reliability and system performance. “
Choosing the recommended solution keeps WPM and WUI on track to be completed on
time. Choosing Alternative #1 pushes the cycle out further to twenty-three years which
increases the risk of more OMT events, increased O&M costs, increased possibility of
a fire, and reduces the overall effectiveness of how we manage our aging assets. We also
add risk by underfunding our commitment of providing safe, reliable, electric service to
our customers. This work has been approved and validated in previous commission
responses.
2.5 Include a timeline of when this work will be started and completed. Describe when
the investments become used and useful to the customer. spend, and transfers to
plant by year.
WPM is an ongoing program. The work is a continuous process of inspecting Avista’s
poles on a feeder basis. Each feeder represents a project within the program. There are
several phases to complete each feeder including inspecting, designing, and capital
follow-up. As soon as any capital follow-up work is completed, the asset can become
used and useful. The transfers to plant occur on a monthly basis. In addition, our Finance
Department preps the AVA_Plan system periodically for a spend and transfer to plant
forecast update for the remainder of the year.
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives
and mission statement of the organization.
This business case improves safety for our customers, employees, and the general public
by responsibly mitigating safety hazards. This will also improve reliability, reduce fire
risk, and decrease the number of unplanned O&M outage responses. Our company’s
vision is supported by building reliable infrastructure and then maintaining the assets in
a safe reliable condition that improves our customers lives. The public utility
commissions and our customers hold us to the highest standard of care. When we act
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 95 of 414
Wood Pole Management
Business Case Justification Narrative Page 11 of 12
prudently and follow through with our commitments, we demonstrate our
trustworthiness.
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please explain
how the investment prudency will be reviewed and re-evaluated throughout the
project
The requested amount is a prudent investment to maintain Avista’s overhead electric
system on a twenty-year cycle, which is also in alignment with the NESC requirement
to inspect and maintain our facilities in a timely manner. This work reduces the
company’s risk.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Electric customers, Distribution Engineering, Environmental, Wildland Urban
Interface, area offices, line crews, Asset Management, and Grid Modernization.
Please note that with the sunsetting of the TCOP program the internal crews
incorporate WPM as part of their workplan.
2.8.2 Identify any related Business Cases
Grid Modernization Program, WSDOT Control Zone Mitigation, and WUI-
Wildfire Urban Interface Program.
3.1 Steering Committee or Advisory Group Information
Asset Management and Distribution Engineering provide ongoing analysis of distribution
asset condition. The analysis is used to direct the WPM work that includes inspecting and
maintaining Avista’s poles, hardware, and equipment on a twenty-year cycle. The twenty-
year cycle is documented in the 2017 Wood Pole Management Review and
Recommendations. The operating guidelines are documented in the Structure Specific
DMFP.
3.2 Provide and discuss the governance processes and people that will provide
oversight
The governance process is a collaborative process that includes leadership from: Asset
Management Asset Maintenance, Distribution Engineering, the Director of Operations, and
the WPM Program Manager and WPM inspectors . The operating guidelines are documented
in the Structure Specific Distribution Feeder Management Plan. The yearly goals are
documented and updated on the annual one pager.
3.3 How will decision-making, prioritization, and change requests be documented and
monitored
WPM is a long-standing program that is well established. There are few change orders, but
they are documented by the inspectors during the audit process. All significant change
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 96 of 414
Wood Pole Management
Business Case Justification Narrative Page 12 of 12
requests are reviewed by the Program Manager for approval. In cases where scope is re-
evaluated, changes are agreed to prior to construction.

The undersigned acknowledge they have reviewed the Wood Pole Management Business
Case and agree with the approach it presents. Significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.

Signature: Date: 7/30/20
Print Name: Mark S Gabert
Title: WPM/WSDOT Program Manager
Role: Business Case Owner

Signature: Date:
Print Name: David Howell
Title: Director of Operations
Role: Business Case Sponsor

Signature: Date:
Print Name: Alicia Gibbs
Title: Asset Maintenance Manager
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
8/2/20
8/2/2020Alicia Gibbs
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 97 of 414
Wildfire Resiliency Plan (July 2020)
Business Case Justification Narrative Page 1 of 10
EXECUTIVE SUMMARY

The threat of wildfires poses a significant risk to utilities across the western United States. In May
of 2020, Avista published its “2020 Wildfire Resiliency Plan” which details twenty-eight actions
to mitigate the risk of wildfire. The Plan includes upgrades to infrastructure aimed at reducing
spark-ignition events and protecting critical infrastructure from the threat of wildfires. The Plan
details a 10-year time horizon. The $268,965,000 Plan includes investments in the four
categories:

Enhanced Vegetation Management
Widen Transmission R/Ws ($5,000,000)
Vegetation management incorporated into CPC designs ($100,000)

Situational Awareness
Fire-Weather Dashboard & TROVE risk analysis ($425,000)
Midline Reclosers Communications ($540,000)
100% Substation SCADA ($17,000,000)

Operations and Emergency Response
Transmission Design Review of Major Events ($100,000)
Fire Ignition Tracking System ($200,000)

Grid Hardening & Dry Land Mode
Transmission Fire Inspection ($3,000,000)
Transmission Grid Hardening ($44,000,000)
Midline Reclosers ($5,400,000)
Distribution Grid Hardening (193,200,000)

Wildfire Plan (CapX 2020-2029) $268,965,000

The 10-year accumulated inherent risk of wildfire is estimated between $8.05 and $18.2 billion
dollars. The mitigated risk (with controls) is estimated between 0.5 and $2.3 billion dollars. Again,
accumulated over a 10-year period. The risk reduction is estimated at between 8X and 16X with
a cost – benefit ratio between 22.9 and 48.6 including $60 million dollars of O&M expense.

VERSION HISTORY
Version Author Description Date Notes
0 David James Initial Submission to Capital
Planning
April 1,
2020 Initial submission
1 David James Refresh using 2020 BC narrative
template
July 29,
2020
No revision to capital
requirements

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 98 of 414
Wildfire Resiliency Plan (July 2020)
Business Case Justification Narrative Page 2 of 10
GENERAL INFORMATION

Requested Spend Amount $268,965,000 (2020-2029) CAPX
$59,586,000 (2020-2029 OPX) for information
Requesting Organization/Department Electric Operations
Business Case Owner David Howell
Business Case Sponsor Heather Rosentrater
Sponsor Organization/Department Electric Operations
Category Program
Driver Customer Service Quality & Reliability
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 99 of 414
Wildfire Resiliency Plan (July 2020)
Business Case Justification Narrative Page 3 of 10
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The risk of wildfires is increasing throughout the western United States. Data from the
U.S. Forest service indicates a 300% increase in the number of wildfires since 1970
Data specific to fires in Washington and Idaho fires suggest that fire size has increased
400-500% over the last several decades. Though the number of powerline involved
wildfires remains relatively low (5-7% WA DNR statistics, 1990-2015), wildfire is
differentiated from natural disasters in that ‘cause and origin’ investigations often lead
to claims for fire suppression costs, property damage, timber loss, and personal injury.
In the fall of 2018, a small team of Avista employees was assembled to assess the
risks, develop defensive strategies, and implement a Wildfire Resiliency Plan. This
business case reflects the 10-year strategy to build defense strategies against wildfire.
1.2 Discuss the major drivers of the business case and the benefits to the customer?
Wildfire does not align well with the existing business case drivers. Unlike most asset
replacement programs, Wildfire Resiliency is a risk-based, not a condition-based
program. Therefore, it is best aligned with Customer Service Quality & Reliability and
is expected to reduce risk exposure by at least $7.5 billion dollars over a 10-year period.
1.3 Identify why this work is needed now and what risks there are if not approved or
is deferred – Avista has published a “2020 Wildfire Resiliency Plan” and have
committed to implementation at the highest levels of the Company including the Board
of Directors. It is a Tier 1 Enterprise Level risk.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above – As part of Wildfire Resiliency, performance metrics will be
tracked including, fire ignition events, to measure the efficacy of the program.
Transmission and Distribution Operations tracks system outages including cause-code,
duration, and impacted customers. The primary goal of the program is to limit the
number of spark-ignition events and the reduction in outages will enhance customer
experience.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
Several supporting documents are available for review:
2020 Avista Wildfire Resiliency Plan (June 2020)
Wildfire Resiliency Cost Plan (January 2020)
Wildfire Risk Assessment (September 2019)
Wildfire Plan Charter (May 2019)
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
Wildfire Resiliency is a comprehensive, risk-based program and includes targeted
equipment replacement. Condition based metrics are not considered.

In May and June of 2019, a series of risk workshops were held to identify potential defensive
strategies to reduce the risk of wildfire. These workshops were facilitated by the Business
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 100 of 414
Wildfire Resiliency Plan (July 2020)
Business Case Justification Narrative Page 4 of 10
Process Improvement team with support from Senior Risk Manager, Bob Brandkamp, and
Asset Management Analyst, Jeff Smith. Over the course of 6-workshops, 160 mitigation
strategies were identified. 60 of those were analyzed in detail and ultimately, 28 strategies
were adopted into the plan including transmission and distribution grid hardening, a
comprehensive review of dry land mode operating strategies, and systems to actively monitor
fire-risk. In addition to internal processes, Avista participated in several utility forums
sponsored by the Western Energy Institute including the Wildfire Planning & Mitigation
workshop. In general, the approach to fire mitigation is consistent throughout the utility
sector.

Option Capital Cost Start Complete
Wildfire Resiliency Plan $268,965,000 07 2020 12 2029
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.

Wildfire Resiliency is a risk-based plan. Inherent (existing) and mitigated (future) risks
were assessed in three categories:
 Financial (the cost of replacing T&D infrastructure associated with wildfire events
and response to third party and other claims for fire suppression and damages)
 Customer (the cost impact to customers including outage duration and societal
disruption)
 Safety (costs associated with worker and public injuries)

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 101 of 414
Wildfire Resiliency Plan (July 2020)
Business Case Justification Narrative Page 5 of 10
The following is a list of the 28 recommended actions indicating a range of inherent and
mitigated risk costs. Note that not all the actions reflect capital investments (e.g.
vegetation management). Monetized risk values represent a 10-year operating time
horizon.

Inherent Risk ($M) Managed Risk ($M) Cost: Benefit Risk Red
System & Transmission Low High Low High Low High %
EOP & Fire ICS Representation 9.6 17.7 9.6 17.6 0.0 2.0 0%
Fire-Weather Dashboard 4.8 8.8 4.3 4.8 0.5 3.7 33%
Engineering Review Major
Events 1 6.9 0.9 2.4 1.0 45.0 58%
Wildfire Compliance Tracking 9.6 18 2.2 2.7 49.3 102.0 82%
Digital Data Collection 9.6 17.7 0.9 2.4 1.3 2.2 88%
Wood Pole FR Mesh Protection 9.6 28 4.3 4.8 2.2 9.5 76%
Fuel Reduction Partner 15 29 3 29 8.0 0.0 27%
Emergency Responder Training 1.8 2.3 0.3 0.9 1.2 1.1 71%
Conforming Rights-of-Way 4.8 8.8 0.2 1.4 0.9 1.5 88%
Transmission Inspection Pym 4 59 1.1 2.6 0.6 11.3 94%
Expedited Fire Response - - - - n/a
Transmission Grid Hardening n/a
Transmission Total $70 $196 $27 $69 0.6 1.9 64%

Inherent Risk ($M) Managed Risk ($M) Cost: Benefit Risk Red
Electric Distribution Low High Low High Low High %
Fuse Coordination Study 41 107 1.6 8.2 197.0 494.0 93%
Recloser Event Reporting 21 82 1.3 8.4 49.3 184.0 91%
Fire Ignition Tracking System 132 547 46 213 286.7 1113.3 62%
Veg Mngt in CPC designs 20 278 10 21 100.0 2570.0 90%
Fire Suppression 'wetting' agent 53 582 11 66 840.0 10320.0 88%
Dry Land Mode 'effectiveness' study 21 57 0.6 4.2 204.0 528.0 94%
WUI layer in GIS 0 0.11 0 0.11 0.0 0.0 0%
Dry Land Mode 'trigger' - - - - n/a
Arcos Wildfire Notification - - - - n/a
Distribution Annual Risk Tree 2,816 5,722 264 1,226 100.1 176.3 83%
Public Safety Initiative 'Right Tree-Right Place' 563 1,145 2.25 28.2 58.4 116.3 98%
Midline Recloser
Communication 14.6 29 0.25 0.28 17.7 35.4 99%
Additional Midline Reclosers 22.6 39 5.63 13.2 2.9 4.4 69%
Digital Data Collection 2,816 5,722 132 564 346.3 665.5 92%
100% Substation Scada 132 547 0 1.6 7.7 31.9 100%
WA Grid Hardening in WUI
Tier 2-3 823.6 1980.75 6.83 41 6.8 16.2 98%
ID Grid Hardening in WUI Tier 2-3 502.4 1208.25 4.17 25 6.8 16.2 98%
Distribution Total $7,978 $18,046 $486 $2,220 28.7 60.6 90%

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 102 of 414
Wildfire Resiliency Plan (July 2020)
Business Case Justification Narrative Page 6 of 10
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.

The illustration indicates the estimated capital and operating investments. Though we
do expect outage rates associated with vegetation and equipment failures to trend
downward, O&M ‘offsets’ are not a significant factor. The primary focus of this plan is
risk reduction and to protect the financial viability of the Company.

Capital cost breakdown by year and project (values in $000’s).

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
Capital $5,265 $16,985 $27,055 $31,380 $31,380 $31,380 $31,380 $31,380 $31,380 $31,380
Operating $2,416 $5,371 $6,917 $7,435 $7,354 $6,772 $6,540 $6,059 $5,627 $5,096
$0
$5,000
$10,000
$15,000
$20,000
$25,000
$30,000
$35,000
$
0
0
0
'
s
Avista Wildfire Resiliency
Plan Cost Forecast
Capital Operating
Capital
System & Transmission 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 10-yr
ST-1 EOP & Fire ICS Representation 0ST-2 Fire-Weather Dashboard 200 150 75 425
ST-3 Engineering Review Major Events 10 10 10 10 10 10 10 10 10 10 100
ST-4 Wildfire Compliance Tracking 0ST-5 Digital Data Collection 0
ST-6 Wood Pole FR Mesh Protection 0
ST-7 Fuel Reduction Partner 0
ST-8 Emergency Responder Training 0
ST-9 Conforming Rights-of-Way 500 500 500 500 500 500 500 500 500 500 5,000ST-10 Transmission Inspection Pgm 300 300 300 300 300 300 300 300 300 300 3,000
ST-11 Expedited Fire Response 0
ST-12 Transmission Grid Hardening 1,000 3,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 44,000
Transmission Total $2,010 $3,960 $5,885 $5,810 $5,810 $5,810 $5,810 $5,810 $5,810 $5,810 $52,525
CapitalElectric Distribution 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 10-yr
D-1 Fuse Coordination Study 0D-2 Recloser Event Reporting 0
D-3 Fire Ignition Tracking System 25 75 100 200
D-4 Veg Mngt in CPC designs 10 10 10 10 10 10 10 10 10 10 100
D-5 Fire Suppression 'wetting' agent 0
D-6 Dry Land Mode 'effectiveness' study 0
D-7 WUI layer in GIS 0
D-8 Dry Land Mode 'trigger'0
D-9 Arcos Wildfire Notification 0D-10 Distribution Annual Risk Tree 0
D-11 Public Safety Initiative 'Right Tree-Right Place'0
D-12 Midline Recloser Communication 20 40 60 60 60 60 60 60 60 60 540
D-13 Additional Midline Reclosers 200 400 600 600 600 600 600 600 600 600 5,400
D-14 Digital Data Collection 0D-15 100% Substation Scada 0 1,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 17,000
D-16 WA Grid Hardening in WUI Tier 2-3 2,000 6,500 10,000 14,500 14,500 14,500 14,500 14,500 14,500 14,500 120,000
D-17 ID Grid Hardening in WUI Tier 2-3 1,000 5,000 8,400 8,400 8,400 8,400 8,400 8,400 8,400 8,400 73,200
Distribution Total $3,255 $13,025 $21,170 $25,570 $25,570 $25,570 $25,570 $25,570 $25,570 $25,570 $216,440
D-10 - $500k/per year added to the above for budget
Plan Total $5,265 $16,985 $27,055 $31,380 $31,380 $31,380 $31,380 $31,380 $31,380 $31,380 $268,965
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 103 of 414
Wildfire Resiliency Plan (July 2020)
Business Case Justification Narrative Page 7 of 10

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.

Implementation has and will impact many areas of the Company including electric
operations, engineering, supply chain, IT, asset management, finance and accounting.
However, great care has been taken to leverage existing workflow processes and
technologies to minimize disruption to the organization. This is an enterprise level
program.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.

A complete list of alternatives is included in the
September 2019 publication entitled, “Wildfire Risk
Analysis Summary – actions under consideration”. This
document focuses on the risks and costs of viable
alternatives and laid the groundwork for actions adopted
in the Resiliency Plan.
2.5 Include a timeline of when this work will be
started and completed. Describe when the
investments become used and useful to the
customer.

The scope of this plan is considerable. Both transmission
and distribution grid hardening projects will be ramped
from 2020 through 2023 and then levelized through 2029.
Other efforts including technology projects such as the fire-weather dashboard and the
TROVE risk analysis will be conducted on the front end of the ten-year horizon. The
following table indicates the capital spend levels, by year. This is a surrogate for
activity.

Values in $000’s.

Capital
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 10-yr
$5,265 $16,985 $27,055 $31,380 $31,380 $31,380 $31,380 $31,380 $31,380 $31,380 $268,965
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 104 of 414
Wildfire Resiliency Plan (July 2020)
Business Case Justification Narrative Page 8 of 10
2.6 Discuss how the proposed investment aligns
with strategic vision, goals, objectives and
mission statement of the organization.

The stated goals of the resiliency plan are:
 Protect lives and property
 Ensure emergency preparedness and align
operating practices with fire threat conditions
 Protect Avista’s energy delivery infrastructure

The effort to develop a comprehensive wildfire mitigation strategy has been fully
embraced by Avista’s Board of Directors and executive management. The Board has
requested quarterly updates since early 2020 and will receive another briefing on
August 5, 2020 (D. Howell and D. James).
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project

Prudency is a fundamental tenant of cost recovery. Avista has engaged directly with
Idaho and Washington Utility Commissioners and their staffs. Avista’s rates
department recently petitioned the IPUC for deferral treatment of all wildfire related
costs (capital and O&M). Discussions continue with Washington Commissioners.
Events surrounding the November 2018 ‘Camp Fire’ lead to the bankruptcy of PG&E
and served as the catalyst for many utilities to assess their systems and defenses
associated with wildfire.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case

Avista electric customers located in Wildland Urban Interface zones 2 & 3 will be directly
engaged via the process. Grid hardening and enhanced vegetation management
strategies will be focused in those areas. In addition, Avista is coordinating with local and
regional stakeholders including fire protection agencies, electric utilities, the Washington
department of natural resources (DNR), the Idaho department of lands (IDL), and groups
with an interest in or impacted by Avista’s plan.

2.8.2 Identify any related Business Cases
N/A

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 105 of 414
Wildfire Resiliency Plan (July 2020)
Business Case Justification Narrative Page 9 of 10
3.1 Steering Committee or Advisory Group Information
Since February of 2019, a Wildfire Steering Committee has actively engaged in the
formation and adoption of the Plan. That committee remains active and will guide
efforts throughout the life of the program. Members include:
Name Title
David Howell Director, Electric Operations (Business Case Owner)
Bruce Howard Sr. Director, Environmental Affairs and Real Estate
Greg Hesler Vice President, General Counsel & Chief Compliance Officer
Alicia Gibbs Manager, Asset Maintenance
Elizabeth Andrews Sr. Manager, Revenue Requirements
Bob Brandkamp Sr. Manager, Risk
Annie Gannon Manager, Communications
Casey Fielder Manager, Corporate Communications

3.2 Provide and discuss the governance processes and people that will
provide oversight

The Wildfire Resiliency Plan will adapt and evolve to align with risk conditions and
available technologies to mitigate those risks. Governance and oversight will be a
consistent element throughout the life of the Plan including direct involvement by
senior management and oversight via the Board of Directors.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Program management is a prescribed function of the Wildfire Plan Manager position.
Monthly status reports will include status of costs, production, and forecasts including
resource requirements. This plan will adapt over time as we gain experience with new
elements including risk-based vegetation management, digital data collection, grid
hardening, and emergency operations tactics specific to fire response.

The undersigned acknowledge they have reviewed the Wildfire Resiliency Plan
business case and agree with the approach it presents. Significant changes to this
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 106 of 414
Wildfire Resiliency Plan (July 2020)
Business Case Justification Narrative Page 10 of 10
will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Print Name: David Howell
Title: Director, Electric Operations
Role: Business Case Owner

Signature: Date:
Print Name: Heather Rosentrater
Title: Sr Vice President, Energy Delivery
& Shared Services

Role: Business Case Sponsor

Signature: Date:
Print Name: David Howell (on behalf of WFRES
Steering Group)

Title:
Role: Steering/Advisory Committee Review

8/2/20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 107 of 414
Distribution System Enhancements
Business Case Justification Narrative Page 1 of 14
EXECUTIVE SUMMARY

Avista’s electric distribution system is the largest part of the company’s infrastructure. It
consists of poles, wires, underground cable, transformers and a variety of other
equipment. In addition, Avista’s electric distribution system has the largest footprint of any
other infrastructure within the company’s service territory. This creates a unique challenge
for the company. The distribution system is the largest contributor to a customer’s
reliability and the overall safety of the public, mostly from the sheer volume of exposure
it establishes. This business case is one of several such as, Minor Rebuilds, Wood Pole
Management, Grid Modernization, etc., that creates a direct customer benefit by
completing projects that improve the electric distribution system’s safety, performance
and reliability. The jobs for this business case are identified by our area engineers for
their regional areas within Washington, Idaho, and Montana and they are prioritized
against each other with input from the distribution planner.

Most of the funds provided by this business case are used to complete projects that solve
performance and capacity issues driven by system wide electric load growth. Other
projects address power quality mitigation, reliability improvements, operational flexibility,
system protection improvements, and safety enhancements. As such, the risk in not
funding this business case is the inevitable decline in the overall health and operation of
Avista’s electric distribution system, e.g. overloading conductor to the point of failure. The
ongoing nature of issues that arise within the electric distribution system coupled with the
large amount of work drives the need for this business case to be funded on a yearly
basis.

VERSION HISTORY
Version Author Description Date Notes
1.1 David James Initial draft of original business case. 04/07/2017
1.2 Cesar Godinez Updated to include voltage/transformer
mitigation work. 07/03/2019 transformer mitigation work
2.0 Cesar Godinez Updated narrative and business case
template. 07/01/2020
name change to “Distribution
System Enhancements” from
“Segment Reconductor and

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 108 of 414
Distribution System Enhancements
Business Case Justification Narrative Page 2 of 14
GENERAL INFORMATION

1. BUSINESS PROBLEM

Avista’s electric distribution system consists of three hundred and fifty seven (357)
discrete primary electric circuits encompassing over 19,000 miles of overhead
conductors and underground cables. The distribution grid is managed by division
or ‘area engineers’ and centralized distribution planning.
Load Demands on the grid are dynamic with load patterns changing as a result
of many factors including weather, temperature, economic conditions,
conservation efforts, and seasonal variations. Avista operates a radial distribution
system using a trunk and lateral configuration (industry standard). Though many
circuits are monitored at the source substation (SCADA), downstream trunk and
lateral branch circuits loading are analyzed via computer simulation. At Avista,
distribution analysis is performed with the Synergi load flow program. AMI data is
also used to analyze service voltages and transformer loading. AMI data has
shown system issues in the form of service voltage problems and transformer
overloading. In the near future AMI load data will be exported to Synergi and used
in the computer simulation.
Additionally, power quality investigation and subsequent mitigation projects are
initiated by customer inquiries or analysis work. Work is also driven by reliability
and safety concerns that are identified by our engineers and/or operation
personnel. Operational flexibility can also drive the need to upgrade electric
circuits, install switching equipment, and other infrastructure as needed.
In a manner similar to substation rebuilds, expansions, and additions that are
planned for and scheduled years in advance, the distribution system also requires
rebuilds, expansions, and additions. The Distribution System Enhancements
Business Case allows for a methodical and planned out approach to needed
feeder enhancements. Secured funding for future years allows for planning large
projects in a multi-year approach, with completion of a portion of the overall project
happening over a series of years. In absence of this business case, critical issues
Requested Spend Amount
Requested Spend Time Period 5 years (on-going)
Requesting Organization/Department
Business Case Owner | Sponsor
Sponsor Organization/Department
Phase
Category
Driver
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 109 of 414
Distribution System Enhancements
Business Case Justification Narrative Page 3 of 14
would be resolved in a reactionary and haphazard fashion, funded through the
Minor Blanket, and completed outside the confines of a “big picture” plan and
approach to feeder management.
Avista’s electric distribution system analysis and mitigation strategies are informed
by several internal documents and data repositories. These are listed below for
reference:

1. Distribution Planning Standard “500 Amp FDR” – internal document that defines the
performance criteria and limits for both urban FDR tie systems and rural pure radial
circuits. This document is maintained by Distribution System Planning (Damon Fisher).
2. FDR Status Report – distribution engineering publishes an annual report indicating peak
circuit demand by season, reliability outage statistics, circuit health check, and other
logistic information.
3. Distribution Standards – distribution engineering maintains construction standards for
both overhead and underground primary circuits. It also maintains standards for all
electrical material and apparatus.
4. PI Database – operating data retrieved by either the SCADA or DMS system is stored
in the PI historian. This allows direct access by engineers and planners to help inform
both operating and design strategies. (Distribution Operations)
5. Distribution FDR Management Plan – a design guide to assist the CPC/Engineer when
making decisions related to reinforcements or reconstruction of distribution assets
(Asset Management).
6. Feeder Automation Strategy – a design guide to assist the CPC/Engineer when making
decisions involving automated devices (Distribution Engineering).
7. Synergi Computer Program – the load flow program derives topology information from
Avista’s GIS system. Updates to the Synergi database are performed by Distribution
Planning.
8. SCADA Variable Limit (SVL) – Avista uses temperature compensated program to
monitor conductors, cables, and series connected major equipment (e.g. transformers,
breakers, switches, regulators, and etc.). This system is deployed on Avista’s
EMS/SCADA system. The program is SME supported by Substation Engineering.
9. AMI Data – AMI service voltage data is used to identify services that are out of
compliance with the ANSI C84.1 standard of +/- 5% of 120 volts. AMI service load data
is used to identify transformers that are overloaded according to the standards set by
distribution engineering.

A typical distribution circuit is illustrated on the next page. Similar to municipal
water systems, grid capacity decreases with distance away from the source
substation. This leads to system ‘constraints’ as loads are added to the system
through direct customer action or load shifting between circuits (Avista).

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 110 of 414
Distribution System Enhancements
Business Case Justification Narrative Page 4 of 14

500A 200 A 100 A
Sub
Load Demand Exceeds Grid Capacity
Illustration of Distribution Grid Capacity Constraint
Avista’s Distribution System contains over 75 different wires and cables
2020 Avista Standard OH Primary Conductors
556 All-Aluminum (AAC) – 601 Amps (main trunk, urban)
-Aluminum (AAC) – 442 Amps (main trunk, rural)
– 238 Amps (gen purposes, rural)
– 119 Amps (lateral circuit)
Legacy Conductors
2/0-3/0 Copper – 319-369 Amps (main trunk)
– 197 Amps (main trunk)
- 110 Amps (lateral circuit)
Avista’s distribution grid contain over 1,000 miles of conductor equivalent or smaller than #6 Copper.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 111 of 414
Distribution System Enhancements
Business Case Justification Narrative Page 5 of 14
Option Description Consequence
Do-Nothing No Action to mitigate thermal
overloads
reliability and safety issues.
Conductor will ‘sag’ down beyond
design limits and contact joint-
telecom circuits or violate NESC
prescribed limits. In extreme
situations, conductor failure will
occur.
below acceptable levels and
customer outages will increase.
at all) will be done in a “scattered”
approach and not guided by
engineered plans and solutions.
treatment
solutions to effect peak load
demand reduction.
This option would be a viable,
areas.
FDR Tie This action is represented in the
program. By extending lines to
to underutilized circ
overloads. This action requires
capital investment.
Capacity
Increase
Reconductor overloaded
‘segments’ to increase line
capacity,
voltage issues, and correct
system protection issue
voltage regulators to mitigate
feeder level
Replace Transformers
additional transformers) to
and service voltage issues.
All electric components are
the most direct approach to
low voltage issues.
System
well as, reliability and safety
adding targeted “smart” devices.
Accomplishing this type of work
system is operated efficiently,
reliably, and safe.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 112 of 414
Distribution System Enhancements
Business Case Justification Narrative Page 6 of 14
Recommendation:
1. Do Nothing is unacceptable. Violates NESC/WAC regulations and industry
standards. It also represents an unacceptable level of risk to public safety
and infrastructure.
2. Targeted DSM is not allowed.
3. FDR Tie – represented in the program (indirect solution).
4. Segment Reconductor – represented in the program (direct solution).
5. System Enhancements – represented in the program.

Projects listed in the current 5-year “Distribution System Enhancements” program
are summarized on the Distribution Engineering SharePoint site. The following is a
summary of those projects listings as of June 2, 2020.

https://sp2016.corp.com/sites/sp/enso/dist/_layouts/15/start.aspx

Region 2021 2022 2023 2025
2,946,400 2,946,4 2,946,4 2,946,4
East 2,142,900 2,142,9 2,142,9 2,142,9 2,142,9
South 1,339,300 1,339,3 1,339,3 1,339,3 1,339,3
1,071,400
Total 7,500,000

One of the planning objectives is to levelize the resource demands and avoid
significant upswings or downturns in crew resource forecasting. Distribution
Engineering works closely with the Operating Divisions and Asset Maintenance to
develop a resource balanced work plan and maximize the effectiveness of Avista
craft resources. In addition, reductions in funding of this business case typically
result in increase spend in our Minor Blanket business case.

Distribution assets are fixed resources and therefore, project alternatives are
generally dominated by supply side solutions. Operating limitations are codified in
Avista internal standards (as listed) but derived through industry and regulatory
policies including: Washington Administrative Code (WAC), National Electric Safety
Code (NESC), National Electric Code (NEC), and IEEE/ANSI standards &
manufacturer recommendations specific to equipment ratings and operating limits.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 113 of 414
Distribution System Enhancements
Business Case Justification Narrative Page 7 of 14

Steering Committee or Advisory Group Information
Distribution Area Engineers and Distribution System Planning.
Tim Figart & Jon Gilrein – Spokane and Deer Park
Marshall Law – East Region (CDA, Kellogg, St. Maries, Sandpoint)
Dan Knutson – Othello, Davenport
Marc Lippincott – Colville
Chris Dux – South Region (Pullman, Clarkston, Grangeville)
Damon Fisher – Distribution System Planning
Cesar Godinez – Distribution Engineering Manager

The steering committee meets monthly to review projects and construction
processes and discuss near term operating conditions. The team also meets
quarterly to focus attention and resources on the system planning needs for grid
capacity, service revisions, and substation capacity.

Decision Making Process

The decision model is represented by individual ‘proposals’ coupled with joint
review and acceptance by distribution engineering and distribution system
planning. The project ‘proposals’ typically consist of a Project Requirement
Diagram (PRD) that outlines the scope of the project and includes supporting
calculations and documentation. The program’s business case is modified
annually to reflect the 5-year work plan. The Capital Planning Group then reviews
all of the submitted business cases and prioritizes and allocates resources across
the organization. Distribution infrastructure is not part of the “Engineering
Roundtable” with the exception of distribution substations.

The Distribution System Enhancements business case decision model is
illustrated on the next page.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 114 of 414
Distribution System Enhancements
Business Case Justification Narrative Page 8 of 14

ApprovalAcceptanceProposal
Authorized Resources by CPG
Requested Resources by Distribution Eng/Planning
(Area/Division Engineer)

1) Reconductor line “segment” to mitigate thermal overload or low voltage issues
2) Construct Tie-Line cto an adjacent circuit 3) Install/replace transformers to mitigate voltage issues or overloaded transformers
4) Install voltage regulator, capacitor bank, or other equipment to mitigate power quality issues.
5) Install recloser, protection devices, or other switching
equipment (including
“Smart” devices) to mitigate reliability/safety issues and/or add operational
flexibility.

mitted to CPG

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 115 of 414
Distribution System Enhancements
Business Case Justification Narrative Page 9 of 14
The undersigned acknowledge they have reviewed the Distribution System
Enhancements business case and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.

Template Version: 05/28/2020
Cesar Godinez Digitally signed by Cesar GodinezDN: C=US, E=[e-mail], O=Avista Utilities, OU=Distribution Engineering, CN=Cesar GodinezReason: I attest to the accuracy and integrity of this documentDate: 2020.07.08 12:23:28-07'00'
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 116 of 414
Distribution System Enhancements
Business Case Justification Narrative Page 10 of 14
EXAMPLES SHOWN FOR ILLUSTRATION:

FDR Status Report (provides baseline circuit performance and logistics
information) Warning Level (yellow highlight),

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 117 of 414
Distribution System Enhancements
Business Case Justification Narrative Page 11 of 14
Distribution “500 Amp” Plan (System Planning)
Company standard for the operation and load service planning associated with
Avista’s electric distribution grid.

Key elements-- Urban “FRD Tie” system. Requires that reserve capacity margins
be maintained so that adjacent circuits can restore service to customers in the event
of a planned or forced outage. In summary, no urban circuit should be loaded above
its 67% capacity limit.

Excerpt from “500 Amp” Plan. Source: Distribution SharePoint (3/15/17)

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 118 of 414
Distribution System Enhancements
Business Case Justification Narrative Page 12 of 14
Avista’s SCADA monitoring system incorporates a temperature compensated
thermal ampacity rating system known internally as SVL (Scada Variable Limit).
SVL has been in use since 1993. The following indicates a summary screen
indicating the top ten most heavily loaded (by % capacity) transmission lines,
substation power transformers, and distribution circuits. This screen is
continuously monitored by System Operators but also used by Area Engineers to
capture data during peak load conditions. It provides additional data to aid with
project planning for the distribution system enhancements program.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 119 of 414
Distribution System Enhancements
Business Case Justification Narrative Page 13 of 14
FDR by Area. Shown only to illustrate the scale of the effort to monitor our
distribution system.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 120 of 414
Distribution System Enhancements
Business Case Justification Narrative Page 14 of 14
Synergi Computer Modeling (Millwood 12F4 screen shot)

Computer simulation is the primary tool used to identify and develop strategies to
mitigate a thermal overload condition. Note, that Avista’s electric distribution
system has been developed over the full course of the Company’s operating
history and infrastructure installed near the turn of the century (1900) is still in-
service. Though current Avista construction standards limit the number of
overhead primary wires to four (4): #4 ASCR, 2/0 ACSR, 336 AAC, 556 AAC;
Avista maintains a fleet of seventy five (75) different primary wires and cables.
Many are no longer available commercially and we maintain ‘hand coils’ salvaged
from project work in order to effect maintenance repairs on those conductor
segments. We ceased to install overhead copper conductors in the 1950’s though
today, thousands of miles of #6A, #6CW, and other copper conductors remain in
service.

Synergi Computer System: Millwood 12F4 Circuit

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 121 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 122 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 123 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 124 of 414
Clearwater Wind Generation Interconnection
Business Case Justification Narrative Page 1 of 6
EXECUTIVE SUMMARY
Avista is a joint owner in the 500kV Colstrip Transmission System and party to the Colstrip Project
Transmission Agreement (“Agreement”). Under Federal Energy Regulatory Commission (“FERC”) rules and
the Agreement, Avista must comply with all rules and procedures governing the interconnection of new
generation facilities with the Colstrip Transmission System. Pursuant to the Agreement, Clearwater Energy
Resources, LLC requested interconnection of a 750MW wind project at Broadview (“Clearwater Wind
Project”), all required study processes were completed, and Avista executed a Large Generator
Interconnection Agreement with the developer on May 22, 2019 (“LGIA”).
Avista and the joint owners of the Colstrip Transmission System are obligated to fund their respective shares
of all Transmission Provider Interconnection Facilities and Network Upgrades applicable to the
interconnection of a Large Generator Interconnection project. Failure to fund this project will result in Avista
being in breach of both the Agreement and the LGIA, and would be a violation of FERC rules governing
generation interconnection. Such obligations arise from Avista’s ownership in the Colstrip Transmission
System, which has benefited Avista retail native load customers over the life of the Colstrip Project.

Avista’s allocation of costs for the construction of required facilities for the Clearwater Wind Project was
originally estimated to be $650,600, in 2018 dollars. The original Business Case was submitted and
approved, July, 2019. Overall project cost was reduced to $570,000 per the in-year adjustment request
approved June 17, 2020. Applicable service code and jurisdiction are 098-ED, common system-wide, electric
direct.

VERSION HISTORY
Version uthor Description Date Notes
1.0 Jeff Schlect Initial narrative drafted from pre-existing
approved case 7/30/2020 Existing Approved Case

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 125 of 414
Clearwater Wind Generation Interconnection
Business Case Justification Narrative Page 2 of 6

GENERAL INFORMATION

1. BUSINESS PROBLEM
Per the Agreement, Avista is a joint owner (joint tenants in common) of the Colstrip Transmission
System, which consists of approximately 250 miles of double circuit 500kV transmission facilities
extending from the Colstrip Project westward to the Broadview 500kV Substation and the Townsend
point of interconnection between the Colstrip Transmission System and the Bonneville Power
Administration’s Eastern Intertie 500kV facilities1. Under FERC rules and the Agreement, Avista must
comply with all rules and procedures governing the interconnection of new generation facilities with the
Colstrip Transmission System. Pursuant to the Agreement, Clearwater Energy Resources, LLC
requested interconnection of its 750MW Clearwater Wind Project to the Colstrip Transmission System
at Broadview. All required study processes were completed and Avista executed a Large Generator
Interconnection Agreement with the developer on May 22, 2019 (“LGIA”).

1 Avista owns a 10.2% share in the Colstrip-Broadview segment and a 12.1% share in the Broadview-
Townsend segment.
Requested Spend Amount $570,000
Requested Spend Time Period 2 years (2020-2021)
Requesting Organization/Department Energy Delivery / Transmission Services
Business Case Owner | Sponsor Jeff Schlect | Heather Rosentrater / Mike Magruder
Sponsor Organization/Department Energy Delivery / Transmission Services
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 126 of 414
Clearwater Wind Generation Interconnection
Business Case Justification Narrative Page 3 of 6
Avista and the joint owners of the Colstrip Transmission System are obligated to fund their respective
shares of all Transmission Provider Interconnection Facilities and Network Upgrades applicable to the
interconnection of a Large Generator Interconnection project. NorthWestern Energy (“NWE”) performs
all Transmission Operator functions under the Agreement, including construction budgeting and
forecasting for Colstrip Transmission System facilities. Avista’s allocation of costs for the construction
of required facilities for the Clearwater Wind Project was originally estimated to be $692,000 to be split
equally between 2020 and 2021. An updated forecast received from NorthWestern Energy on June 1,
2020, outlined an overall project decrease (from $692,000 to $570,000) along with a timing adjustment
between 2020 and 2021 (2020 - $110,000; 2021 - $460,000).

1.1 What is the current or potential problem that is being addressed?
Pursuant to the Agreement and its mandatory compliance requirements with FERC generation
interconnection rules, the Company must fund its applicable ownership share of constructions
costs associated with generation interconnection projects, including the Clearwater Wind
Project.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer.
The applicable driver for the Company’s construction investment in FERC jurisdictional
generation interconnection projects Mandatory & Compliance.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred.
Failure by the Company to provide construction funding for this project would be: (i) an act of
default under Section 25 of the Agreement, (ii) an act of default under the LGIA, and (iii) a
violation of FERC rules pursuant to which the Company could incur compliance penalties of up
to $1 million per day. The Clearwater Wind Project is currently planned for completion in 2021
but, depending upon action or inaction by the developer under the LGIA, the project and related
funding may be delayed.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Appendix B to the LGIA incorporates construction milestones for the project.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem.
Clearwater Wind Project #234 Feasibility Study Report (NWE)
Clearwater Wind Project #234 System Impact Study Report (NWE)
Clearwater Wind Project #234 Facilities Study Report (NWE)
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
Not applicable

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 127 of 414
Clearwater Wind Generation Interconnection
Business Case Justification Narrative Page 4 of 6

The Company must fund its allocated share of capital improvements under the Colstrip Transmission
Agreement, the LGIA and FERC rules.

Option Capital Cost Start Complete
Fund Network Upgrades under LGIA $570,000 01 2020 12 2021
Default on agreements and violate FERC rules N/A N/A N/A

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Not applicable – Mandatory and Compliance driver
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
2020 – Design, engineering and procurement
2021 – Construction
No related O&M reductions are expected with this project
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Capital funding only; no engineering or construction labor impacts to the Company. NWE
performs all construction and administration activities as Transmission Operator under the
Agreement.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Not applicable (only alternative is to not fund as outlined under 1.3 above)
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
NWE, as the Transmission Operator under the Agreement, manages the Colstrip Transmission
System construction program. Investments become used and useful and are placed in service
following construction completion and energization.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Business Case investment upholds the Company’s Code of Conduct and is consistent with its
lasting values. Such investment complies with applicable contract obligations and FERC rules.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 128 of 414
Clearwater Wind Generation Interconnection
Business Case Justification Narrative Page 5 of 6
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project.
Capital investment under this Business Case is mandatory – required by contract and FERC
rules. As outlined in 1.3 above, failure by the Company to provide construction funding for this
project would be: (i) an act of default under Section 25 of the Agreement, (ii) an act of default
under the LGIA, and (iii) a violation of FERC rules pursuant to which the Company could incur
compliance penalties of up to $1 million per day.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Counterparties to the Colstrip Transmission Agreement, joint owners of the Colstrip
Transmission System, and joint parties to the LGIA – NorthWestern Energy, PacifiCorp,
Portland General Electric and Puget Sound Energy
LGIA Counterparty – Clearwater Energy Resources, LLC
Bonneville Power Administration – Transmission entity interconnecting with the Colstrip
Transmission System at the point of change of ownership near Townsend, MT
2.8.2 Identify any related Business Cases
Colstrip Transmission

3.1 Steering Committee or Advisory Group Information
The Colstrip Transmission Committee, of which the Company is a member, meets periodically
to review construction funding associated with the Colstrip Transmission System, including
generation interconnection projects. The Company’s Transmission Services department
administers the LGIA.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Pursuant to Section 22 of the Agreement, the Colstrip Transmission Committee is established
to facilitate cooperation, interchange of information and efficient management of the Colstrip
Transmission System. The Colstrip Transmission Committee consists of five members, each
designated by one of the parties to the Agreement. Each committee member has the right to
vote their party’s ownership share in the Colstrip Transmission System. The Company’s
Transmission Services department participates on the Colstrip Transmission Committee and
administers the LGIA.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Such items are reviewed by the Colstrip Transmission Committee and documented by NWE
as the Transmission Operator under the Agreement.

The undersigned acknowledge they have reviewed the Clearwater Wind Generation
Interconnection Business Case and agree with the approach it presents. Significant
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 129 of 414
Clearwater Wind Generation Interconnection
Business Case Justification Narrative Page 6 of 6
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.

Signature: Date:
Print Name: Jeff Schlect
Title: Senior Manager, FERC Policy and
Transmission Services

Role: Business Case Owner

Signature: Date:
Print Name: Mike Magruder
Title: Director, Transmission Operations
and System Planning

Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 130 of 414
Clearwater Wind Generation Interconnection
Business Case Justification Narrative Page 7 of 7
The undersigned acknowledge they have reviewed the Clearwater Wind Generation
Interconnection Business Case and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.
Signature:Date:
Print Name:Jeff Schlect
Title:Senior Manager, FERC Policy and
Transmission Services
Role:Business Case Owner
Signature:Date:
Print Name:Mike Magruder
Title:Director, Transmission Operations
and System Planning
Role:Business Case Sponsor
Signature:Date:
Print Name:
Title:
Role:Steering/Advisory Committee Review
Template Version:05/28/2020
Jeff Schlect Digitally signed by Jeff Schlect
Date: 2020.07.30 17:30:45 -07'00'7/30/2020
Michael A. Magruder Digitally signed by Michael A.
Magruder
Date: 2020.07.31 12:22:28 -07'00'7/31/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 131 of 414
Colstrip Transmission
Business Case Justification Narrative Page 1 of 7
EXECUTIVE SUMMARY
Avista is a joint owner in the 500kV Colstrip Transmission System and party to the Colstrip Project
Transmission Agreement (“Agreement”). Avista and the joint owners are obligated to fund their respective
shares of the Colstrip Transmission System construction and maintenance budgets, as approved by the
Colstrip Transmission Committee, which consists of representatives of each of the parties to the Agreement.
The Colstrip Transmission Committee reviews and approves, on an annual basis, the capital and O&M
expense program proposed by NorthWestern Energy (“NWE”) (the designated Transmission Operator under
the Agreement). Pursuant to Section 22 of the Agreement, Avista provides annual input to, and approval for,
the Colstrip Transmission System capital and O&M expense program commensurate with its ownership
shares in the Colstrip Transmission System.1

In conjunction with the Company’s ownership interest in Colstrip Project Units 3 and 4, the Colstrip
Transmission System has benefited the Company’s retail native load customers since the early 1980’s. To
continue to reliably integrate the Company’s Colstrip Project resources to native load and to meet applicable
NERC transmission planning and operational reliability standards, the Colstrip Transmission System must
be maintained. Examples of recent and pending capital expenditures in the Colstrip Transmission System
include end-of-life replacement of 500kV power circuit breakers at the Colstrip 500/230kV Station and 500kV
structure relocation to mitigate erosion risk caused by high runoff in the Little Big Horn River.

Colstrip Transmission program expenditures have averaged $348,000 over the past ten years. NWE’s
latest draft plan was released in July, 2020, outlining a five-year (2020-2024) average program expense of
$516,000. The original Business Case was submitted and approved in April, 2017. Applicable service
code and jurisdiction are 098-ED, common system-wide, electric direct.

VERSION HISTORY
Version uthor Description Date Notes
1.0 Jeff Schlect Initial narrative drafted from pre-existing
approved case 7/28/2020 Existing Approved Case

1 Avista owns a 10.2% share in the Colstrip-Broadview segment and a 12.1% share in the Broadview-
Townsend segment.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 132 of 414
Colstrip Transmission
Business Case Justification Narrative Page 2 of 7

GENERAL INFORMATION

1. BUSINESS PROBLEM
As part of the construction and integration of Colstrip Units 3 and 4 in the early 1980s for the benefit of
the Company’s native load retail customers, the Colstrip project participants constructed the Colstrip
Transmission System, approximately 250 miles of double circuit 500kV transmission facilities
extending from the Colstrip Project westward to the Broadview 500kV Substation and the Townsend
point of interconnection between the Colstrip Transmission System and the Bonneville Power
Administration’s Eastern Intertie 500kV facilities.

Avista owns a 15% share of Colstrip Units 3 and 4 (approximately 225MW). Reliable operation of the
Colstrip Transmission System is necessary to transfer Colstrip output to the respective systems of
each joint project owner, including Avista (other project owners are: NorthWestern Energy, PacifiCorp,
Portland General Electric and Puget Sound Energy). Avista and the other joint project owners are
party to the Colstrip Project Transmission Agreement which, among other things, obligates Avista to
fund its commensurate share of all construction and maintenance expenses for the ongoing operation,
Requested Spend Amount $724,000 (2021)
Requested Spend Time Period Ongoing Annual Program
Requesting Organization/Department Energy Delivery / Transmission Services
Business Case Owner | Sponsor Jeff Schlect | Heather Rosentrater / Mike Magruder
Sponsor Organization/Department Energy Delivery / Transmission Services
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 133 of 414
Colstrip Transmission
Business Case Justification Narrative Page 3 of 7
maintenance, renewal and replacement of the jointly owned Colstrip Transmission System facilities.
Examples of recent expenditures in the Colstrip Transmission System are noted in Section 2.2 below.
As NERC transmission planning and operational reliability standards2 evolve, compliance with both
operational and planning standards may require replacement of, or upgrades to, Colstrip Transmission
System facilities.
1.1 What is the current or potential problem that is being addressed?
Pursuant to the Agreement, the Company must fund its applicable ownership share of capital
improvements to the jointly owned Colstrip Transmission System.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer.
The Company’s capital investment in the Colstrip Transmission System is driven by its
contractual obligations under the Agreement (Mandatory & Compliance). Related drivers
include Asset Condition and Failed Plant & Operations.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred.
Failure to fund its allocated share of costs under the Agreement will put the Company into default
and would eliminate the Company’s right to use the Colstrip Transmission System to integrate
its resources for service to its bundled retail native load customers.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Not applicable
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem.
Not applicable
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
Not applicable

The Company must fund its allocated share of capital improvements under the Colstrip Transmission
Agreement.

2 Among its other provisions, the U.S. Energy Policy Act of 2005 provided for the establishment of mandatory
reliability standards and authorized the Federal Energy Regulatory Commission (FERC) to assess penalties of
up to $1 million per day per violation for non-compliance with these standards and other FERC regulations.
FERC has certified the North American Electric Reliability Organization (NERC) to establish and enforce these
reliability standards. The Company has a statutory obligation to plan, improve, upgrade, and operate its
transmission system, including the Colstrip Transmission System, to maintain compliance with these standards
and is required to self-certify its compliance with these standards on an annual basis.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 134 of 414
Colstrip Transmission
Business Case Justification Narrative Page 4 of 7
Option Capital Cost Start Complete
Fund capital program under the Agreement $516,000 1981 Ongoing
Do not fund – Contract default Undetermined --- ---

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Additional Information – In addition to upholding the Company’s contractual obligations and
maintaining the ability to integrate its Colstrip generation output for service to its bundled retail
native load customers, Colstrip Transmission program funding also provides the Company a
future transmission alternative for consideration under the Company’s Integrated Resource
Planning process, to integrate potential renewable resources located in Montana.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
Capital amounts are used for improvements, renewals and replacements of Colstrip
Transmission System assets. Examples of recent expenditures in the Colstrip Transmission
System include:
 End-of-life replacement of 500kV power circuit breakers at the Colstrip 500/230kV
Substation
 Erosion mitigation caused by record high runoff in the Big Horn River, threatening the
stability of two 500kV structures
 Construction of optical ground wire (OPGW) communication facilities between Broadview
and Colstrip to meet dual communication path requirements under North American Electric
Reliability Corporation (NERC) standards
 500kV relay replacements
 Hardware, software and operating system upgrades to maintain compliance with applicable
operating standards
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Capital funding only; no engineering or construction labor impacts to the Company. NWE
performs all construction and construction administration activities as Transmission Operator
under the Agreement.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Not applicable (only alternative is to not fund and default on contract)
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
NWE, as the Transmission Operator under the Agreement, manages the Colstrip Transmission
System construction program. Program investments, as improvements, renewals and
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 135 of 414
Colstrip Transmission
Business Case Justification Narrative Page 5 of 7
replacements for the existing Colstrip Transmission System, become used and useful each year
upon being placed in-service.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Program investment upholds the Company’s Code of Conduct and is consistent with its lasting
values. Colstrip Transmission System investment maintains the Company’s ability to integrate
its Colstrip generation assets for service to bundled retail native load customers and provides
the Company with a future transmission alternative to integrate potential renewable resources
located in Montana.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project.
Capital investment under the program is mandatory – required by contract – pursuant to the
Agreement. The Company’s ongoing ownership in the Colstrip Transmission System may be
evaluated consistent with its assessment of potential future resource acquisitions in Montana
under the Company’s Integrated Resource Planning activities.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Avista Power Supply – Internal customer for the integration of resources designated for
service to bundled retail native load customers
Counterparties to the Colstrip Transmission Agreement and joint owners of the Colstrip
Transmission System – NorthWestern Energy, PacifiCorp, Portland General Electric and
Puget Sound Energy
Bonneville Power Administration – Transmission entity interconnecting with the Colstrip
Transmission System at the point of change of ownership near Townsend, MT
2.8.2 Identify any related Business Cases
Clearwater Wind Generation Integration

3.1 Steering Committee or Advisory Group Information
Pursuant to Section 22 of the Agreement, Avista provides annual input to, and approval for, the
Colstrip Transmission System capital and O&M expense program commensurate with its
ownership shares in the Colstrip Transmission System. The Colstrip Transmission Committee,
of which the Company is a member, meets periodically to review, and provide recommendations
for, the annual capital program administered by NWE. The Colstrip Transmission Committee
provides approval for each year’s capital program.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 136 of 414
Colstrip Transmission
Business Case Justification Narrative Page 6 of 7
3.2 Provide and discuss the governance processes and people that will
provide oversight
Pursuant to Section 22 of the Agreement, the Colstrip Transmission Committee is established
to facilitate cooperation, interchange of information and efficient management of the Colstrip
Transmission System. The Colstrip Transmission Committee consists of five members, each
designated by one of the parties to the Agreement. Each committee member has the right to
vote their party’s ownership share in the Colstrip Transmission System. Section 22(f) of the
Agreement outlines all matters that shall be submitted to the committee by NWE for approval,
including Colstrip Transmission System construction and operating budgets.
With respect to long-term continuing ownership and participation in the Colstrip Transmission
System, the Company’s Power Supply and Transmission Services groups will, under the
Company’s Integrated Resource Planning process, analyze and assess such costs and benefits
related to the integration of potential renewable resources located in Montana.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Such items are reviewed by the Colstrip Transmission Committee and documented by NWE
as the Transmission Operator under the Agreement.
The undersigned acknowledge they have reviewed the Colstrip Transmission
Business Case and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Print Name: Jeff Schlect
Title: Senior Manager, FERC Policy and
Transmission Services

Role: Business Case Owner

Signature: Date:
Print Name: Mike Magruder
Title: Director, Transmission Operations
and System Planning

Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 137 of 414
Colstrip Transmission
Business Case Justification Narrative Page 7 of 7

Template Version: 05/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 138 of 414
Colstrip Transmission
Business Case Justification Narrative Page 7 of 7
The undersigned acknowledge they have reviewed the Colstrip Transmission
Business Case and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.
Signature:Date:
Print Name:Jeff Schlect
Title:Senior Manager, FERC Policy and
Transmission Services
Role:Business Case Owner
Signature:Date:
Print Name:Mike Magruder
Title:Director, Transmission Operations
and System Planning
Role:Business Case Sponsor
Signature:Date:
Print Name:
Title:
Role:Steering/Advisory Committee Review
Template Version:05/28/2020
Jeff Schlect Digitally signed by Jeff Schlect
Date: 2020.07.30 17:22:00 -07'00'7/30/2020
Michael A. Magruder Digitally signed by Michael A.
Magruder
Date: 2020.07.31 12:21:25 -07'00'7/31/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 139 of 414
Protection System Upgrades for PRC-002
Business Case Justification Narrative Page 1 of 6
EXECUTIVE SUMMARY
This section is reserved to provide a brief description of the business case and high level summary of the projects or
programs included. Please limit to no more than 2 paragraphs. Components that should be included: 1) a synopsis of
the problem, 2) the service code and jurisdiction of customers impacted, 3) the recommended solution, 4) the cost of
the solution, 5) how the solution will benefit customers identified, 6) the significance of the timeline and 7) the risks of
not approving this business case.
<< Both the Executive Summary and Version History should fit into one page >>

NERC reliability standard PRC-002-2 defines the disturbance monitoring and
reporting requirements to have adequate data available to facilitate analysis of Bulk
Electric System (BES) Disturbances. The methodology of Attachment A of the NERC
standard was performed to identify the affected buses within the Avista BES. The
Protection Systems must be capable of recording electrical quantities for each BES
Elements it owns connected to the BES buses identified.
Non-compliance can carry a fine of up to a million dollars per day based on severity.
This business case is important to customers because it allows analysis of system
faults for the BES that can lead to continued stability and reliability of the electric
system.

Service: ED – Electric Direct
Jurisdiction: AN – Allocated North
Engineering Roundtable Request Number: ERT_2016-07
Cost of Solution: $12,000,000

VERSION HISTORY
Version uthor Description Date Notes
1.0 Randy Spacek Initial Version 7/11/2017 Initial Version
2.0 Glenn Madden Revised to remove DRAFT
watermark 5/28/2019
3.0 Karen Kusel /
Glenn Madden Update to 2020 Template 06/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 140 of 414
Protection System Upgrades for PRC-002
Business Case Justification Narrative Page 2 of 6
GENERAL INFORMATION

1 BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
NERC reliability standard PRC-002-2 defines the disturbance monitoring and reporting
requirements to have adequate data available to facilitate analysis of Bulk Electric
System (BES) Disturbances. The methodology of Attachment A of the NERC standard
was performed to identify the affected buses within the Avista BES. The Protection
Systems must be capable of recording electrical quantities for each BES Elements it
owns connected to the BES buses identified.
The present Protection Systems are either electromechanical or first generation relays
not capable of meeting the NERC PRC-002-2 standard requirements of fault recording.
The scope of the project is to upgrade the existing Protection Systems on various 230
kV and 115kV terminals to Fault Recording (FR) capability per PRC- 002 requirements
at Beacon, Boulder, Rathdrum, Cabinet Gorge, North Lewiston, Lolo, Pine Creek,
Shawnee, and Westside Substations. Implementation is a phased approach with 50%
compliaint within 4 years and fully compliant within 6 years of the effective date 7/1/16.
The total number of affected terminals is 49.
Non-compliance can carry a fine of up to a million dollars per day based on severity.
1.1 What is the current or potential problem that is being addressed?
PRC-002-2 went into effect on 7/1/2016, we have six years to bring our protection system
into compliance with this updated standard.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer Service
Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset Condition, or
Failed Plant & Operations) and the benefits to the customer
Mandatory & Compliance is the main driver for this project. But this will also allow more
information to be collected to facilitate analysis of BES disturbances.
1.3 Identify why this work is needed now and what risks there are if not approved or is
deferred
Avista is required to comply with PRC-002 by July 1, 2022.
Requested Spend Amount $12,000,000
Requested Spend Time Period 5 Years
Requesting Organization/Department Substation Engineering
Business Case Owner | Sponsor Glenn Madden | Josh Diluciano
Sponsor Organization/Department Electrical Engineering
Phase Execution
Category Project
Driver Mandatory & Compliance
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 141 of 414
Protection System Upgrades for PRC-002
Business Case Justification Narrative Page 3 of 6
1.4 Identify any measures that can be used to determine whether the investment would
successfully deliver on the objectives and address the need listed above.
System Planning Assessments, Relay & Protection Design Reporting for PRC-002.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information; do not attach]
NERC Reliability Standard PRC-002-2
NERC Project 200711 Disturbance Monitoring:
DL-2007-11_DM_Imp_Plan_2014Sep01_clean
PRC-002 Bus Fault Summary & Anaylsis 2016.xlsx
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.
The present Protection Systems are either electromechanical or first generation relays
not capable of meeting the NERC PRC-002-2 standard requirements of fault recording.
2 PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]
The Protection System upgrade of 49 terminals impacts the resources of Engineering
and GPSS over a 5 year period. The NERC standard requires compliance by specific
dates. By missing the compliance date set forth by NERC, Avista not only risks
monetary penalties based on severity but reputational damage as well.

Cost estimates per terminal from previous Protection System upgrades at a total
installed cost of $150k.

Protection System upgrades is the preffered solution. The relay replacement will not
only provide the recording capability but will improve system reliability, reduce
maintenance and support other NERC standard requirements (PRC-023, PRC-004).
In the past, Avista has attempted to put in a single digital fault recorder that complicated
the wiring and CT circuits within a station. All recorders have since been removed.

Option Capital Cost Start Complete
Upgrade Protection Systems $4.86M 02 2017 10 2022
Do Nothing $0M
Installation of a digital recorder on each BES
bus to provide the SER and FR data.

2.1 Describe what metrics, data, analysis or information was considered when preparing
this capital request.
Examples include:
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 142 of 414
Protection System Upgrades for PRC-002
Business Case Justification Narrative Page 4 of 6
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
Since this is a compliance mandate, we also looked at other standards and relay options.
2.2 Discuss how the requested capital cost amount will be spent in the current year (or
future years if a multi-year or ongoing initiative). (i.e. what are the expected functions,
processes or deliverables that will result from the capital spend?). Include any known or
estimated reductions to O&M as a result of this investment.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing
reductions to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
2020 - $3,200,000
2021 – $5,420,000
2022 – $2,480,000
2023 – $150,000
O&M costs may be reduced with this equipment replacement.
2.3 Outline any business functions and processes that may be impacted (and how) by
the business case for it to be successfully implemented.
[For example, how will the outcome of this business case impact other parts of the business?]
Delay of the other projects due to resource scarcity.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation
strategies for each alternative.
See Section 2.0 for alternative discussion.
2.5 Include a timeline of when this work will be started and completed. Describe when
the investments become used and useful to the customer. spend, and transfers to
plant by year.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful.
(i.e. if transfer to plant occurs monthly, quarterly or upon project completion).]
Project is currently underway, construction is in progress at multiple sites and will conclude
in 2022 and closeout of project will occur in 2023. Transfers to plant are completed when
the work at each location is completed.
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives
and mission statement of the organization.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]
Mission: We improve our customers’ lives through innovative energy solutions.
Vision: Better energy for life
Fault recording at substations enables root cause analysis, which can lead to improved
reliability. Additionally the work is mandatory from NERC.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 143 of 414
Protection System Upgrades for PRC-002
Business Case Justification Narrative Page 5 of 6
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please explain
how the investment prudency will be reviewed and re-evaluated throughout the
project
NERC required projects are vetted through NERC as to the viability of requiring the work to
be done and the associated benefit. The investment is likely to result in improved reliability
to the BES.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Electrical Engineering, Generation Production/Substation Support, Transmission
Operations and System Planning and Operations
2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]
Not Applicable.
3 MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a
part of your departmental prioritization process.]
The Engineering Roundtable process is used to identify projects requmng Transmission,
Substation, or Protection (TS&P) engineering support. The committee is responsible to
track TS&P project requests, facilitate prioritization of TS&P capital projects across
Engineering, Operations, and Planning), and to ensure projects are completed consistent
with the company's mission and corporate strategies.
3.2 Provide and discuss the governance processes and people that will provide
oversight
Engineering Roundtable meets several times a year to analyze current and future projects.
3.3 How will decision-making, prioritization, and change requests be documented and
monitored
Project folders are saved to Engineering shared drives and Businesss Case Funds
Requests are available on the Finance sharepoint site

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 144 of 414
Protection System Upgrades for PRC-002
Business Case Justification Narrative Page 6 of 6
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Protection System Upgrades for
PRC-002 and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.

Signature: Date:
Print Name: Glenn Madden
Title: Manager, Substation Engineering
Role: Business Case Owner

Signature: Date:
Print Name: Josh DiLuciano
Title: Director, Electrical Engineering
Role: Business Case Sponsor

Signature: Date:
Print Name: Damon Fisher
Title: Principle Engineer
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
1/5/2021
1/5/2021
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 145 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 146 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 147 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 148 of 414
Transmission Construction - Compliance
Business Case Justification Narrative Page 1 of 10
EXECUTIVE SUMMARY
The Transmission Construction – Compliance Business Case covers the Transmission rebuild and reconductor work
necessary to maintain compliance with the NERC Reliability Standard TPL-001-4 – Transmission System Planning
Performance Requirements (“Standard”). It has 8 requirements and 57 sub-requirements related to planning and
analysis, including the requirement for robust system models to determine system stability, voltage levels and system
performance under various scenarios. This standard mandates that an annual planning assessment be conducted
and corrective actions be identified and implemented to remedy any system performance deficiencies In addition, when
Avista’s system planning studies indicate any kind of problem that could arise in the transmission system, it must be
remedied within specific timeframes. The Transmission Construction - Compliance Program provides funding to
mitigate any identified reliability issues in order to remain in compliance with NERC requirements.
The implementation of this business case will be considered successful if these projects are all completed prior to the
required compliance dates identified in the Engineering Roundtable Project List, which are copied from the Corrective
Action Plans (within the annually published Avista System Planning Assessment).
The Transmission Construction – Compliance Business Case also covers the Transmission line rebuild for lines not
meeting National Electric Safety Code (NESC) physical capacities for appropriate loading cases. These code
minimums have also been adopted into the State of Washington's Administrative Code (WAC). These lines may have
met the NESC criteria at the time of their original construction, but have been found to not be up to standards through
anaysis either as a result of requests for facility additions, or identified past additions not analyzed at the time of
installation.
The recommended solution is to build, rebuild, or reconductor transmission lines as identified in the Corrective Action
Plans to stay in compliance with NERC mandatory and enforceable Reliability Standards (most notably TPL-001-4)
and the NESC code (via WAC).
If Avista does not implement this business case, the company is at risk of violating NERC Reliability Standard
Requirements and could be subject to penalties of up to $1M per day for the duration of any such violation. Following
a “do nothing” option for this business case would likely be treated as an aggravating factor by the regulatory authority
when assessing enforcement actions. If Avista does not fully implement this business case, it also runs the risk of
being fined for not staying in compliance with the NESC code and WAC rules. There are no expected business impacts
to continuing this program in place. A spend of $5,050,000 is needed to complete the planned 2021-2025 projects .
This Program will have a Service Code of Electric Direct and a Rate Jurisdiction of Allocated North.
The Business Case contains four projects:
• KEC Rimrock Substation Interconnection
• Beacon-Ross Park 115kV Rebuild
• Beacon-Boulder #1 115kV Rebuild (east of Irvin)
• Ninth & Central-Sunset 115kV Partial Rebuild (Upgrade to 795 ACSS)
The customer benefits from this Business Case through increased service reliability.

VERSION HISTORY
Version Author Description Date Notes
Draft Ken Sweigart Initial draft of original business case 7/10/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 149 of 414
Transmission Construction - Compliance
Business Case Justification Narrative Page 2 of 10
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 The Transmission Construction – Compliance Business Case covers the Transmission rebuild and
reconductor work necessary to maintain compliance with the NERC Reliability Standard TPL-001-4 –
Transmission System Planning Performance Requirements (“Standard”). This standard mandates that an
annual planning assessment be conducted and corrective actions be identified and implemented to
remedy any system performance deficiencies. Corrective Action Plans must be completed within the
required timeframe to meet the system performance requirements dictated by the Standard.
The Transmission Construction – Compliance Business Case also covers the Transmission line rebuild
for lines not meeting National Electric Safety Code (NESC) physical capacities for appropriate loading
cases. These code minimums have also been adopted into the State of Washington's Administrative Code
(WAC). These lines may have met the NESC criteria at the time of their original construction, but have
been found to not be up to standards through anaysis either as a result of requests for facility additions,
or identified past additions not analyzed at the time of installation.
1.2 What is the current or potential problem that is being addressed? NERC
Reliability Standards and NESC loading capacities.
1.3 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer Mandatory
& Compliance: Customer benefits by having a Transmission System in compliance with Federal Code
and State Law.
1.4 Identify why this work is needed now and what risks there are if not
approved or is deferred Relevant sections of the NERC Sanction Guidelines are cited below:
2.9 Concealment or Intentional Violation
NERC or the Regional Entity shall always consider as an aggravating factor any attempt by
a violator to conceal the violation from NERC or the Regional Entity, or any intentional
violation incurred for purposes other than a demonstrably good faith effort to avoid a
significant and greater threat to the immediate reliability of the Bulk Power System.

2.10 Economic Choice to Violate
Requested Spend Amount $5,050,000
Requested Spend Time Period 5 years
Requesting Organization/Department TLD Engineering
Business Case Owner | Sponsor Josh DiLuciano/Heather Rosentrater
Sponsor Organization/Department Energy Delivery/Electrical Engineering
Phase Execution
Category Program
Driver Mandatory & Compliance
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 150 of 414
Transmission Construction - Compliance
Business Case Justification Narrative Page 3 of 10
Penalties shall be sufficient to assure that entities responsible for complying with Reliability
Standards do not have incentives to make economic choices that cause or unduly risk
violations of Reliability Standards, or incidents resulting from violations of the Reliability
Standards. Economic choice includes economic gain for, or the avoidance of costs to, the
violator. NERC or the Regional Entity shall treat economic choice to violate as an
aggravating factor when determining a Penalty.
2.15 Maximum Limitations on Penalties
In the United States, the maximum Penalty amount that NERC or a Regional Entity will
assess for a violation of a Reliability Standard Requirement is $1,000,000 per day per
violation. NERC and the Regional Entities will assess Penalties amounts up to and including
this maximum amount for violations where warranted pursuant to these Sanction
Guidelines.
In the case of projects addressing NESC capacity inadequacies, Avista will be cognisant of
not meeting the WAC.
.Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above. As-Built confirmation of mitigation measures.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
KEC Rimrock System Impact Study.docx
CAI Structure Analysis Results_BEA-BLD.xlsx
CAI Structure Analysis Results_BEA-ROS.xlsx
2019 Avista System Planning Assessment

1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 151 of 414
Transmission Construction - Compliance
Business Case Justification Narrative Page 4 of 10

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 152 of 414
Transmission Construction - Compliance
Business Case Justification Narrative Page 5 of 10

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 153 of 414
Transmission Construction - Compliance
Business Case Justification Narrative Page 6 of 10

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 154 of 414
Transmission Construction - Compliance
Business Case Justification Narrative Page 7 of 10

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 155 of 414
Transmission Construction - Compliance
Business Case Justification Narrative Page 8 of 10

This is the continuation of a Program first started in 2012 (execution phase), and requires the mitigation of
clearances violations.

Option Capital Cost Start Complete
Maintain Compliance $5.05M 01-2021 12-2025
[Alternative #1] See 1.5.2 $M MM YYYY MM YYYY
[Alternative #2] See 1.5.2 $M MM YYYY MM YYYY
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
See 1.5.2
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
This program is in the various stages based on individual project.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Primary impacts are in the area of obtaining Transmission system outages and construction resources.
Although Transmission Line Design has the ability to Contract for construction services on the large
projects, internal construction resources typically perform Spokane area jobs.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
See 1.5.2.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
KEC Rimrock Substation Interconnection: 2020-2022
Beacon-Ross Park 115kV Rebuild: 2020-2021
Beacon-Boulder #1 115kV Rebuild (east of Irvin): 2020-2022
Ninth & Central-Sunset 115kV Partial Rebuild (Upgrade to 795 ACSS): 2022-2023
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 156 of 414
Transmission Construction - Compliance
Business Case Justification Narrative Page 9 of 10
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Aligns with Avista’s Culture of Compliance.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Design solution performed within PLS-CADD, which is the industry leader in providing Transmission Line
Design computer based programs. Designs are reviewed at multiple stages to ensure prudency and
maximum Stakeholder value.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Many and varied throughout Avista.
2.8.2 Identify any related Business Cases
None.

3.1 Steering Committee or Advisory Group Information
The Engineering Roundtable functions as the Vetting Platform, Steering Committee, and Advisory Group.
Provide and discuss the governance processes and people that will
provide oversight
Electrical Engineering Expected Spend Committee reviews on a monthly basis ongoing spend for projects
approved by the ERT. Committee members include Managers, Project Managers, analysts, and the
Electrical Engineering Director.
3.2 HOW WILL DECISION-MAKING, PRIORITIZATION, AND CHANGE
REQUESTS BE DOCUMENTED AND MONITORED
During the design phase these functions are processed through the Engineering Roundtable. During large
project Contracted construction, Change Orders are processed through Supply Chain. On smaller in-
house construction projects, changes are agreed upon at the Project Eneginer/Project Manager, and are
documented in the As-Built process.
The undersigned acknowledge they have reviewed the Transmission Construction
– Compliance Business Case Justification Narrative and agree with the approach it
presents. Significant changes to this will be coordinated with and approved by the
undersigned or their designated representatives.

Signature: Date:
Print Name:
Title:
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 157 of 414
Transmission Construction - Compliance
Business Case Justification Narrative Page 10 of 10
Role: Business Case Owner

Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 158 of 414
Transmission NERC Low Priority Ratings Mitigation
Business Case Justification Narrative Page 1 of 5
EXECUTIVE SUMMARY
The Transmission NERC Low Priority Lines Mitigation Business Case covers the work to reconfigure insulator
attachments, and/or rebuild existing transmission line structures, or remove earth beneath transmission lines in order
to mitigate ratings/sag discrepancies found between "design" and "field" conditions as determined by LiDAR survey
data. This program was undertaken in response to the October 7, 2012 North American Electric Reliability Corporations
(NERC) "NERC Alert" - Recommendation to Industry, "Consideration of Actual Field Conditions in Determination of
Facility Ratings". This Capital Program covers mitigation work on Avista's "Low Priority" 230kV and 115kV transmission
lines. Mitigation brings lines in compliance with the National Electric Safety Code (NESC) minimum clearances values.
These code minimums have also been adopted into the State of Washington's Administrative Code (WAC). This
program is expected to be completed in 2023.
The recommended solution is to correct the issues found in the LiDAR studies to stay in compliance with the NESC
code and WAC. There are no expected business impacts to continuing this program in place. If Avista does not fully
implement this business case, it runs the risk of being fined for not staying in compliance with the NESC code and
WAC rules. A spend of $6,700,000 is needed to complete the mitigations by 2023. This Program will have a Service
Code of Electric Direct and a Rate Jurisdiction of Allocated North.
The customer benefits from this Business Case through increased service reliability.

VERSION HISTORY
Version Author Description Date Notes
Draft Ken Sweigart Initial draft of original business case 7/10/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 159 of 414
Transmission NERC Low Priority Ratings Mitigation
Business Case Justification Narrative Page 2 of 5
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 The Transmission NERC Medium Priority Lines Mitigation Business Case covers the work to reconfigure
insulator attachments, and/or rebuild existing transmission line structures, or remove earth beneath
transmission lines in order to mitigate ratings/sag discrepancies found between "design" and "field"
conditions as determined by LiDAR survey data. This program was undertaken in response to the October
7, 2012 North American Electric Reliability Corporations (NERC) "NERC Alert" - Recommendation to
Industry, "Consideration of Actual Field Conditions in Determination of Facility Ratings". This Capital
Program covers mitigation work on Avista's "Low Priority" 230kV and 115kV transmission lines. Mitigation
brings lines in compliance with the National Electric Safety Code (NESC) minimum clearances values.
These code minimums have also been adopted into the State of Washington's Administrative Code (WAC).
1.2 What is the current or potential problem that is being addressed? Clearance
violations.
1.3 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer Mandatory
& Compliance: Customer benefits by having a Transmission System in compliance with Federal Code
and State Law.
1.4 Identify why this work is needed now and what risks there are if not
approved or is deferred The North American Electric Reliability Corporations (NERC) "NERC
Alert" originally identified Low Priority Transmission Line assessments to complete by December 31, 2013.
Although a mitigation timeline did not include a penalty threat, we have been operating under a grace
period that requires us to report progress every six months. Completing the program by 2023 will show
us taking ten years to complete the effort. Deferring completion is tempting greater scrutiny from NERC
and delays mitigation of a compliance violations recognized by Washington State Law.
1.5 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above. As-Built confirmation of mitigation measures.

Requested Spend Amount $6,700,000
Requested Spend Time Period 3 years
Requesting Organization/Department TLD Engineering
Business Case Owner | Sponsor Josh DiLuciano/Heather Rosentrater
Sponsor Organization/Department Energy Delivery/Electrical Engineering
Phase Execution
Category Program
Driver Mandatory & Compliance
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 160 of 414
Transmission NERC Low Priority Ratings Mitigation
Business Case Justification Narrative Page 3 of 5
1.6 Supplemental Information
1.6.1 Please reference and summarize any studies that support the problem
CAN-0009_FAC-008 FAC-009.pdf
1.6.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.

This is the continuation of a Program first started in 2012 (execution phase), and requires the mitigation of
clearances violations.

Option Capital Cost Start Complete
Mitigate Violations $6.7M 01-2021 12-2023
[Alternative #1] $M MM YYYY MM YYYY
[Alternative #2] $M MM YYYY MM YYYY
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 161 of 414
Transmission NERC Low Priority Ratings Mitigation
Business Case Justification Narrative Page 4 of 5
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
This program is in the Execution Stage with spend directed primarily at structure change-outs resulting in
greater ground clearance.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Primary impacts are in the area of obtaining Transmission system outages and construction resources.
Although Transmission Line Design has the ability to Contract for construction services on the large
projects, internal construction resources typically perform the smaller jobs.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Raising structure heights is by far the go to alternative. In one instance the removal of earth was used.
Earth removal can trigger permitting, which otherwise would not be necessary.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
Smaller projects can take place throughout the year. Most of the large projects take place in the Fall
months and Transfer to Plant in the November time frame.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Aligns with Avista’s Culture of Compliance.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Mitigation design solution performed within PLS-CADD, which is the industry leader in providing
Transmission Line Design computer based programs. Designs are reviewed at multiple stages to ensure
prudency and maximum Stakeholder value.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Many and varied throughout Avista.
2.8.2 Identify any related Business Cases
None.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 162 of 414
Transmission NERC Low Priority Ratings Mitigation
Business Case Justification Narrative Page 5 of 5
3.1 Steering Committee or Advisory Group Information
The Engineering Roundtable functions as the Vetting Platform, Steering Committee, and Advisory Group.
Provide and discuss the governance processes and people that will
provide oversight
Electrical Engineering Expected Spend Committee reviews on a monthly basis ongoing spend for projects
approved by the ERT. Committee members include Managers, Project Managers, analysts, and the
Electrical Engineering Director.
3.2 HOW WILL DECISION-MAKING, PRIORITIZATION, AND CHANGE
REQUESTS BE DOCUMENTED AND MONITORED
During the design phase these functions are processed through the Engineering Roundtable. During large
project Contracted construction, Change Orders are processed through Supply Chain. On smaller in-
house construction projects, changes are agreed upon at the Project Eneginer/Project Manager, and are
documented in the As-Built process.
The undersigned acknowledge they have reviewed the Transmission NERC Low
Priority Ratings Mitigation Business Case Justification Narrative and agree with the
approach it presents. Significant changes to this will be coordinated with and
approved by the undersigned or their designated representatives.

Signature: Date:
Print Name:
Title:
Role: Business Case Owner

Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Template Version: 05/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 163 of 414
Tribal Permits & Settlements
Business Case Justification Narrative Page 1 of 7
EXECUTIVE SUMMARY

This business case is driven by compliance – the legal requirement to obtain and maintain permits/leases for
Avista’s facilities located on Tribal reservations. Land ownership on Tribal reservations is complex. Much of
the land is held in trust by the federal government on behalf of either Tribes or individual Tribal members.
Permits for Avista’s transmission and distribution facilities were originally obtained pursuant to 25 CFR 169.
Business leases required for substations are obtained pursuant to 25 CFR 162. However, the federal
regulations do not typically allow for perpetual easements. Rather, permits/leases can be issued up to 50
years and then these permits need to be renewed. The majority of Avista’s permits have reached the 50
year expiration and need to be renewed. In addition, new facilities placed on Trust lands need new permits.
In order to acquire a renewed or new permit, a time-consuming federal regulatory process needs to be
followed and permission needs to be obtained from the Tribe and/or the majority of individual Tribal
landowners who have an interest in the relevant parcel of land. The permit is issued by the Bureau of Indian
Affairs after they determine all steps of the process have been achieved. Most of the land on Reservations
is divided into parcels of 80 acres or less. Therefore, a transmission or distribution line usually crosses
numerous parcels of land – each of which requires its own permit.

Avista has facilities on the following Tribal reservations: Spokane, Colville, Nez Perce, Coeur d’Alene,
Flathead, and Kalispel trust lands in Airway Heights. Avista maintains approximately 82 miles of transmission
lines on Tribal trust lands. Over the last 10 years, we have renewed permits on the Coeur d’Alene, Flathead,
and Nez Perce reservations. The current focus is renewals on the Spokane and Colville Reservations.
Approximately 300 new permits are needed on the Spokane Reservation and 130 on the Colville Reservation.

Failure to obtain necessary new permits and maintain existing permits would put us in immediate violation of
Federal Law. Without a valid permit, the Bureau of Indian Affairs would require us to remove our facilities
from Tribal trust lands. Avista has an obligation to serve its customers on these reservations. To ensure
Avista can serve its customers and transmit power on and across Tribal reservations, we need to complete
the process of renewing permits that have and/or are expiring.

VERSION HISTORY
Version Author Description Date Notes
Draft Toni Pessemier Initial draft of original business case 7/8/20
1.0 Updated Approval Status Full amount approved
1.1 Budget change
2.0

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 164 of 414
Tribal Permits & Settlements
Business Case Justification Narrative Page 2 of 7
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed? Avista
has a federal regulatory requirement to obtain and maintain permits/leases for
its facilities located on Tribal reservations, specifically for the land held in trust
by the Federal government on behalf of either Tribes or individual Tribal
members (“trust lands”). Permits for Avista’s transmission and distribution
facilities were originally obtained from the Bureau of Indian Affairs pursuant to
25 CFR 169. Business leases required for substations are obtained from the
BIA pursuant to 25 CFR 162. The Federal regulations do not allow for perpetual
easements. Rather, permits/leases were issued up to 50 years. The majority
of Avista’s permits on Tribal reservations have reached the 50 year expiration
and need to be renewed.
1.2 Discuss the major drivers of the business case – Mandatory and
Compliance – Avista needs to obtain and maintain active permits for all of its
encroachments on Trust lands on Tribal reservations. Avista has facilities on the
following reservations: Spokane, Colville, Nez Perce, Coeur d’Alene, Flathead,
and Kalispel trust lands in Airway Heights. Avista maintains approximately 82
miles of transmission lines on Trust lands and extensive distribution systems.
To-date, we have renewed permits on the Nez Perce, Coeur d’Alene and
Flathead reservations. Avista’s current focus is to renew permits for facilities on
the Spokane and Colville Reservations.

Requested Spend Amount $1,250,000
Requested Spend Time Period 5+ years
Requesting Organization/Department American Indian Relations
Business Case Owner | Sponsor Toni Pessemier /Jason Thackston
|
Sponsor Organization/Department Energy Resources
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 165 of 414
Tribal Permits & Settlements
Business Case Justification Narrative Page 3 of 7
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred Avista is the only electric provider on the Spokane
Reservation and is the electric provider in the Inchelium area of the Colville
Reservation. Avista has an obligation to serve its customers. Approximately
300 permits are needed on the Spokane Reservation and 130 on the Colville
Reservation. To ensure Avista can continue to serve its customers, and transmit
power to serve customers on and off the reservations, we need to continue the
process of renewing permits that have and/or are expiring. Avista does not have
the ability to condemn on Tribal trust lands. If Avista is not actively pursuing
these renewals, we would be in violation of Federal law, and the Bureau of
Indian Affairs could demand that we immediately remove our facilities from
Tribal trust lands. There are examples across the United States where
businesses have been required to remove their facilities when permits have
expired. Although Avista has now renewed many of the transmission related
permits for 20-50 years, it has been estimated that it would cost at least $61
million to relocate all transmission lines off of Tribal land. Because of our
obligation to serve, we need to continue obtaining the required permits for
distribution facilities on the reservations.

1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above. Over the last 10 years, Avista has successfully delivered
on the objectives and renewed all of the expired permits for facilities on the Nez
Perce, Coeur d’Alene and Flathead reservations so we have a successful track
record and are extensively familiar with the process and estimated costs.
However, each Tribe, reservation, and Tribal member is unique so costs can
vary depending on individual negotiations and resolutions.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.

Continue the process to obtain renewed permits for Avista’s facilities located on Trust
lands on Tribal reservations which are required by law to transmit power and continue
serving our customers. Relocating transmission lines would include longer distances
and the risk of obtaining satisfactory easements on non-Tribal land. For distribution
assets on Trust lands, there is no immediate viable option, due to obligation to serve.

Option Capital Cost Start Complete
Continue to negotiate permits/leases as required 250,000 annually 01 2021 12 2025
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 166 of 414
Tribal Permits & Settlements
Business Case Justification Narrative Page 4 of 7
Do nothing, - not in compliance with federal
regulations and leads to next alternative
$0
Relocate transmission lines off of Tribal land $61,190,000 01 2021 12 2023
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The 250,000 is a placeholder for permitting costs which has run historically:
Project Description 2017 2018 2019
2015 CDA 230kV TransPermits 5,777 5,311 4,832
2015 Colville Tribe DistPermit 103,660 43,792 84,971
2015 CSKT 230kV Tran Permits 2,963 63,816 2015 NezPerce 230kV T-Permits (4,952) 2015 Spokane Tribe DistPermits 62,870 73,911 77,144
2015 SpokaneTribe 115kV Permit 38,677 103,083 205,060
2016 ID Dist Tribal Permits 4,823 2017 Nez Perce Dist Permits 177,710 39,944 26,256
2020 CDA 230kV TransPermits 502
2020 Colville Tribe DistPermit 14,961
2020 Nez Perce Dist Permits 2,228
2020 Spokane Tribe DistPermits 2,919
Kamiah Nez Perce 115kV Easmt 23,491
Grand Total 415,020 329,857 418,873
Costs can vary depending on the Tribe, Bureau of Indian Affairs personnel on the
reservation, and individual Tribal members when trying to reach a settlement.
Additionally the federal regulations were updated in 2017 and the costs associated with
the renewal process (e,g, individual surveys, appraisal reports, process to obtain consent
from landowners) have the potential to increase.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
The costs are associated with following 25 CFR 169 and 162 regulatory
processes, and negotiating settlements with Tribe and/or individual Tribal
members as needed. The objective is to renew all of the remaining expiring
permits. Avista maintains a Native American Relations department for the
express purpose of working closely with Tribes on a variety of issues. The
annual O&M expenditure for this department is approximately $300,000. The
Tribal Rights of Way Specialist devotes 90% of her time to this capital business
case.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
By renewing the permits, transmission and distribution engineering will not need
to evaluate options and costs associated with relocating our facilities.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 167 of 414
Tribal Permits & Settlements
Business Case Justification Narrative Page 5 of 7
Operations staff will have rights for ingress and egress to maintain our facilities
and service to customers will not be negatively impacted.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative. See 2.0

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
This work is ongoing. Transfer to plant is reviewed quarterly. When permits
have been obtained, related costs can be transferred.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Being able to serve our customers is critical and our customers trust we will do so.
Obtaining the required permits allows us to demonstrate our focus on compliance.
Avista’s commitment to Tribal relations demonstrates accomplishing this in a
collaborative manner.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project Costs are directly associated with
compliance and adhering to federal law and regulations 25 CFR 169 and 162.
When settlement discussions are necessary to obtain a permit, each situation
and scenario is evaluated for possible alternatives and related costs. In all
cases to-date, the settlement costs have been lower than alternatives such as
relocating facilities.

2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case

2.8.2 Identify any related Business Cases

3.1 Steering Committee or Advisory Group Information
There is no specific Steering Committee for this Business Case. The Advisory
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 168 of 414
Tribal Permits & Settlements
Business Case Justification Narrative Page 6 of 7
Group is the American Indian Relations department in consultation with others
including the Realty Department, Legal, District Managers, Transmission and
Distribution Engineers as needed.
3.2 Provide and discuss the governance processes and people that will
provide oversight American Indian Relations department is responsible for
day to day activities. The Tribal R/W specialist works with other Real Estate
representatives and utilizes multiple systems. The Sr. VP of Energy Resources
provides oversight along with VP General Counsel and VP Chief Regulatory
Counsel.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored Decision making will occur as outlined in 3.2.
Change requests and documentation will be initiated and monitored by
American Indian Relations with support from Financial Planning & Analysis
Operations Analytics Manager.

The undersigned acknowledge they have reviewed the Tribal Permits and
Settlements Business Case and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.

Signature: Date: 7/9/20
Print Name: Toni Pessemier
Title: American Indian Relations Advisor
Role: Business Case Owner

Signature: Date:
Print Name: Jason Thackston
Title: Sr. VP Energy Resources
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

7/10/20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 169 of 414
Tribal Permits & Settlements
Business Case Justification Narrative Page 7 of 7

Template Version: 05/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 170 of 414
Use Permits
Business Case Justification Narrative Page 1 of 6
EXECUTIVE SUMMARY

Avista owns and maintains electric transmission, distribution, and natural gas facilities which cross
public lands managed by a variety of state, federal and local agencies, as well as entities who own
extensive tracts, such as railroads. Traditionally, we have secured long-term rights-of-way permits
for these facilities, but have been required to renew them through an annual billing process. The
cost of renewing these permits continues to increase each year, ranging from 3% to 10% annually,
depending on the agency, thereby increasing annual O&M expenses to the company and our
customers. This business case proposal is to secure long-term agreements with lump-sum
payments in order to reduce overall expenses related to labor of tracking, research, and processing
these annual permits. In some cases, we have been able to negotiate a lower annualized cost over
the term of the permit by paying a lump sum up front. In either case, we reduce costs to the
company and our customers. Making long-term lump sum payments allows us to capitalize these
costs, as the permit is a long-term asset.

Without capital funding, we will continue to incur increasing annual permitting fees and related
internal costs as an O&M expense. These costs affect all customers, electric and gas, in the entire
Avista service territory.

VERSION HISTORY
Version Author Description Date Notes
Draft Rod Price Initial draft of original business case 6/30/2020
1.0 Rod Price Completed business case 7/28/2020
1.1
2.0
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 171 of 414
Use Permits
Business Case Justification Narrative Page 2 of 6
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Avista owns and maintains electric transmission, distribution, and natural gas facilities
which cross public lands managed by a variety of state, federal and local agencies, as
well as entities who own extensive tracts, such as railroads. As these rights of way
ei ee, ee bee aig aa iceaig fee, eadig iceaed O&M
expenses associated with both the permit costs and the labor to process them.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
This business case is directly tied to Reliability, Mandatory & Compliance, Performance
& Capacity, and Failed Plant & Operations. In order to legally construct, maintain and
upgrade our facilities on agency owned lands, we must acquire and renew rights of way
permits. While we would continue doing this work without this business case, the main
benefits to the customer are being able to negotiate lower fixed permit costs through
lump sum payments, as well as securing long term permits which will allow us to
maintain reliability in our infrastructure. In addition, we will reduce our labor costs for
managing these permits. We also reduce the risk of annual permits not being renewed,
or being modified unilaterally.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Right of way permitting on agency-owned lands is an ongoing and necessary scope of
work. We will continue doing this work without an approved capital business case.
This business case is based on our potential of saving the company and our customers
money over the long term by capitalizing permit fees and negotiating lower costs
through long term, lump sum payments.
Requested Spend Amount $50,000
Requested Spend Time Period annually.
Requesting Organization/Department V08 / Real Estate
Business Case Owner | Sponsor Rod Price | Bruce Howard
Sponsor Organization/Department A04 / Environmental Affairs
Phase Execution
Category Productivity
Driver Performance & Capacity
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 172 of 414
Use Permits
Business Case Justification Narrative Page 3 of 6
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Annual tracking of all agency permits costs, and then completing a comparative analysis
against past years.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.

We propose that through this business case, we will work with agencies to negotiate lump
sum payments for our rights of way permits, thereby securing long-term, and lower fixed
costs associated with acquiring and renewing these permits.
Option Capital Cost Start Complete
Capitalize and negotiate lump sum payments $50,000 01/2021 12/2021
Keep paying annually increasing permit fees
through O&M dollars
$0 01/2021 12/2021
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request

Review of past years permit costs, we feel that $50k annually will be enough to cover
renewals.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 173 of 414
Use Permits
Business Case Justification Narrative Page 4 of 6
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
Starting in 2021, the capital cost amount will be used primarily to cover the costs of
agency right of way fees. There should be minimal labor costs associated with this
activity, and the annual labor costs should reduce slightly if the number of annual
renewals is reduced through the negotiation of long-term permits.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
By taking annually renewing permits, and converting them to longer-term permits, we
should positively impact the labor associated with processing annual permits.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The only other alternative is to continue processing annual permits and paying the
annually increasing fees, which is a charge to company O&M.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
This is a program and the work is completed throughout the year based on when agency
permits are received. They will become used and useful once the fully executed permit
is in place.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
O ed iee i aiged ih Aia ii f deieig eiabe e
to our customers at the most affordable price we can deliver. Rights of way permits are
required for Avista to construct, maintain, and upgrade electric and gas infrastructure
on agency owned land. Without these rights of way, we cannot meet our objectives.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Without this business case, we will still be required to do the same work, thereby
continuing to pay increasing O&M costs. This program proposal is prudent, as it will
help mitigate long-term expenses for the company and our customers.
2.8 Supplemental Information

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 174 of 414
Use Permits
Business Case Justification Narrative Page 5 of 6
2.8.1 Identify customers and stakeholders that interface with the business case
Electric and Gas operations are impacted by this business case as we are securing
igh f a f hee faciiie. Aia eecic ad ga ce ae a
affected by our ability to provide reliable and low-cost power.
2.8.2 Identify any related Business Cases

3.1 Steering Committee or Advisory Group Information
This program will be monitored by the Real Estate Manager, Sr. Director of
Environmental Affairs, and Department Financial & Budget Specialist.
3.2 Provide and discuss the governance processes and people that will
provide oversight
This program will be monitored by the Real Estate Manager, Sr. Director of
Environmental Affairs, and Department Financial & Budget Specialist. We will
evaluate the annual costs and savings to ensure the program is on track.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The undersigned acknowledge they have reviewed the Use Permits and agree with
the approach it presents. Significant changes to this will be coordinated with and
approved by the undersigned or their designated representatives.

Signature: Date:
Print Name: Rod Price
Title: Mgr Real Estate
Role: Business Case Owner

Signature: Date:
Print Name: Bruce Howard
Title: Sr Dir Environmental Affairs
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
07/29/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 175 of 414
Use Permits
Business Case Justification Narrative Page 6 of 6

Template Version: 05/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 176 of 414
West Plains New 230kV Substation
Business Case Justification Narrative Page 1 of 7
EXECUTIVE SUMMARY
This section is reserved to provide a brief description of the business case and high level summary of the projects or
programs included. Please limit to no more than 2 paragraphs. Components that should be included: 1) a synopsis of
the problem, 2) the service code and jurisdiction of customers impacted, 3) the recommended solution, 4) the cost of
the solution, 5) how the solution will benefit customers identified, 6) the significance of the timeline and 7) the risks of
not approving this business case.
<< Both the Executive Summary and Version History should fit into one page >>

The 2010 Spokane Area Regional Assessment identified specific transmission system
performance issues in the five and the ten-year planning horizons. Many of the issues are caused
by inadequate 230/115 kV transformation in the area.

Additionally, the distribution stations in this area are connected to radial transmission lines.
Manual operator action is necessary to restore service to customers following automatic circuit
breaker operation to isolate a fault. This business case is important to customers because it will
more easily allow planned outages to occur that will enable maintenance and replacement of
substation equipment before it causes unplanned outages and reduces the electric system
reliability that customers have become accustomed to receiving.

Service: ED – Electric Direct
Jurisdiction: AN – Allocated North
Engineering Roundtable Request Number: ERT_2017-54
Cost of Solution: $9,000,000

VERSION HISTORY
Version Author Description Date Notes
1.0 Ken Sweigart /
Jeff Schlect Initial Version 04/14/2017 Initial Version
2.0 Karen Kusel /
Glenn Madden Update to 2020 Template 6/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 177 of 414
West Plains New 230kV Substation
Business Case Justification Narrative Page 2 of 7
GENERAL INFORMATION
1 BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
The 2010 Spokane Area Regional Assessment identified specific transmission system
performance issues in the five and the ten-year planning horizons. Many of the issues are
caused by inadequate 230/115 kV transformation in the area. Presently there are four
substations in the Spokane Area providing 230/115 kV transformation: Beacon (500 MVA),
Bell (250 MVA), Boulder (500 MVA), and Westside (250 MVA). The concept of constructing
the West Plains New 230kV Substation is to add 500 MVA of transformation capacity. This
project is required to mitigate NERC TPL-001-4 standard violations for P2 and P6 events.
Additionally, the distribution stations in this area are connected to radial transmission lines.
Manual operator action is necessary to restore service to customers following automatic
circuit breaker operation to isolate a fault. Currently the Sunset-Westside 115kV
Transmission Line includes the South Fairchild 115 kV Tap, to which the Four Lakes 115
kV Tap is connected, leaving a total exposure of 31 miles for all customers served by the
Cheney, Fairchild South, Four Lakes, Hayford and Hallett & White substations.
There are a minimum of seven (7) thermal or voltage limit violations identified to take place
within the 10-year planning horizon if this project is not constructed. Additional supporting
documentation may be found in the Garden Springs Integration Project Feasibility Study
report authored by John Gross.
1.1 What is the current or potential problem that is being addressed?
This project is required to mitigate NERC TPL-001-4 standard violations for P2 and P6
events.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer Service
Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset Condition, or
Failed Plant & Operations) and the benefits to the customer
There are a minimum of seven (7) thermal or voltage limit violations identified to take place
within the 10-year planning horizon if this project is not constructed.
Requested Spend Amount $9,000,000
Requested Spend Time Period 2 Years
Requesting Organization/Department Transmission / System Planning
Business Case Owner | Sponsor Glenn Madden | Josh Diluciano
Sponsor Organization/Department T&D
Phase Initiation
Category Project
Driver Mandatory & Compliance
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 178 of 414
West Plains New 230kV Substation
Business Case Justification Narrative Page 3 of 7
1.3 Identify why this work is needed now and what risks there are if not approved or is
deferred
This project is required to mitigate NERC TPL-001-4 standard violations for P2 and P6
events.
1.4 Identify any measures that can be used to determine whether the investment would
successfully deliver on the objectives and address the need listed above.
Future System Planning Assessment reports.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information; do not attach]
System Planning Assessments located on the System Planning Department Sharepoint
site.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.
Not Applicable.
2 PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]
Alternative 1 – Do Nothing / Status Quo:
This alternative is not recommended because it does not mitigate the expected capacity
constraints, and does not comply with applicable NERC transmission planning standards.
Operating Procedures may be used to defer some system deficiencies.

Alternative 2 – Construct the West Plains New 230kV Substation:
This alternative constructs a new 230 kV station in the West Plains area. The 230 kV station
(Phase 2) would be sourced through a new 230 kV transmission line interconnection with the
Bonneville Power Administration (BPA) and/or with connections to Westside Substation. The
115 kV portion of the new station (Phase 1) is a part of the West Plains Transmission
Reinforcement Plan which addresses reliability issues and provides operational flexibility. All
system deficiencies identified will be mitigated.

Alternative 3 – Airway Heights-Westside 115 kV Transmission Line:
Constructing a new 9.5-mile 115 kV transmission line from Airway Heights to Westside was
considered as an alternative. Outages at the Westside station, including the P6 outage of
both 230/115 kV transformers and P7 outage of the 230 kV double circuit into Westside,
continue to cause performance issues. A new 230 kV source to the Spokane area provides
a more robust long term solution.

Alternative 4 – Garden Springs 230 kV Station with 230 kV Transmission Line to Westside:
Constructing a 7.9-mile 230 kV transmission line from Westside to a new Garden Springs
station was considered instead of the proposed Bluebird-Garden Springs 230 kV
Transmission Line interconnection with BPA. Performance issues are not fully mitigated with
this alternative. Specifically, the P7 outage of the 230 kV double circuit into Westside
continues to be an issue and right-of-way events between Westside and Garden Springs
stations do not meet performance criteria.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 179 of 414
West Plains New 230kV Substation
Business Case Justification Narrative Page 4 of 7

Alternative 5 – No New 230 kV Infrastructure – 115 kV Transmission Line Rebuilds:
Rebuilding several 115 kV transmission lines in the Spokane area instead of constructing any
new 230 kV infrastructure was considered. The alternative does not provide the necessary
redundancy but instead creates a higher dependence upon existing facilities.

Option Capital Cost Start Complete
Construct the West Plains New 230kV Substation
(2 Phases)
$33M 01 2022 12 2028
Alternative 1 – Do Nothing / Status Quo $0M
Alternative 3 – Airway Heights-Westside 115 kV
Transmission Line

Alternative 4 – Garden Springs 230 kV Station with
230 kV Transmission Line to Westside

Alternative 5 – No New 230 kV Infrastructure – 115
kV Transmission Line Rebuilds

2.1 Describe what metrics, data, analysis or information was considered when preparing
this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
System Planning Assessments.
2.2 Discuss how the requested capital cost amount will be spent in the current year (or
future years if a multi-year or ongoing initiative). (i.e. what are the expected functions,
processes or deliverables that will result from the capital spend?). Include any known or
estimated reductions to O&M as a result of this investment.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing reductions
to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
2022 - $9,000,000 (Construction may spread into 2023)
O&M will increase with the addition of this new substation due to inspection and
maintenance on the substation, transmission and distribution equipment.
2.3 Outline any business functions and processes that may be impacted (and how) by
the business case for it to be successfully implemented.
[For example, how will the outcome of this business case impact other parts of the business?]
System Operations will have improved functionality of the electric system.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 180 of 414
West Plains New 230kV Substation
Business Case Justification Narrative Page 5 of 7
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation
strategies for each alternative.
See Section 2.0 for alternative discussion.
2.5 Include a timeline of when this work will be started and completed. Describe when
the investments become used and useful to the customer. spend, and transfers to
plant by year.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful. (i.e. if
transfer to plant occurs monthly, quarterly or upon project completion).]
Design and Construction are scheduled for 2022. Transfers to Plant will occur when the
substation is commissioned and in-service.
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives
and mission statement of the organization.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]
Mission: We improve our customers’ lives through innovative energy solutions.
Vision: Better energy for life
Additional transformation capabilities in the area will alleviate the threat of customer
outages.
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please explain
how the investment prudency will be reviewed and re-evaluated throughout the
project
The scope for the project, which is to increase transformation capacity in the Spokane
station is the least cost option that provides the needed functionality. Adhering to the scope
and project objectives will be reviewed regularly by the project team including the project
engineer and the project manager.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Electrical Engineering, Generation Production/Substation Support, Transmission
Operations and System Planning and Operations
2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]
Westside 230/115kV Station Rebuild also provides stability to the Spokane area.
3 MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a part
of your departmental prioritization process.]
The Engineering Roundtable initially is designated as the Steering Committee for this
project, with a more project-specific Steering Committee to be potentially identified at a
later date.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 181 of 414
West Plains New 230kV Substation
Business Case Justification Narrative Page 6 of 7
3.2 Provide and discuss the governance processes and people that will provide
oversight
Engineering Roundtable meets several times a year to analyze current and future projects.
3.3 How will decision-making, prioritization, and change requests be documented and
monitored
Project folders are saved to Engineering shared drives and Businesss Case Funds
Requests are available on the Finance sharepoint site

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 182 of 414
West Plains New 230kV Substation
Business Case Justification Narrative Page 7 of 7
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the West Plains New 230kV Substation
and agree with the approach it presents. Significant changes to this will be coordinated with
and approved by the undersigned or their designated representatives.

Signature: Date:
Print Name: Glenn Madden
Title: Manager, Substation Engineering
Role: Business Case Owner

Signature: Date:
Print Name: Josh DiLuciano
Title: Director, Electrical Engineering
Role: Business Case Sponsor

Signature: Date:
Print Name: Damon Fisher
Title: Principle Engineer
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 183 of 414
Westside 230/115kV Station Rebuild
Business Case Justification Narrative Page 1 of 7
EXECUTIVE SUMMARY
This section is reserved to provide a brief description of the business case and high level summary of the projects or
programs included. Please limit to no more than 2 paragraphs. Components that should be included: 1) a synopsis of
the problem, 2) the service code and jurisdiction of customers impacted, 3) the recommended solution, 4) the cost of
the solution, 5) how the solution will benefit customers identified, 6) the significance of the timeline and 7) the risks of
not approving this business case.
<< Both the Executive Summary and Version History should fit into one page >>

The existing Westside #1 230/115 kV transformer exceeds its applicable facility rating for the P1 event of
the Westside #2 230/115 kV transformer. System performance analysis indicates an inability of the system
to meet the performance requirements in Table 1 of NERC TPL-001-4 in scenarios representing 2017
Heavy Summer for P1 events. While Avista intends to avoid proactively shedding customer load, an
operating procedure to shed non-consequential load can be used until 2021 to mitigate system deficiencies
(non-consequential load shedding is considered acceptable through the 84 month implementation of TPL-
001-4).
Westside Transformer Replacement is the recommended solution. Replace the existing Westside
transformers with 250 MVA rated transformers and reconstruct both the 230 kV and 115 kV buses at the
station to double bus, double breaker. All associated system deficiencies will be mitigated.

Service: ED – Electric Direct
Jurisdiction: AN – Allocated North
Engineering Roundtable Request Number: ERT_2017-47
Cost of Solution: $32,000,000

VERSION HISTORY
Version Author Description Date Notes
1.0 Ken Sweigart Initial Version 4/14/2017 Initial Version
2.0 Karen Kusel /
Glenn Madden Update to 2020 Template 6/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 184 of 414
Westside 230/115kV Station Rebuild
Business Case Justification Narrative Page 2 of 7
GENERAL INFORMATION
1 BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
The existing Westside #1 230/115 kV transformer exceeds its applicable facility rating for
the P1 event of the Westside #2 230/115 kV transformer. System performance analysis
indicates an inability of the system to meet the performance requirements in Table 1 of
NERC TPL-001-4 in scenarios representing 2017 Heavy Summer for P1 events. While
Avista intends to avoid proactively shedding customer load, an operating procedure to shed
non-consequential load can be used until 2021 to mitigate system deficiencies (non-
consequential load shedding is considered acceptable through the 84 month
implementation of TPL-001-4).
1.1 What is the current or potential problem that is being addressed?
System performance analysis indicates an inability of the system to meet the performance
requirements in Table 1 of NERC TPL-001-4 in scenarios representing 2017 Heavy
Summer for P1 events.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer Service
Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset Condition, or
Failed Plant & Operations) and the benefits to the customer
Mandatory & Complaince - All associated system deficiencies will be mitigated with the completion
of this project.
1.3 Identify why this work is needed now and what risks there are if not approved or is
deferred
While Avista intends to avoid proactively shedding customer load, an operating procedure to shed
non-consequential load can be used until 2021 to mitigate system deficiencies (non-consequential
load shedding is considered acceptable through the 84 month implementation of TPL-001-4).
1.4 Identify any measures that can be used to determine whether the investment would
successfully deliver on the objectives and address the need listed above.
Future System Planning Assessments which show mitigation of all prior deficiencies.
Requested Spend Amount $32,000,000
Requested Spend Time Period 15 Years
Requesting Organization/Department Transmission/System Planning
Business Case Owner | Sponsor Glenn Madden | Josh DiLuciano
Sponsor Organization/Department T&D
Phase Execution
Category Project
Driver Mandatory & Compliance
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 185 of 414
Westside 230/115kV Station Rebuild
Business Case Justification Narrative Page 3 of 7
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information; do not attach]
System Planning Assessments.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for replacement.
Not Applicable.
2 PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]
Westside Transformer Replacement is the recommended solution. Replace the existing
Westside transformers with 250 MVA rated transformers and reconstruct both the 230
kV and 115 kV buses at the station to double bus, double breaker. All associated system
deficiencies will be mitigated.
Project scope includes the following:
Phase 1: Replace the existing Westside #1 230/115 kV transformer and construct necessary
bus work and breaker positions. $11 million, energize 2018
Phase 2: Continue bus work and breaker replacement: $8 million, energize 2019
Phase 3: Replace the existing Westside #2 230/115 kV transformer and complete bus work
to single bus configuration: $6 million, energize 2020
Phase 4: Complete bus work to double bus, double breaker on both the 230 kV and 115 kV
buses: $7 million, energize 2022

Alternative 1 - Status Quo/Do Nothing: This alternative is not recommended because it does
not mitigate the expected capacity constraints and does not adhere to NERC transmission
planning standards.
Solution/Alternative 2 - Westside Transformer Replacement: Replace the existing Westside
transformers with 250 MVA rated transformers and reconstruct both the 230 kV and 115 kV
buses at the station to double bus, double breaker. All associated system deficiencies will be
mitigated.
Alternative 3- Garden Springs 230kV Station Integration: The Garden Springs 230 kV
Station Integration project includes the installation of new 230/115 kV transformation in the
Spokane area. The additional transformation will offload the Westside #1 and #2 230/115
transformers. In the future, the Garden Springs 230 kV Station Integration project will be
necessary in addition to the Westside Transformer Replacement project.
Alternative 4 - Replace Westside Transformers without Station Rebuild: Replacing the
existing Westside transformers to 250 MVA rated transformers will mitigate the transformer
overload system deficiencies but will create a short circuit breaker rating exceedance.
Additional P2 bus outage system deficiencies will exist.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 186 of 414
Westside 230/115kV Station Rebuild
Business Case Justification Narrative Page 4 of 7
Option Capital Cost Start Complete
[Recommended Solution] Westside Transformer
Replacement
$32M 2015 2022
Alternative #1 Status Quo $0M
Alternative #3 Garden Springs 230kV Station
Integration

Alternative #4 Replace Westside Transformers
without Station Rebuild

2.1 Describe what metrics, data, analysis or information was considered when preparing
this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
System Planning Assessments.
2.2 Discuss how the requested capital cost amount will be spent in the current year (or
future years if a multi-year or ongoing initiative). (i.e. what are the expected functions,
processes or deliverables that will result from the capital spend?). Include any known or
estimated reductions to O&M as a result of this investment.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing
reductions to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
2020 – $3,000,000
2021 - $3,500,000
2022 - $2,800,000
2023 - $2,000,000
2024 – $1,000,000
O&M costs will be comparible to what they were before this project.
2.3 Outline any business functions and processes that may be impacted (and how) by
the business case for it to be successfully implemented.
[For example, how will the outcome of this business case impact other parts of the business?]
System Operations will have improved functionality of the electric system.
2.4 Discuss the alternatives that were considered and any tangible risks and mitigation
strategies for each alternative.
See Section 2.0 for alternative discussion.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 187 of 414
Westside 230/115kV Station Rebuild
Business Case Justification Narrative Page 5 of 7
2.5 Include a timeline of when this work will be started and completed. Describe when
the investments become used and useful to the customer. spend, and transfers to
plant by year.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful.
(i.e. if transfer to plant occurs monthly, quarterly or upon project completion).]
Construction will continue through 2024. Transfers to Plant will be at the close of each
Phase.
2.6 Discuss how the proposed investment aligns with strategic vision, goals, objectives
and mission statement of the organization.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]
Mission: We improve our customers’ lives through innovative energy solutions.
Vision: Better energy for life
The completion of this project leads directly to a dimished threat of customer outages.
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please explain
how the investment prudency will be reviewed and re-evaluated throughout the
project
The scope for the project, which is to increase transformation capacity in the Spokane area
is the least cost option that provides the needed functionality. Adhering to the scope and
project objectives will be reviewed regularly by the project team including the project
engineer and the project manager.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Electrical Engineering, Generation Production/Substation Support, Transmission
Operations and System Planning and Operations
2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]
Not Applicable.
3 MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a part
of your departmental prioritization process.]
• Project Engineer/Project Manager (PE/PM)- Dana Gerbing/Zachary Curry
• Engineering Roundtable Committee
The assigned PE/PM holds stakeholder meetings to develop/confirm scope, schedule
and costs. Also meets at time of pre-construction. Other meetings held as necessary.
This project has also been reviewed by the Engineering Roundtable.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 188 of 414
Westside 230/115kV Station Rebuild
Business Case Justification Narrative Page 6 of 7
3.2 Provide and discuss the governance processes and people that will provide
oversight
Engineering Roundtable meets several times a year to analyze current and future projects.
3.3 How will decision-making, prioritization, and change requests be documented and
monitored
Project folders are saved to Engineering shared drives and Businesss Case Funds
Requests are available on the Finance sharepoint site

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 189 of 414
Westside 230/115kV Station Rebuild
Business Case Justification Narrative Page 7 of 7
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Westside 230/115kV Station
Rebuild and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.

Signature: Date:
Print Name: Glenn Madden
Title: Manager, Substation Engineering
Role: Business Case Owner

Signature: Date:
Print Name: Josh DiLuciano
Title: Director, Electrical Engineering
Role: Business Case Sponsor

Signature: Date:
Print Name: Damon Fisher
Title: Principle Engineer
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 190 of 414
Spokane Valley Transmission Reinforcement Project
Business Case Justification Narrative Page 1 of 7
EXECUTIVE SUMMARY
This section is reserved to provide a brief description of the business case and high level summary of the
projects or programs included. Please limit to no more than 2 paragraphs. Components that should be
included: 1) a synopsis of the problem, 2) the service code and jurisdiction of customers impacted, 3) the
recommended solution, 4) the cost of the solution, 5) how the solution will benefit customers identified, 6) the
significance of the timeline and 7) the risks of not approving this business case.
<< Both the Executive Summary and Version History should fit into one page >>

Local load growth, specifically at the local paper mill occurring in 2007 is a strong driver for a
transmission system expansion in the Spokane Valley area. Additionally, there are NERC TPL-
001-4 events not meeting performance requirements that are mitigated by completing the project.
The worst performance issue mitigated by the completion of the project is the NERC TPL-001-4
category P2.4 event of an internal Breaker Fault (Bus-tie Breaker) on A717 at Boulder Station.
System performance analysis indicates an inability of the System to meet the performance
requirements in Table 1 of NERC TPL-001-4 in scenarios representing 2017 Heavy Summer
Scenarios for the P2 contingency. An Operating Procedure to open Boulder A717 can be used to
mitigate the system deficiencies. Portions of the project have been completed prior to 2016.

The remaining portions of the Spokane Valley Transmission Reinforcement project are
constructing the Irvin Substation and rebuilding a portion of the Beacon – Boulder #2 115 kV
Transmission Line. All system defeciencies are mitigated and the desired operational flexibility to
serve large industrial customers is realized. This business case is important to customers
because its completion likely allows customers to continue to receive electrical service with the
reliability that they have grown accustom to receiving.

Service: ED – Electric Direct
Jurisdiction: AN – Allocated North
Engineering Roundtable Request Number: ERT_2017-48
Cost of Solution: $19,00,000 (includes completed projects) over $15 years

VERSION HISTORY
Version Author Description Date Notes
1.0 Ken Sweigart Initial Version 4/14/2017 Initial Version
2.0 Karen Kusel /
Glenn Madden Update to 2020 Template 06/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 191 of 414
Spokane Valley Transmission Reinforcement Project
Business Case Justification Narrative Page 2 of 7
GENERAL INFORMATION
1 BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
Completion of this project is required to mitigate a NERC TPL-001-4 system deficiency. The
transmission system in the Spokane Valley currently fails TPL-001-4(P2.4), which is an
internal Breaker Fault (Bus-tie Breaker) on A717 at the Boulder Station. In addition the
system fails the NERC TPL-001-4 P2 Contingency for the 2017 Heavy Summer Scenario.
Completion of this project is required to ensure Avista maintains compliance with NERC
regulations and Avista's planning documents.
1.1 What is the current or potential problem that is being addressed?
Being currently out of compliance of NERC TPL-001-4 and potential breaker faults which
could lead to large customer outages.
1.2 Discuss the major drivers of the business case (Customer Requested,
Customer Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity,
Asset Condition, or Failed Plant & Operations) and the benefits to the customer
The major driver of the business case is Mandatory & Compliance. Completion of this
project is required to ensure Avista maintains compliance with NERC regulations and
Avista's planning documents.
1.3 Identify why this work is needed now and what risks there are if not approved
or is deferred
There are risks to the reliability of electric service with delays to the completion of this
project.
1.4 Identify any measures that can be used to determine whether the investment
would successfully deliver on the objectives and address the need listed
above.
Future System Planning Assessments will show the BES improvements made by
completing this project.
Requested Spend Amount $6,800,000 (Remaining Projects)
Requested Spend Time Period 3 Years
Requesting Organization/Department Transmission/System Planning
Business Case Owner | Sponsor Glenn Madden | Josh Diluciano
Sponsor Organization/Department T&D
Phase Execution
Category Project
Driver Mandatory & Compliance
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 192 of 414
Spokane Valley Transmission Reinforcement Project
Business Case Justification Narrative Page 3 of 7
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information; do not attach]
2016 Avista System Planning Assessment.pdf
Irvin Project Final.pdf
IrvinvSubstationvProject - Rev C.pdf
SP-2009-03 Summary of Work - Irvin Project.pdf
SP-2011-07 2011 Spokane Valley Transmission Reinforcement.pdf
1.5.2 For asset replacement, include graphical or narrative representation of
metrics associated with the current condition of the asset that is proposed
for replacement.
Not Applicable.
2 PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]
Recommendation: Alternative 2, complete the Spokane Valley Transmission Reinforcement
project. Remaining project scope includes the following:
Construct the Irvin Station terminating the Beacon – Boulder #1 and #2, Irvin – IEP, and Irvin
– Opportunity 115 kV transmission lines as a breaker and a half configuration: $5 million.
Rebuild the existing Beacon – Boulder #2 115 kV Transmission Line from Beacon to Millwood
to 795 ACSS conductor: $2 million.
Alternative 1: Status Quo
This alternative is not recommended because it does not mitigate the expected capacity
constraints, and does not adhere to NERC Compliance regulations.
Alternative 2: Revert to before the CDA Reconfiguration Project
Revert the system to the condition prior to the Coeur d’Alene Reconfiguration Project creating
the Boulder-Rathdrum and Post Falls –Ramsey 115 kV transmission lines. Operational
concerns will present themselves specifically with a P2.1 planned outage followed by a forced
Pl event in the Coeur d’Alene area. (The P2.1 and Pl event combination is not a TPL-001-4
event.) Operational flexibility constrained by large industrial customers will continue to
persist.
Option Capital Cost Start Complete
Complete Project (Irvin Substation and BEA-
BLD #2 115kv Line Rebuild)
$6.8M 01 2020 12 2021
Alt 1: Status Quo $0M
Alt 3: Revert to before the CDA
Reconfiguration Project

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 193 of 414
Spokane Valley Transmission Reinforcement Project
Business Case Justification Narrative Page 4 of 7
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
Load Growth, changes to compliance standards and System Planning Assessments were
considered.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital
spend?). Include any known or estimated reductions to O&M as a result of
this investment.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing
reductions to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
2020 - $3.9M
2021 - $2.9M
O&M will be reduced by replacing the transmission line which will help offset the cost of
O&M of inspection and maintenance requirements of the substation and its equipment.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
[For example, how will the outcome of this business case impact other parts of the business?]
System Operations will have improved functionality of the electric system in the Spokane
Valley area.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Status Quo would possibly lead to NERC fines and large customer outages. Reverting to
before the CDA Reconfiguration project would negate the benefits of having completed that
project.
2.5 Include a timeline of when this work will be started and completed. Describe
when the investments become used and useful to the customer. spend, and
transfers to plant by year.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful. (i.e. if
transfer to plant occurs monthly, quarterly or upon project completion).]
Construction at Irvin Substation will continue in the Fall of 2020 and be complete in the
Spring of 2021. The Beacon – Boulder #2 transmission rebuild will be completed in late
2021.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 194 of 414
Spokane Valley Transmission Reinforcement Project
Business Case Justification Narrative Page 5 of 7
Transfers to Plant will occur as the substation and transmission line are deemed in-service
and energized.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]
Mission: We improve our customers’ lives through innovative energy solutions.
Vision: Better energy for life
This project will provide a solid foundation for customer reliability in the Spokane Valley.
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please
explain how the investment prudency will be reviewed and re-evaluated
throughout the project
The scope for the project, which is to increase reliability in the Spokane Valley by creating
the switching station is the least cost option. Adhering to the scope and project objectives
will be reviewed regularly by the project team including the project engineer and the project
manager.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Electrical Engineering, Generation Production/Substation Support, Transmission
Operations and System Planning and Operations
2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]
Not Applicable.
3 MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a part
of your departmental prioritization process.]
• Glenn Madden - Manager, Substation Engineering
• Project Engineer/Project Manager (PE/PM)- Various
The assigned PE/PM holds stakeholder meetings to develop/confirm scope, schedule and
costs. Also meets at time of pre-construction. Other meetings held as necessary.
This project has been reviewed by the Engineering Roundtable.
3.2 Provide and discuss the governance processes and people that will provide
oversight
Engineering Roundtable meets several times a year to analyze current and upcoming
project.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 195 of 414
Spokane Valley Transmission Reinforcement Project
Business Case Justification Narrative Page 6 of 7
3.3 How will decision-making, prioritization, and change requests be documented
and monitored
Project folders are saved to Engineering shared drives and Businesss Case Funds
Requests are available on the Finance sharepoint site.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 196 of 414
Spokane Valley Transmission Reinforcement Project
Business Case Justification Narrative Page 7 of 7
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Spokane Valley Transmission
Reinforcement Project and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Print Name: Glenn Madden
Title: Manager, Substation Engineering
Role: Business Case Owner

Signature: Date:
Print Name: Josh DiLuciano
Title: Director, Electrical Engineering
Role: Business Case Sponsor

Signature: Date:
Print Name: Damon Fisher
Title: Principle Engineer
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 197 of 414
SCADA - SOO and BuCC

Business Case Justification Narrative v1.0 Page 1 of 7
EXECUTIVE SUMMARY
This business case provides for replacement of existing technology, as well as for deployment of new
applications and technology as required to address expanding regulatory and business requirements.
This program (Supervisory Control and Data Acquisition - System Operations Office and Backup Control
Center) replaces and upgrades existing electric and gas control center telecommunications and
computing systems as they reach the end of their useful lives, require increased capacity, or cannot
accommodate necessary equipment upgrades due to existing constraints. Some system upgrades may
be necessitated by other requirements, including NERC reliability standards, federal gas standards,
system growth, and external projects (e.g. Smart Grid). The customers who benefit are all electric and
gas residential, commercial, and industrial customers (CD.AA).
The estimated costs for the upcoming five years are $4.3M. The amount requested is based partially upon
historical spending needs, and partially on known upcoming major projects. Within the program’s yearly
authorized spend amount, specific budgetary items to be implemented are determined based upon requests
by affected stakeholders including System Operations, Distribution Operations, and Power Supply, and are
documented in the Director of Transmission & Distribution System Operations’ annual goals and priorities
list.
There are multiple risks if this program is not adequately funded. The clearest risk would be to public and
personnel safety. The control systems supported by this business case provide real-time visibility,
situational awareness, and control of Avista’s electric and gas systems. Degradation of these capabilities
due to lack of capacity, capability, or aging systems would present increased safety risk. Additionally there
is significant compliance risk. These control systems provide the capabilities required to achieve
compliance with numerous reliability standards and requirements. For the electrical system these include
the NERC standards BAL, COM, CIP, EOP, INT, PER, PRC, TOP, and VAR. For the gas system these
include the PHMSA “Pipeline Safety: Control Room Management/Human Factors” rule (49 CFR Parts 192
and 195.) The expenditure of these funds is necessary to operate Avista’s electric and gas systems in a
safe, reliable, and compliant manner.

VERSION HISTORY
Version Author Description Date Notes
Draft Craig Figart Initial draft of original business case 07.1.2020
1.0 Craig N Figart Final version of 2020 business case 07.17.2020 Updated Executive Summary

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 198 of 414
SCADA - SOO and BuCC

Business Case Justification Narrative v1.0 Page 2 of 7
GENERAL INFORMATION

1. BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
1.1 What is the current or potential problem that is being addressed?
In order to effectively operate the Transmission & Distribution (T&D) Systems, sufficient business
and computing hardware and software is necessary. This business case provides for replacement
of existing technology in alignment with manufacturer product roadmaps for application and
technology lifecycles, as well as for deployment of new applications and technology as required to
address expanding regulatory and business requirements. Technology continues to change and
T&D Systems continue to incorporate improved technology.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Asset Condition is the major driver of the business case. Another driver is Customer Service quality
and reliability. This business case is crucial in a key aspect of Our Vision; “Delivering reliable energy
service…” It is essential in providing sufficient control center technology tools, situational awareness,
and monitor/control capabilities to achieve reliable energy service.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred.
There are multiple risks if this program is not adequately funded. The clearest risk would be to public
and personnel safety. The control systems supported by this business case provide real-time
visibility, situational awareness, and control of Avista’s electric and gas systems. Degradation of
these capabilities due to lack of capacity, capability, or aging systems would present increased safety
risk. Additionally there is significant compliance risk.
These control systems provide the capabilities required to achieve compliance with numerous
reliability standards and requirements. For the electrical system these include the NERC standards
BAL, COM, CIP, EOP, INT, PER, PRC, TOP, and VAR. For the gas system these include the
PHMSA “Pipeline Safety: Control Room Management/Human Factors” rule (49 CFR Parts 192 and
195.)
The expenditure of these funds is necessary to operate Avista’s electric and gas systems in a safe,
reliable, and compliant manner.
Requested Spend Amount $4.3M
Requested Spend Time Period 5 years
Requesting Organization/Department T&D - SCADA/EMS/DMS - System Operations
Business Case Owner | Sponsor Craig N Figart | Mike Magruder
Sponsor Organization/Department Energy Delivery
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 199 of 414
SCADA - SOO and BuCC

Business Case Justification Narrative v1.0 Page 3 of 7
In addition to the risks related to public and personnel safety, compliance risk would be increased
without this investment. Non-compliant operational capabilities and practices would result in
negative audit findings, significant financial penalties, and litigation expenses. Obsolete equipment
would remain in service until failure. Additional capacity for growth may or may not be suitable for
required expansions to meet other needs (e.g. Regulatory, Smart Grid.)
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information; do not attach]
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.

[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]

Option Capital Cost Start Complete
Fully Funded “SCADA – SOO and BuCC” business
case
$1.3M 01/2021 12/2021
Cancel Dispatcher Training Simulator (DTS)
replacement
$1.15M 01/2021 12/2021
Do not complete EMS Upgrade project, nor DTS $0.65M 01/2021 12/2021
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 200 of 414
SCADA - SOO and BuCC

Business Case Justification Narrative v1.0 Page 4 of 7

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing
reductions to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
The EMS upgrade project is required to be completed in order to upgrade hardware and software that is
no longer supported. The EMS upgrade project will also better accommodate operation under the Energy
Imbalance Market.

2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful.
(i.e. if transfer to plant occurs monthly, quarterly or upon project completion).]
This is a continuous program. Work is started and completed throughout each year, and in some cases, such
as major upgrades, spans multiple years. Technology continues to change and T&D Systems continue to
incorporate improved technology.
0.
200,000.
400,000.
600,000.
800,000.
1,000,000.
1,200,000.
1,400,000.
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
SCADA Capital Spend History
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 201 of 414
SCADA - SOO and BuCC

Business Case Justification Narrative v1.0 Page 5 of 7
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]
This business case is crucial in a key aspect of Our Vision; “Delivering reliable energy service…” It is essential
in providing sufficient control center technology tools, situational awareness, and monitor/control capabilities to
achieve reliable energy service.
This business case is key in accomplishing the Our Focus item of “Safe & Reliable Infrastructure.” Providing
remote monitor and control capabilities to operators is essential in achieving “optimum life-cycle performance -
safely, reliably, and at a fair price.”
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project

2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
o Our Stakeholders include:
o Operations
▪ System Operators
▪ Power Schedulers
▪ Distribution Dispatchers
▪ Gas Controllers
▪ Energy Accounting & Risk Management
▪ Neighboring utility control centers
▪ Peak Reliability Coordinator
o Technicians
▪ Protection/Control/Metering Technicians
▪ Telecommunication Technicians
o Engineering
▪ Protection/Integration Engineering
▪ Substation Engineering
▪ Generation Engineering
▪ Distribution System Operations
o Enterprise Technology
▪ Oracle Database Administrators
▪ Security Engineering
▪ Network Engineering
▪ Network Operations

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 202 of 414
SCADA - SOO and BuCC

Business Case Justification Narrative v1.0 Page 6 of 7
2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]

3.1 Steering Committee or Advisory Group Information
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a
part of your departmental prioritization process.]
3.2 Provide and discuss the governance processes and people that will
provide oversight
Within the program’s yearly authorized spend amount, specific budgetary items to be implemented are
determined based upon requests by affected stakeholders including System Operations, Distribution
Dispatch, and Power Supply, and are documented in the Director of Transmission & Distribution System
Operations’ annual goals and priorities list.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored

The undersigned acknowledge they have reviewed the Business Case Justification
Narrative – SCADA -SOO and BuCC – 2020 and agree with the approach it
presents. Significant changes to this will be coordinated with and approved by the
undersigned or their designated representatives.

Signature: Craig N Figart Date: July 17, 2020
Print Name: Craig N Figart
Title: Manager of SCADA/EMS
Role: Business Case Owner

Signature: Date:
Print Name: Mike Magruder
Title: Energy Delivery Director,
Transmission & Distribution
System Operations

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 203 of 414
SCADA - SOO and BuCC

Business Case Justification Narrative v1.0 Page 7 of 7
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 204 of 414
Transmission Minor Rebuild
Business Case Justification Narrative Page 1 of 6
EXECUTIVE SUMMARY
The Transmission Minor Business Case covers the Transmission rebuild and reconductor work necessary to maintain
compliance with the North American Electric Reliability Corporation (NERC) Reliability Standard FAC-501-WECC-1 as
applied through Avista’s Transmission Maintenance Inspection Program (TMIP) This standard mandates that specific
Transmission lines be inspected annually and assessed for corrective actions to be implemented to remedy any system
performance deficiencies. The TMIP applies the same inspection methodology to the entire Avista system with the
understanding that only a portion of the mitigation work is recognized as Mandatory and Compliance. The remaining
work undertaken within this Business Case is recognized as Failed Plant and Asset Condition.
The implementation of this business case will be considered successful if these projects are all completed on an annual
basis or the dates identified in the Engineering Roundtable Project List.
The Transmission Minor Rebuild Business Case covers the follow-up work to Wood Pole Inspections, Aerial Patrol
inspections, and Ad Hoc ground inspections and Air Switch Replacements.
During routinely scheduled inspections, issues are discovered regarding the condition of assets, including items such
as rotten poles, broken/split/rotten crossarms, broken conductor or ground/shield wire, and air switches that no longer
operate safely or reliably.
The recommended solution is to correct the issues found by these inspections either in the same year, or within 1-2
years afterwards. There are no expected business impacts to continuing this program in place. If Avista does not fully
implement this business case, it runs an increased risk of system failures, customers outages, and wildfires. This
Program will have a Service Code of Electric Direct and a Rate Jurisdiction of Allocated North. An annual spend of
$3,343,420 is needed to complete the mitigations as follows:
• ER 2057, BI AMT12 and AMT13 ($1,613,420): Wood and Steel Pole Inspections (FAC-501-WECC-1, TMIP)
• ER 2057, BI XT902 ($1,500,000): Aerial and ground inspections (FAC-501-WECC-1, TMIP, and Ad Hoc)
• ER 2254, BI AMT10 ($230,000): Planned/unplanned replacements based on failure or upgrade needs
The customer benefits from this Business Case through increased service reliability.

VERSION HISTORY
Version Author Description Date Notes
Draft Ken Sweigart Initial draft of original business case 7/10/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 205 of 414
Transmission Minor Rebuild
Business Case Justification Narrative Page 2 of 6

GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 The Transmission Minor Business Case covers the Transmission rebuild and reconductor work necessary
to maintain compliance with the North American Electric Reliability Corporation (NERC) Reliability
Standard FAC-501-WECC-1 as applied through Avista’s Transmission Maintenance Inspection Program
(TMIP) This standard mandates that specific Transmission lines be inspected annually and assessed for
corrective actions to be implemented to remedy any system performance deficiencies. The TMIP applies
the same inspection methodology to the entire Avista system with the understanding that only a portion of
the mitigation work is recognized as Mandatory and Compliance. The remaining work undertaken within
this Business Case is recognized as Failed Plant and Asset Condition.
The Business Case also covers aerial, ground and Ad Hoc patrols intended to pro-actively replace
structures and structure components as riak on near term failure. This work (BI XT902: $1.5M) in previous
years was funded through the Operations Storms blanket Business Case.
1.2 What is the current or potential problem that is being addressed? . Avoidance
of failure conditions; that, if left unaddressed in the near-term (<1-2 years) will result in an increased risk
of system failures, customers outages, and wildfires.
1.3 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer Mandatory
& Compliance, combined with Failed Plant and Asset Condition: Customer benefits by having a
Transmission System in compliance with Federal Standards, and one where identified near-term failure
risks are proacitively addressed.
1.4 Identify why this work is needed now and what risks there are if not
approved or is deferred Unlike Asset Management studies and analysis that develop long-term
facility failure models, the inspection protocols associated with this Business Case identify asset problems;
that, if left unaddressed, will lead to near-term catastrophic structural failures.

Requested Spend Amount $16,717,100
Requested Spend Time Period 5 years
Requesting Organization/Department TLD Engineering
Business Case Owner | Sponsor Josh DiLuciano/Heather Rosentrater
Sponsor Organization/Department Energy Delivery/Electrical Engineering
Phase Execution
Category Program
Driver Multiple (see Executive Summary)
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 206 of 414
Transmission Minor Rebuild
Business Case Justification Narrative Page 3 of 6

1.5 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above. As-Built confirmation of mitigation measures.
1.6 Supplemental Information
1.6.1 Please reference and summarize any studies that support the problem
Asset Maintenance Wood Pole Management annual inspection reports
Transmission Line Design annual aerial patrol reports
Ad hoc inspections and or real-time notifications from area offices

1.6.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
Below are a few examples of the metric documents developed for this Business Case.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 207 of 414
Transmission Minor Rebuild
Business Case Justification Narrative Page 4 of 6

This is the continuation of an ongoing Program, and requires the mitigation of structure deficiencies.

Option Capital Cost Start Complete
Mitigate Deficiencies $16.7M 01-2021 12-2025
[Alternative #1] $M MM YYYY MM YYYY
[Alternative #2] $M MM YYYY MM YYYY
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
The benefits of this Business Case are seen in something not happening. Pro-actively addressing near-
term failures results in avoiding public safety risks including physical, electrical, and fire. A portion of this
Business Case was previously funded through an Operations Business Case.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
This program is in the Execution Stage with spend directed primarily at structure and structure component
change-outs resulting in facility failure avoidance.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Primary impacts are in the area of obtaining Transmission system outages and construction resources.
Although Transmission Line Design has the ability to Contract for construction services on the large
projects, internal construction resources typically perform the smaller jobs.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Replacing structures and structure components is presently the only alternative considered.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
Smaller projects can take place throughout the year. Most of the large projects take place in the Fall
months and Transfer to Plant in the Novemeber time frame.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 208 of 414
Transmission Minor Rebuild
Business Case Justification Narrative Page 5 of 6
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Aligns with Avista’s Culture of Compliance. This Business Case directly impacts our customer, and places
them as its focus.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Mitigation design solutions performed within PLS-CADD, which is the industry leader in providing
Transmission Line Design computer based programs. Designs are reviewed at multiple stages to ensure
prudency and maximum Stakeholder value.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Many and varied throughout Avista.
2.8.2 Identify any related Business Cases
None.
3.1 Steering Committee or Advisory Group Information
The Engineering Roundtable functions as the Vetting Platform, Steering Committee, and Advisory Group.
Provide and discuss the governance processes and people that will
provide oversight
Electrical Engineering Expected Spend Committee reviews on a monthly basis ongoing spend for projects
approved by the ERT. Committee members include Managers, Project Managers, analysts, and the
Electrical Engineering Director.
3.2 HOW WILL DECISION-MAKING, PRIORITIZATION, AND CHANGE
REQUESTS BE DOCUMENTED AND MONITORED
During the design phase these functions are processed through the Engineering Roundtable. During large
project Contracted construction, Change Orders are processed through Supply Chain. On smaller in-
house construction projects, changes are agreed upon at the Project Eneginer/Project Manager, and are
documented in the As-Built process.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 209 of 414
Transmission Minor Rebuild
Business Case Justification Narrative Page 6 of 6

The undersigned acknowledge they have reviewed the Transmission Minor Rebuild
Business Case Justification Narrative and agree with the approach it presents.
Significant changes to this will be coordinated with and approved by the undersigned
or their designated representatives.

Signature: Date:
Print Name:
Title:
Role: Business Case Owner

Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 210 of 414
Transmission Major Rebuild – Asset Condition
Business Case Justification Narrative Page 1 of 10
EXECUTIVE SUMMARY
The Transmission Major Rebuild – Asset Condition Business Case covers major rebuilds of transmission lines due to
overall asset condition. Factors such as operational issues, ease of access during outages, and potential for
communications build-out are also considered in prioritizing this work. The projects within this program are developed
through Asset Management’s general analysis of Avista’s Transmission System facilities that provides a risk based
ranking of over 100 Transmission Lines. This ranking is followed up by line specific studies. Projects are chosen to
maximize stakeholder value.
Investments made under this program rebuild existing transmission lines based on overall asset condition. “Condition”
is measured by useful life or the number of condition-related outages. Factors such as operational issues, ease of
access during outages, and need to add automation or communications equipment may be included in the type of
spending in this category. Replacing old and worn-out poles and cross-arms and other associated transmission
equipment, help guard against increasing risk for more failures and outages. Transmission outages can have significant
consequences, as they tend to impact a large number of customers and have the potential to start fires in dry areas.
In addition to reliability issues, failure to properly invest builds a bow-wave of needed investments in the future, thus
this program is crucial to maintaining operations. When facilities reach an age when it is close to or at the end of its
useful life, the Company preventively replaces it to maintain reliability and acceptable levels of service.
The implementation of this business case will be considered successful if these projects are completed as planned on
time and on budget.
The recommended solution is to rebuild transmission lines as prioritized by the Engineering Roundtable group to ensure
that Avista sufficiently addresses its aging Transmission Line infastructure. There are no expected business impacts
to continuing this program in place. This Program will have a Service Code of Electric Direct and a Rate Jurisdiction
of Allocated North. A spend of $71,900,000 is needed to complete the projects as follows:
• ER 2614, BI ST701 ($1,000,000): MTR-PST/PST-3HT 115kV UndergroundTransmission Line Rebuild
• ER 2611, BI KT901 ($21,650,000): Noxon-Pine Creek 230kV Transmission Line Rebuild
• ER 2594, BI CT908 ($250,000): Benewah-Pine Creek 230kV Transmission Line Rebuild
• ER 2596, BI LT900 ($49,000,000): Lolo-Oxbow 230kV Transmission Line Rebuild
Avista customers benefit from this Business Case through improved service reliability.

VERSION HISTORY
Version Author Description Date Notes
Draft Ken Sweigart Initial draft of original business case 7/10/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 211 of 414
Transmission Major Rebuild – Asset Condition
Business Case Justification Narrative Page 2 of 10

GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 The Transmission Major Rebuild – Asset Condition Business Case covers nvestments made to rebuild
existing transmission lines based on overall asset condition. “Condition” is measured by useful life or the
number of condition-related outages. Factors such as operational issues, ease of access during outages,
and need to add automation or communications equipment may be included in the type of spending in this
category. Replacing old and worn-out poles and cross-arms and other associated transmission equipment,
help guard against increasing risk for more failures and outages. Transmission outages can have
significant consequences, as they tend to impact a large number of customers and have the potential to
start fires in dry areas. In addition to reliability issues, failure to properly invest builds a bow-wave of needed
investments in the future, thus this program is crucial to maintaining operations. When facilities reach an
age when it is close to or at the end of its useful life, the Company preventively replaces it to maintain
reliability and acceptable levels of service.
1.2 What is the current or potential problem that is being addressed? .
Transmission outages can have significant consequences, as they tend to impact a large number of
customers and have the potential to start fires in dry areas. In addition to reliability issues, failure to properly
invest builds a bow-wave of needed investments in the future, thus this program is crucial to maintaining
operations.
1.3 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer Asset
Condition: Customer benefits by having a reliable Transmission System capable of supporting service
needs.
1.4 Identify why this work is needed now and what risks there are if not
approved or is deferred Transmission outages can have significant consequences, as they
tend to impact a large number of customers and have the potential to start fires in dry areas. In addition to
reliability issues, failure to properly invest builds a bow-wave of needed investments in the future, thus this
program is crucial to maintaining operations.

Requested Spend Amount $71,900,000
Requested Spend Time Period 5 years
Requesting Organization/Department TLD Engineering
Business Case Owner | Sponsor Josh DiLuciano/Heather Rosentrater
Sponsor Organization/Department Energy Delivery/Electrical Engineering
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 212 of 414
Transmission Major Rebuild – Asset Condition
Business Case Justification Narrative Page 3 of 10
1.5 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above. The implementation of this business case will be considered successful if these
projects are completed on time and within budget. Typical Project Management tracking tools in regards
to schedule and budget will be employed, as well as construction inspection services.
1.6 Supplemental Information
1.6.1 Please reference and summarize any studies that support the problem
Transmission Report 2020 Draft.docx
2016 Lolo-Oxbow 230kV Model Asset Management Plan Rev a.docx
LOL-OXB – model results.pptx
CDA (CDA-Rathdrum & Silver Valley) Transmission Reinforcement.pptx
CDA (Sandpoint) Transmission Reinforcement.pptx
Noxon-Pine Creek Final Report v3.docx
Noxon-Pine Creek Wood to Steel Conversion.pptx
1.6.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
Below are a few examples of the metric documents developed for this Business Case.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 213 of 414
Transmission Major Rebuild – Asset Condition
Business Case Justification Narrative Page 4 of 10

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 214 of 414
Transmission Major Rebuild – Asset Condition
Business Case Justification Narrative Page 5 of 10

The Noxon-Pine Creek 230kV Line is #2 on the Asset Condition Risk Index; and, when scheduled to be
rebuilt, will have most poles at age 44-years or higher. It is therefore recommended to pursue the Steel
Transmission Case.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 215 of 414
Transmission Major Rebuild – Asset Condition
Business Case Justification Narrative Page 6 of 10

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 216 of 414
Transmission Major Rebuild – Asset Condition
Business Case Justification Narrative Page 7 of 10

The Lolo-Oxbow 230kV Line is #1 on the Asset Condition Risk Index. Given the history of outages due to
fire, the time and effort required to mobilize and rebuild in this very remote location, lost revenue during
outages, and the desire by Transmission Planning to upgrade this line to match the Idaho Power Company
portion of the line, it is recommended to pursue the Rebuild and Reconductor Option.
This is the continuation of an ongoing Program, and requires the replacement of aging infastructure to support
service levels. Please see Alternatives Evaluation within documents referenced in Section 1.6.1, and information
shown in Section 1.6.2 for details.
Option Capital Cost Start Complete
Rebuild Infastructure $71.9M 01-2021 12-2025
[Alternative #1] $M MM YYYY MM YYYY
[Alternative #2] $M MM YYYY MM YYYY
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
The benefits of this Business Case are seen in being able to support overall Asset Management strategies.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
• ER 2614, BI ST701 ($1,000,000): The MTR-PST/PST-3HT 115kV UndergroundTransmission Line
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 217 of 414
Transmission Major Rebuild – Asset Condition
Business Case Justification Narrative Page 8 of 10
Rebuild Project will complete in 2021, having started in 2019. Used and Useful and Transferred to
Plant in Spring of 2021.
• ER 2611, BI KT901 ($21,650,000): The Noxon-Pine Creek 230kV Transmission Line Rebuild Project
will be in the Design/Procurement stages in 2022-2023, and Procure/Construct in 2024-2025. Used
and Useful and Transferred to Plant in Fall/Winter of 2024 and 2025.
• ER 2594, BI CT908 ($250,000): The Benewah-Pine Creek 230kV Transmission Line Rebuild Project
is scheduled to begin design in 2025; and, at this time is acting as a placeholder for a future project.
• ER 2596, BI LT900 ($49,000,000): The Lolo-Oxbow 230kV Transmission Line Rebuild Project began
construction in 2020, and will complete in 2025. Used and Useful and Transferred to Plant in
Fall/Winter of each year between 2021 and 2025.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Primary impacts are in the area of obtaining Transmission system outages and construction resources.
Although Transmission Line Design has the ability to Contract for construction services on the large
projects. Design resources can be supplemented by local consulting services.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Please see documents referenced in Section 1.6.1, and information shown in Section 1.6.2.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
Please see Section 2.2.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Aligns with the Focus Areas of Customers and Perform.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Design solutions performed within PLS-CADD, which is the industry leader in providing Transmission Line
Design computer based programs. Designs are reviewed at multiple stages to ensure prudency and
maximum Stakeholder value.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Many and varied throughout Avista.
2.8.2 Identify any related Business Cases
None.
3.1 Steering Committee or Advisory Group Information
The Engineering Roundtable functions as the Vetting Platform, Steering Committee, and Advisory Group.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 218 of 414
Transmission Major Rebuild – Asset Condition
Business Case Justification Narrative Page 9 of 10
Provide and discuss the governance processes and people that will
provide oversight
Electrical Engineering Expected Spend Committee reviews on a monthly basis ongoing spend for projects
approved by the ERT. Committee members include Managers, Project Managers, analysts, and the
Electrical Engineering Director.
3.2 HOW WILL DECISION-MAKING, PRIORITIZATION, AND CHANGE
REQUESTS BE DOCUMENTED AND MONITORED
During the design phase these functions are processed through the Engineering Roundtable. During large
project Contracted construction, Change Orders are processed through Supply Chain.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 219 of 414
Transmission Major Rebuild – Asset Condition
Business Case Justification Narrative Page 10 of 10

The undersigned acknowledge they have reviewed the Transmission Major Rebuild
– Asset Condition Business Case Justification Narrative and agree with the
approach it presents. Significant changes to this will be coordinated with and
approved by the undersigned or their designated representatives.

Signature: Date:
Print Name:
Title:
Role: Business Case Owner

Signature: Date:
Print Name:
Title:
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 220 of 414
Substation – New Distribution Station Capacity Program
Business Case Justification Narrative Page 1 of 7
EXECUTIVE SUMMARY
This section is reserved to provide a brief description of the business case and high level summary of the
projects or programs included. Please limit to no more than 2 paragraphs. Components that should be
included: 1) a synopsis of the problem, 2) the service code and jurisdiction of customers impacted, 3) the
recommended solution, 4) the cost of the solution, 5) how the solution will benefit customers identified, 6) the
significance of the timeline and 7) the risks of not approving this business case.
<< Both the Executive Summary and Version History should fit into one page >>
New distribution substations added to the system for load growth and reliability are critical to the
long term operation of the system. As load demands, increase and customer expectations rise
regarding reliability, incremental distribution substation capacity is required. This allows for
improved operational flexibility, better system reliability, and easier routine maintenance
scheduling as equipment is more easily taken out of service because load can be transferred.

Capacity on the electric system to be able to take components out of service on a planned basis
so that maintenance or replacements can be made has reduced as load demands have
increased. Having the right amount of backup capacity in each area is critical for the continued
appropriate management of the electric system. This business case is important because through
it, customers can likely continue to receive electric service at a level that they have grown
accustom to receiving.

Service: ED – Electric Direct
Jurisdiction: Various. Each rebuild project has its own Jurisdiction.
Engineering Roundtable Request Number: Various. Each rebuild project has its own ERT
Request.
2020 Expected Spend: $7,600,000

VERSION HISTORY
Version uthor Description Date Notes
1.0 Ken Sweigart Initial Version 04/14/2017 Initial Version
2.0 Karen Kusel /
Glenn Madden Update to 2020 Template 06/30/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 221 of 414
Substation – New Distribution Station Capacity Program
Business Case Justification Narrative Page 2 of 7
GENERAL INFORMATION
1 BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
New distribution substations added to the system for load growth and reliability are critical
to the long term operation of the system. As load demands, increase and customer
expectations rise regarding reliability, incremental distribution substation capacity is
required. This allows for improved operational flexibility, better system reliability, and easier
routine maintenance scheduling as equipment is more easily taken out of service because
load can be transferred.
1.1 What is the current or potential problem that is being addressed?
As load demands, increase and customer expectations rise regarding reliability,
incremental distribution substation capacity is required.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Performance and Capacity – Increasing load on an aging electrical system. And the better
the asset condition, the fewer equipment failures and possible customer outages there are.
1.3 Identify why this work is needed now and what risks there are if not approved
or is deferred
This is a continuing effort to stay ahead of the curve to avoid reliability issues.
1.4 Identify any measures that can be used to determine whether the investment
would successfully deliver on the objectives and address the need listed
above.
System Planning Assessments and Studies.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
[List the location of any supplemental information; do not attach]
Requested Spend Amount $6,000,000 per year
Requested Spend Time Period On Going
Requesting Organization/Department T&D
Business Case Owner | Sponsor Glenn Madden | Josh DiLuciano
Sponsor Organization/Department T&D
Phase Execution
Category Program
Driver Performance & Capacity
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 222 of 414
Substation – New Distribution Station Capacity Program
Business Case Justification Narrative Page 3 of 7
System Planning Assessments on System Planning Sharepoint site.
1.5.2 For asset replacement, include graphical or narrative representation of
metrics associated with the current condition of the asset that is proposed
for replacement.
Not Applicable.
2 PROPOSAL AND RECOMMENDED SOLUTION
[Describe the proposed solution to the business problem identified above and why this is the best and/or least
cost alternative (e.g., cost benefit analysis, attach as supporting documentation)]
This program adds new distribution substations to the system in order to serve new and
growing load as well as for increased system reliability and operational flexibility. New
substations under this program will require planning and operational studies, justifications,
and approved Project Diagrams prior to funding.
Alternatives considered include:
Do Nothing: Maintain (to the best of our ability) all obsolete or end-of-life apparatus. Repair
or replace equipment on emergency basis only. Some repairs would not be possible due to
obsolescence. Considerably more, and longer, customer outages would result. Although
there is zero Capital cost connected with keeping the status quo there are some associated
O&M and other system sustainment costs.
Extension of distribution feeders from neighboring substations and increased capacity
at those substations would be required at a minimum. The negative impact is most
certainly reduced reliability and difficulty in long term maintenance and system
operation. Increased liability would result.
Solution: Anticipated load growth requires the addition of two new substations per year
over the 2017-2026 horizon
Option Capital Cost Start Complete
Recommended Solution $6M Annually Annually
Alternative #1: Do Nothing $0
Extend Existing Distribution Feeders
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Examples include:
- Samples of savings, benefits or risk avoidance estimates
- Description of how benefits to customers are being measured
- Comparison of cost ($) to benefit (value)
- Evidence of spend amount to anticipated return
Reference key points from external documentation, list any addendums, attachments etc.
System Planning Assessments.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 223 of 414
Substation – New Distribution Station Capacity Program
Business Case Justification Narrative Page 4 of 7
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital
spend?). Include any known or estimated reductions to O&M as a result of
this investment.
How will the outcome of this investment result in potential additional O&M costs, employee or staffing
reductions to O&M (offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]

Below is a graph showing previous years actual spend on this Business Case, the Expected
Spend for 2020 and budget requests for the future.

O&M will increase due to the addition of electric substation and associated transmission
and distribution lines. This will include inspections and maintenance of equipment.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
[For example, how will the outcome of this business case impact other parts of the business?]
System Operations will have improved functionality of the electric system.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Status Quo – Obsolete equipment drives up maintenance costs and outage risks. Extending
Distribution Feeders – higher risk of load issues and customer outages.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 224 of 414
Substation – New Distribution Station Capacity Program
Business Case Justification Narrative Page 5 of 7
2.5 Include a timeline of when this work will be started and completed. Describe
when the investments become used and useful to the customer. spend, and
transfers to plant by year.
[Describe if it is a program or project and details about how often in a year, it becomes used-and-useful. (i.e. if
transfer to plant occurs monthly, quarterly or upon project completion).]
See graph above, Section 2.2. Transfers to plant will occur when a substation is in-service
or energized. Adhering to project timelines will save capital carrying costs.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
[If this is a program or compilation of discrete projects, explain the importance of the body of work.]
Mission: We improve our customers’ lives through innovative energy solutions.
Vision: Better energy for life
These projects will help Avista stay ahead of the curve of load growth and equipment age
to prevent customer outages.
2.7 Include why the requested amount above is considered a prudent investment,
providing or attaching any supporting documentation. In addition, please
explain how the investment prudency will be reviewed and re-evaluated
throughout the project
Failure to adjust to load changes and customer needs will lead to equipment failures,
customer outages and expensive emergency projects.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Electrical Engineering, Generation Production/Substation Support, Transmission
Operations and System Planning and Operations
2.8.2 Identify any related Business Cases
[Including any business cases that may have been replaced by this business case]
Not Applicable.
3 MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
[Please identify and describe the steering committee or advisory group for initial and ongoing vetting, as a part
of your departmental prioritization process.]
• Glenn Madden - Manager, Substation Engineering
• Project Engineer/Project Manager (PE/PM) – Various
The assigned PE/PM holds stakeholder meetings to develop/confirm scope, schedule and
costs. Also meets at time of pre-construction. Other meetings held as necessary.
The Engineering Roundtable manages the prioritization of projects within this business
case as supported by Asset Management studies and input from company subject matter
experts. The Engineering Roundtable is comprised of representatives from the following
departments: Asset Management, Compliance, System Planning, System Operations,
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 225 of 414
Substation – New Distribution Station Capacity Program
Business Case Justification Narrative Page 6 of 7
Telecommunications, Transmission Contracts, Protection Engineering, Substation
Engineering, Transmission Engineering, and Substation Support.
3.2 Provide and discuss the governance processes and people that will provide
oversight
Engineering Roundtable meets several times a year to analyze current and future projects.
3.3 How will decision-making, prioritization, and change requests be documented
and monitored
Project folders are saved to Engineering shared drives and Businesss Case Funds
Requests are available on the Finance sharepoint site

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 226 of 414
Substation – New Distribution Station Capacity Program
Business Case Justification Narrative Page 7 of 7
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Substation – New Distribution
Station Capacity Program and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.

Signature: Date:
Print Name: Glenn Madden
Title: Manager, Substation Engineering
Role: Business Case Owner

Signature: Date:
Print Name: Josh DiLuciano
Title: Director, Electrical Engineering
Role: Business Case Sponsor

Signature: Date:
Print Name: Damon Fisher
Title: Principle Engineer
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
1/5/2021
1/5/2020 1/5/2021
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 227 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 228 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 229 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 230 of 414
Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
Business Case Justification Narrative Page 1 of 12
EXECUTIVE SUMMARY

In February 2012, Avista’s Asset Management Group released findings in the “Avista’s Proposed Protocol
for Managing Select Aldyl-A Pipe in Avista Utility’s Natural Gas System” report. The report documents
specific Aldyl-A pipe in Avista’s natural gas pipe system, describes the analysis of the types of failures
observed, and the evaluation of its expected long-term integrity. The report proposed the undertaking of a
twenty-year program to systematically replace select portions of Aldyl-A medium density pipe within its
natural gas distribution system in the States of Washington, Oregon, and Idaho.
The Gas Facility Replacement Program (GFRP) was initiated in 2012 and is planned to continue for 20
years (until the end of 2031). It is the sole mission and charter for the GFRP to plan and execute the
replacement of 737 miles of Aldyl-A main pipe and to rebuild 17,769 service tee transitions throughout
Avista’s service territories (Idaho, Oregon, and Washington). The Aldyl-A main pipe replacement work
includes Aldyl-A pipe that is 1-1/4” diameter and great and with an install date prior to January 1, 1987, or
a manufactured date prior to January 1985.
Avista has a regulatory mandate to complete this program and has a goal of investing in its infrastructure
to achieve optimum life-cycle performance. The historical spending trend from 2015 through 2019 has
been $20M-$22M annually and is reflective of the program’s most recent cost experience updates. The
requested budget amounts consider Avista’s regulatory mandate to complete this program and has a goal
of investing in its infrastructure to achieve optimum life-cycle performance. Inflation of approximately 2.3%
has been planned for by escalating the annual costs.
Aldyl-A pipe will eventually reach a level of unreliability that is not acceptable due to the tendency for this
material to suffer brittle-like cracking leak failures. There is a potential harm to the public through damage
to life and property and there is a high likelihood of increasing regulatory scrutiny from increasing failures.
Not approving or deferring this body of work would further exacerbate the risks.

VERSION HISTORY
Version Author Description Date Notes
Draft Michael Whitby Initial draft of original business case 2011
1 Michael Whitby Budget Change 2015 Additional $1.8M approved
2 Michael Whitby Budget Change 2016 Additional $3M approved
3 Michael Whitby Budget Change 2017 $2M deferred to 2018
4 Michael Whitby Budget Change 2018 $1M deferred to 2019
5 Michael Whitby Budget Change 2019 $1.5M deferred to 2020
6 Karen Cash Budget Change 2020 $1,035,000 deferred to 2021

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 231 of 414
Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
Business Case Justification Narrative Page 2 of 12
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
For Avista, aside from third party excavation damage, the highest risks within our natural gas
distribution system is Aldyl-A Main Pipe (Manuf. 1964-1984), and the bending stress that occurs on
Aldyl-A service pipe where it is connected to steel main pipe.
GFRP was initiated in 2012 and is planned to continue for 20 years (until the end of 2031). It is the
sole mission and charter for the GFRP to plan and execute the replacement of 737 miles of Aldyl-A
main pipe and to rebuild 17,769 service tee transitions. The Aldyl-A main pipe replacement work
includes Aldyl-A pipe that is 1-1/4” diameter and great and with an install date prior to January 1,
1987, or a manufactured date prior to January 1985.
The GFRP’s Service Tee Transition Rebuild (STTR) Program was structured to mitigate the risks
associated with the “Bending Stress Services” category within a 5-year time frame. The STTR
Program started in 2013 and was deemed substantially complete in December 2017.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Avista has a regulatory mandate to complete this program and has a goal of investing in its
infrastructure to achieve optimum life-cycle performance.
As of August 2011, the US Department of Transportation Pipeline and Hazardous Materials Safety
Administration (PHMSA) mandates gas distribution pipeline operators to implement Integrity
Management Plans, or in Avista’s case, a Distribution Integrity Management Plan (DIMP) in which
pipeline operators are required to identify and mitigate the highest risks within their system. For
Avista, aside from third party excavation damage, the highest risks within our natural gas distribution
system is Aldyl-A Main Pipe (Manuf. 1964-1984), and the bending stress that occurs on Aldyl-A
service pipe where it is connected to steel main pipe.
More specifically, and as related to the risks identified above, in February 2012 Avista’s Asset
Management Group released findings in the “Avista’s Proposed Protocol for Managing Select Aldyl-
A Pipe in Avista Utility’s Natural Gas System” report. The report documents specific Aldyl-A pipe in
Avista’s natural gas pipe system, describes the analysis of the types of failures observed, and the
evaluation of its expected long-term integrity. The report proposed the undertaking of a 20-year
program to systematically replace select portions of Aldyl-A medium density pipe within its natural
gas distribution system in the states of Idaho, Oregon, and Washington.
Requested Spend Amount $22,000,000 - $29,000,000 Annually
Requested Spend Time Period 11 years (2021 through 2031)
Requesting Organization/Department Natural Gas / Gas Facility Replacement Program
Business Case Owner | Sponsor Karen Cash / Mike Faulkenberry
Sponsor Organization/Department Energy Delivery / Natural Gas
Phase Execution
Category Program
Driver Mandatory & Compliance
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 232 of 414
Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
Business Case Justification Narrative Page 3 of 12
Subsequently, the Gas Facility Replacement Program’s (GFRP) was formed as the operational entity
committed to structuring and implementing a systematic approach to mitigating the Aldyl-A pipe risks
as identified in aforementioned report.
On December 31, 2012 the Washington Utilities and Transportation Commission (WUTC)
issued its policy statement on Accelerated Replacement of Pipeline Facilities with Elevated Risks
which requires gas utility companies to file a plan every two year for replacing pipe that represents
an elevated risk of failure. The requirement to file a Pipe Replacement Plan (PRP) commenced on
June 1, 2013. In response to this order, Avista’s first 2-year PRP for 2014-2015 was submitted and
approved in 2013 per Docket PG-131837, Order 01. Avista’s second two-year PRP for 2016-2017
was submitted in 2015 and approved in 2016 per WUTC Docket PG-160292, Order 01. Avista
submitted a PRP in June 2017, and 2019.In Avista’s filings, the “Avista’s Proposed Protocol for
Managing Select Aldyl-A Pipe in Avista Utility’s Natural Gas System” report serves as the pipe
replacement “Master Plan”, and two year pipe replacement goals which includes specific project
locations, and the anticipated pipe replacement quantities.
On March 6, 2017 the Oregon Public Utilities Commission (“Commission”) issued Order 17-084
(Docket UM 1722, Investigation into Recovery of Safety Costs by Natural Gas Utilities), which in part
required each of the natural gas distribution companies serving customers in Oregon to file with the
Commission by September 30th each year an annual “Safety Project Plan” (or Plan).1 The purpose
of the Plan is to increase transparency into the investments made by each utility that are based
predominantly on the need to achieve important safety objectives. More specifically, the Plan is
intended to achieve the following objectives:

• Explain capital and expenses needed to mitigate safety issues identified by risk analysis or new
federal and state rules;

• Demonstrate the utility’s safety commitment and priority to its customers;

• Provide a non-technical explanation of primary safety reports each utility is required to file with
the Commission’s pipeline safety staff; and

• Identify major regulatory changes that impact the utility’s safety investments.

The Idaho Public Utilities Commission (IPUC) has not required gas utility companies to submit an
action plan, Avista has submitted the “Avista’s Proposed Protocol for Managing Select Aldyl-A Pipe
in Avista Utility’s Natural Gas System” report for review, and communicates annual pipe replacement
goals which includes specific project locations, and the anticipated pipe replacement quantities.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred

To ensure Avista fulfills the regulatory mandate to complete this program.
The need to conduct this program has been identified in “Avista’s Proposed Protocol for Managing
Select Aldyl-A Pipe in Avista Utility’s Natural Gas System” report. Further, and more specifically, due
to the tendency for this material to suffer brittle-like cracking leak failures, Aldyl-A will eventually
reach a level of unreliability that is not acceptable. There is a potential harm to the public through
damage to life and property and there is a high likelihood of increasing regulatory scrutiny from
increasing failures. Not approving or deferring this body of work would further exacerbate the risks
as identified above.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 233 of 414
Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
Business Case Justification Narrative Page 4 of 12
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The objective of this investment and structured replacement program is to reduce risk by replacing
at risk pipe and by rebuilding Service Tee Transitions. Through rigorous Project Management efforts,
the GFRP plans and tracks the performance of the projects, and utilizes Earned Value for cost
analysis and for upstream reporting. Further, the GFRP tracks and reports Planned vs. Actual
quantities by project, by year, by state jurisdiction, and also reports multi-year cumulative statistics.

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
a. On December 31, 2012, the Washington Utilities and Transportation Commission
(WUTC) issued its policy statement on Accelerated Replacement of Pipeline Facilities
with Elevated Risks which requires gas utility companies to file a plan every two years
for replacing pipe that represents an elevated risk of failure. The requirement to file a
Pipe Replacement Plan (PRP) commenced on June 1, 2013.
b. February 23, 2012 – Avista Utilities Asset Management “Proposed Protocol for
Managing Select Aldyl-A Pipe in Avista Utilities’ Natural Gas System”
c. April 11, 2013 - Revised Avista Utilities Asset Management “Proposed Protocol for
Managing Select Aldyl-A Pipe in Avista Utilities’ Natural Gas System”
d. July 2013 – ARMS Reliability Report – Avista Study of Aldyl-A Mainline Pipe and
Bending Stress Point Leaks
e. Avista’s first 2-year PRP to the WUTC for 2014-2015 was submitted and approved in
2013 per Docket PG-131837, Order 01.
f. Avista’s second 2-year PRP to the WUTC for 2016-2017 was submitted in 2015 and
approved in 2016 per WUTC Docket PG-160292, Order 01.
g. Order of the Public Utility Commission of Oregon in Docket UM 1722, Investigation into
Recovery of Safety Costs by Natural Gas Utilities. March 6, 2017.
h. Avista’s Proposed Protocol for Managing Select Aldyl-A Pipe in Avista Utility’s Natural
Gas System report serves as the pipe replacement “Master Plan”, and two year pipe
replacement goals which includes specific project locations, and the anticipated pipe
replacement quantities.
i. April 2018 – ARMS Reliability Report - Avista Study of Aldyl-A Mainline Pipe Leaks 2018
Update

1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.

The chart below identifies the expected number of material failures in Avista’s Priority Aldyl-A piping
in two cases: Replacement Case – piping replaced over a 20-year time horizon, and Base Case –
assumed that priority piping was not remediated under any program.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 234 of 414
Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
Business Case Justification Narrative Page 5 of 12

As shown in the graph below and outlined in “Forecasting Results” section of “Avista’s Proposed
Protocol for Managing Select Aldyl-A Pipe in Avista Utility’s Natural Gas System” report, Avista’s
forecast modeling tool “Availability Workbench Modeling” evaluates several classes of pipe which
are represented as “curves” showing the percentage of the amount of pipe class that is projected to
fail in each year of the forecasted time period.

“Avista’s Proposed Protocol for Managing Select Aldyl-A Pipe in Avista Utility’s Natural Gas System”
report details the various time horizons modeled for the Aldyl-A Pipe Replacement program.
The Aldyl-A Pipe Replacement effort has been proposed and planned as a systematic twenty-year
pipe replacement program. The program is expected to have a nominal impact to existing business
resources, functions, and processes since the GFRP has been structured to function as a “stand
alone” program consisting of dedicated “internal” resources. The primary functions established for
these internal resources are to plan, design, oversee, manage, and administer the significant body
of projectized work as assigned to “external” contract construction resources.
Periodically, on an as-needed basis, the GFRP will call on other business units for support.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 235 of 414
Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
Business Case Justification Narrative Page 6 of 12
Since pipe replacement work is a capital expenditure, the impact to O&M cost has been minimal.
Occasionally GFRP projects will encounter circumstances that necessitate O&M expenditures. When
known, these O&M costs are estimated prior to construction. The GFRP tracks and monitors O&M
costs monthly.

Option Capital Cost Start Complete
Replace priority high-risk Aldyl-A pipe in a 20-year
timeframe
≈ $443M January
2012
December
2031

The 2013 Avista Study of Aldyl-A Mainline Pipe Leaks was updated in 2018 based on the upon leaks
and replacements through the end of 2017. The original study developed failure distributions that
described the likelihood of leaks occurring on the Aldyl-A pipe installed by Avista for natural gas
distribution and to evaluate multiple replacement scenarios. According to the table below the
baseline scenario remains more cost effective when compared to the replacement strategies.

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.

The 2013 Avista Study of Aldyl-A Mainline Pipe Leaks was updated in 2018 based on the upon
leaks and replacements through the end of 2017. The study incorporated leak reduction and risk
avoidance in the analysis.

After updating the model with leaks and replacements from 2013-2018 the expected number or
leaks for the remaining period (2018-2088) reduced from 26,792 to 12,335 due to the large amount
of the worst pipe already replaced. If the 20-year replacement program where all Aldyl-A pipe is
removed continues there is a slight reduction in the expected number of leaks, 255 in the original
study and 246 in the updated model.

Safety risks and criticality were also considered as part of the study update. It is understood that
each failure event (leak) does not always result in an injury and this is incorporated as a
percentage of events that result per Avista standard modeling guidelines. The severities used are
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 236 of 414
Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
Business Case Justification Narrative Page 7 of 12
shown in table below. The projected number of catastrophic events drop from 258 to 5 events
over the next 70 years by replacing the Aldyl-A pipe.

While Avista's 20-year structured replacement program has proven to reduce the highest risk in
the early years of the program, the continuation of this structured replacement program is both
necessary and prudent to mitigating the remaining risks within the system, and to achieving
Avista's goal of operating and maintaining a safe and reliable natural gas distribution system.

2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
[Offsets to projects will be more strongly scrutinized in general rate cases going forward (ref. WUTC Docket No. U-190531 Policy
Statement), therefore it is critical that these impacts are thought through in order to support rate recovery.]

Over the duration of the 20-year program, the GFRP will conduct replacement and rebuild work in
virtually every gas district across Idaho, Oregon, and Washington, with large concentrations of Aldyl-
A pipe occurring in the metropolitan centers of Spokane, Washington, Medford, Oregon, and Coeur
d’Alene, Idaho. Based on the scope of work and schedule, the GFRP will plan and manage more
than 100 Major Capital Projects as follows:

Category Type Quantity Duration Project Count
Major Main Pipe 737 miles 20 years ~ 105
Major STTR 17,769 service tees 5 years (Completed) ~20

The 2013 study predicted a total of 26,792 leaks on Aldyl-A mainline pipe from 2018 through 2088
years without any form of a proactive replacement program. Based upon the proactive replacements
that have occurred, the number of leaks predicted over the same period has reduced to 12,335 with
246 catastrophic events if the proactive replacement were to not continue. With the current
replacement of all Aldyl-A pipe by 2035, the number of predicted leaks from 2018 to program
completion reduces slightly, moving from 255 to 246 leaks of which 4 have the potential to be
catastrophic events. Assumptions made during the study were as follows:

• Planned replacement of Aldyl-A Mainline pipe costs $357 per three feet in Washington
and Idaho and $360 per three feet in Oregon.
• Unplanned replacement of Aldyl-A Mainline pipe costs $5,071 per three-foot section.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 237 of 414
Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
Business Case Justification Narrative Page 8 of 12
• Consequences for a Catastrophic Event, Injury with lost time and injury without lost time
are applied per Avista standard practice.

At Avista we forecast Capital Projects/Programs on five-year budget planning cycles which are
updated and adjusted annually. In order to provide the most accurate budget forecasts possible it is
necessary to draw from the program’s most current cost data which is tracked and derived from
recently completed projects. The historical spending trend from 2015 through 2019 has been $20M-
$22M annually and is reflective of the program’s most recent cost experience updates. The requested
budget amounts take into account of Avista’s regulatory mandate to complete this program with full
contractor complement and has a goal of investing in its infrastructure to achieve optimum life-cycle
performance. Inflation of approximately 2.3% has been planned for by escalating the annual costs.

Year System Transfer to Plant
(TTP)
Actual vs.
Forecasted
2011 $2,683,207 Actual
2012 $187,815 Actual
2013 $17,690,260 Actual
2014 $16,875,629 Actual
2015 $19,709,181 Actual
2016 $19,576,293 Actual
2017 $18,371,496 Actual
2018 $21,914,044 Actual
2019 $22,002,672 Actual
2020 $22,307,086 Forecasted
2021 $22,832,227 Forecasted
2022 $23,357,368 Forecasted
2023 $23,894,587 Forecasted
2024 $24,444,163 Forecasted
2025 $25,006,379 Forecasted
2026 $25,006,379 Forecasted
2027 $26,169,901 Forecasted
2028 $26,771,808 Forecasted
2029 $27,387,560 Forecasted
2030 $28,017,474 Forecasted
2031 $28,661,876 Forecasted
Grand Total $443,442,553
Annual Average $21,116,312

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 238 of 414
Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
Business Case Justification Narrative Page 9 of 12
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Unplanned leak repairs are an O&M cost and are addressed by the local districts. Through this
program, O&M expenses are mitigated. The 2013 study predicted a total of 26,792 leaks on
Aldyl-A mainline pipe from 2018 through 2088 years without any form of a proactive replacement
program. Based upon the proactive replacements that have occurred, the number of leaks
predicted over the same period has reduced to 12,335 with 246 catastrophic events if the
proactive replacement were to not continue.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.

To establish context, Avista’s goal is operate a safe & reliable, and cost-effective gas distribution
system. Specifically, as related to these goals, § XI of “Avista’s Proposed Protocol for Managing
Select Aldyl-A Pipe in Avista Utility’s Natural Gas System” report details the various time horizons
modeled for the Aldyl-A Pipe Replacement program.
To summarize, the primary alternatives modeled are as follows:
• Do Nothing
Pipe Replacement Strategies:
Since the “do nothing” option was not an acceptable or prudent approach, the Company evaluated
different periods of time for removal of all Priority Aldyl-A pipe, up to a program horizon of 30 years.
Avista assessed the prudence of different approaches based on the forecast of likely natural gas
leaks due to failed pipe, as well as the rate impact to customers.
• Less than 20 Year Pipe Replacement Program
• Conduct a 20 Year Pipe Replacement Program (Optimal)
• Conduct a 25+ Year Pipe Replacement Program
Based on the time horizon scenarios modeled, it was determined that the optimum timeframe for
removing priority Aldyl-A pipe was the 20 years.
RISKS ASSOCIATED WITH ALTERNATIVES CONSIDERED:
To summarize the primary alternatives and associated risks;
• Do Nothing:
It has been determined that this type of pipe is at risk and is approaching unacceptable levels
of reliability without prompt attention. The “Do Nothing” option exposes Avista to increased
operational risks, and worse, is a potential harm to our customers and the public through
damage to life and property, and a high likelihood of legal action against the Company and
likely regulatory fines. For this reason it was deemed “not prudent” and is not a serious
consideration.
• Less than 20 Year Pipe Replacement Program:
Avista found that a timeline less than 20 years resulted in a greater cost impact to customers
in the near term, and that it did little to reduce the forecast number of leaks expected each
year. This approach did not effectively optimize the potential risks and rate impacts.
• Conduct a 20 Year Pipe Replacement Program:
The report proposes and suggests that a Systematic Replacement Program conducted over
a 20 year timeline is the optimum timeframe to prudently manage this risk, based on the
forecast number of leaks and risks, and the rate impact to our customers.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 239 of 414
Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
Business Case Justification Narrative Page 10 of 12
• Conduct a 25+ Year Pipe Replacement Program:
Lengthening the timeframe to 25 years resulted in more than a doubling of the number of
leaks expected when compared to a 20-year horizon. Lengthening the timeline beyond 25
years was found to result in a substantial increase in the number of material failures
expected.
As outlined above, Asset Management has identified 20 years as the optimum timeframe to prudently
manage this risk. Avista’s leadership has adopted this recommendation and has funded and staffed
the program to achieve this objective. Furthermore, the three state Commissions that regulate
Avista’s natural gas operations have thoroughly examined this program in several rates proceedings,
and in policy proceedings, and have deemed this approach to be prudent, cost effective, and in the
interest of our customers.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.

Start: January 2012
Expected End: December 2031
The annual list of projects in each of the three states (ID, OR, and WA) are established as unique
“blanket projects” that transfer to plant (TTP) each month as they are “used & useful”.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.

The Gas Facilities replacement Program (GFRP) is responsible for Aldyl-A pipe replacement
which aligns with Avista’s mission to operate and maintain a “Safe and Reliable Infrastructure”.
Avista has a goal of investing in its infrastructure to achieve optimum life-cycle performance.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project

The objective of this investment and structured replacement program is to reduce risk by
replacing at risk pipe and by rebuilding Service Tee Transitions. Through rigorous efforts, the
GFRP plans and tacks the performance of each project and utilizes Earned Value for cost
analysis and for upstream reporting. Furthermore, the GFRP tracks and report Planned vs.
Actual quantities by project, year, state jurisdiction, and also reports multi-year cumulative
statistics.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case

Avista’s customers and the general public expect Avista’s natural gas system to operate safely
and reliably without incidents. Avista is dedicated to and focused on maintaining a safe and
reliable system that shields the public from imprudent risks. The proposed pipe replacement
programs have been initiated with the purpose of mitigating the known risks within the natural
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 240 of 414
Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
Business Case Justification Narrative Page 11 of 12
gas distribution system. Given this context, the Gas Facility Replacement Program’s portfolio
of projects could therefore be considered as a customer-related benefit.

The GFRP’s Aldyl-A Pipe Replacement projects touch numerous internal and external
stakeholders. A comprehensive list of stakeholders is in the “2019 GFRP Operating Plan &
Projects” document.

2.8.2 Identify any related Business Cases

Business cases have been submitted annually and updated as necessary since 2012, the
inception of the Gas facility Replacement Program.

3.1 Steering Committee or Advisory Group Information
The Gas Facility Replacement Program (GFRP) Advisory Group consists of the GFRP’s
Program Manager, Cas Operations Contract Construction Manager, Director of Natura Gas, and
the Manager of Gas Design & Measurement. This group meets monthly to review program wide
Earned Value results, that status of the delivery of the individual projects, budget allocations and
variances, internal resource demands, customer care results and issues, contractor
performance, and to communicate potential program risks and shortfalls.

In addition, Avista’s Distribution Integrity Management Plan and Asset Management groups
provide periodic input, and/or validation of the replacement plan and schedule.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Each year an annual portfolio of projects is derived from Avista’s Distribution Integrity
Management Program (DIMP) Aldyl-A prioritization list which currently identifies unique priority
project areas (polygons) throughout the natural gas system in ID, OR, and WA. The portfolio of
projects is sized to meet jurisdictional commitments. Then individual priority projects are
planned, phased, scoped, designed, and detailed estimates are prepared. Once the individual
project estimates are finalized, the overall program-wide capital budget is refined to reflect a
more precise budget. The requested spend level has historically been determined based upon
Avista’s experience in the management of the Aldyl-A pipe facilities across Avista’s service
territories coupled with any changing costs of construction year to year.
There are circumstances where lower priority Aldyl-A projects may be accelerated if it makes
sense to coordinate the timing of pipe replacement projects with prior phasing or with other utility
and road projects. The individual projects for GFRP are typically managed by the Customer
Project Coordinators (CPC’s) while the overall program budget is managed by the GFRP
Program Manager.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The Gas Facility Replacement Program (GFRP) Advisory Group consists of the GFRP’s
Program Manager, Cas Operations Contract Construction Manager, Director of Natura Gas, and
the Manager of Gas Design & Measurement. This group meets monthly to review program wide
Earned Value results, that status of the delivery of the individual projects, budget allocations and
variances, internal resource demands, customer care results and issues, contractor
performance, and to communicate potential program risks and shortfalls. The monthly
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 241 of 414
Gas Facility Replacement Program (GFRP)
Aldyl-A Pipe Replacement
Business Case Justification Narrative Page 12 of 12
documentation tracks the projects and is the primary device for documenting program decision
making.
As projects are completed, the Distribution Integrity Management Program (DIMP) Aldyl-A
prioritization list is updated annually. As projects are completed, they are removed from the list
and new projects are added and evaluated, as necessary.
Annual spend levels and funds change requests to the Capital Planning Group are maintained
as documentation of program funding and funding changes throughout the year.

The undersigned acknowledge they have reviewed the Gas Facility Replacement
Program (GFRP) and agree with the approach it presents. Significant changes to
this will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date: 7/13/20
Print Name: Karen Cash
Title: GFRP Manager
Role: Business Case Owner

Signature: Date:
Print Name: Mike Faulkenberry
Title: Natural Gas Director
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
7/13/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 242 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 243 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 244 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 245 of 414
Gas Overbuilt Pipe Replacement Program, ER 3006
1 GENERAL INFORMATION
Requested Spend Amount $400,000
Requesting Organization/Department B51 -Gas Engineering
Business Case Owner Jeff Webb I Seth Samsel!
Business Case Sponsor Mike Faulkenberry
Sponsor Organization/Department Gas Operations & Engineering
Category Program
Driver Mandatory & Compliance
ER 3006
1.1 Steering Comm ittee or Advisory Group Information
All the known mobile home parks with overbuilt pipe in Avista's Oregon districts were
catalogued at one time , analyzed and risk ranked as part of the utility's Distribution Integrity
Management Program (DIMP). In addition to these known mobile home parks, with numerous
overbuilt facilities, each local District (including those in Idaho and Washington states)
periodically finds individual locations with newly overbuilt facilities. These projects and the risk
associated with them are mitigated, over time, as part of the Overbuilt Pipe Replacement
Program.
DIMP has the capability to analyze risk (probability and consequence) associated with various
threats to natural gas facilities, including over-built pipe. The DIMP analysis related to overbuilt
segments results in an overall risk score for each of the defined segments. The Overbuilt Pipe
Program Manager and each of the Gas Operations District Managers utilize DIMP risk scoring
to prioritize projects within an approved level of annual program spend. Ideally, overbuilds
would all be addressed as they are encountered, however, there is no compliance
requirement behind the timing in which overbuilds must be eliminated. Avista has historically
managed overbuilt facilities as part of this program and the associated risks along with other
risk priorities in the Company. This is the main reason behind the program's historically
approved funding levels instead of addressing all known overbuilds as a large, individually
funded project. As the number of known overbuilds in the company has decreased, the level
of requested and approved funding has decreased as well. The requested spend level has
historically been determined based upon mitigating a manageable level of overbuilt facilities
across our service territories coupled with any changing costs of construction year to year.
The goal is to manage and prioritize risk associated with overbuilt pipe and complete projects
with the highest risk first. Each Operations District is allotted a manageable portion of the
approved budget based upon project need. The projects for each district are typically
managed locally while the overall program budget is managed by the Program Manager in
Gas Engineering. Image 1 below is a list of the current projects within this program.
Mobile Home Park, Overbuilt Pipe Replacement Program 2/12/2020 Requested Budget: $400,000 $400,000 $400,000 $250,000 $
Approved Budget: $400,000 $400,000 $400,000 $250,000 $
Estimated Costs: $385,000 $410,000 $420,000 $250,000 $480,000
District · Overbuilt Site • Completed? • Estimated Cost • 2020 • 2021 · 2022 • 2023 • 2024 · DIMP Score/ft •
Medford 555 Freeman Rd, Central Point OR No $ 450,000 X X 1930
Medford 301 Freeman Rd, Central Point OR No $ 285,000 X 4145
Medford 2252 Table Rock, Medford OR No $ 325.000 X 3485
Medford 2335 Table Rock, Medford OR No $ 135,000 X 2894
Medford 3555 S Pacific, Medford OR No s 480,000 X 1400
Medford 4425 W Main St, Medford OR No $ 15.000 X 717
Klamath Falls Klamath Falls General Overbuilds No $ 35,000 X X X X
RoseburR RoseburR General Overbuilds No $ 20,000 X X X X
La Grande La Grande General Overbuilds No s 30,000 X X X X
Image 1 -List of current projects within this Program
Business Case Justification Narrative Page 1 of 4
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 246 of 414
Gas Overbuilt Pipe Replacement Program, ER 3006
2 BUSINESS PROBLEM
As a natural gas distribution system operator, Avista is required to operate within the minimum
safety standards outlined in Part 192 of the Department of Transportation's Code of Federal
Regulations (CFR). The CFR defines the laws that all operators must legally comply with in
the operation of natural gas distribution systems. There are sections of existing gas piping
within Avista's gas distribution system that have experienced encroachment or have been
overbuilt by customer constructed improvements (i.e. living structures, sheds, decks, etc.) and
were not designed to be installed under these conditions. In these circumstances, it is difficult
to operate and maintain these facilities without increased risk or a reduction in overall safety.
Overbuilt facilities restrict company access to the pipe resulting in accessibility issues. If
facilities were not designed for overbuilt conditions it can result in the inability to perform
certain maintenance activities required by CFR such as meter inspections or leakage survey.
Leakage surveys are typically performed by walking directly above the gas facilities while
operating leak detection equipment. This maintenance becomes impossible if access to the
ground above the facility becomes hindered. Overbuilds not originally designed to be in an
overbuilt condition are also a violation of the CFR for an overbuilt facility as they do not meet
code requirements for installation within a sealed conduit that can be vented outside of the
overlying structure.
Overbuilds present an increased risk to customers due to the threat that gas can get
entrapped inside of a structure, which increases the potential for an unsafe atmosphere to
develop as well as result in potential ignition which could be catastrophic to life and property.
Multiple factors impact risk and the replacement of these facilities, but of primary concern is
the increased risk hazard due to a leak. Overbuilds increase operations and maintenance
costs as Avista is often required to return to overbuild locations multiple times to attempt and
complete leak survey and other maintenance tasks that cannot be completed at the normal
scheduled time due to the overbuild.
Addressing overbuilt pipe in mobile home parks is where the highest risk and greatest quantity
of overbuilt facilities exist due to the dynamic nature of these facilities. However, overbuilds
are not isolated to mobile home parks and the need potentially exists for this program to be
utilized in all of Avista's service territories.
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Cost Start Complete
Option 1 -Do nothing/defer project $0 N/A
Option 2 -Preferred Solution/Complete $400,000 January December
programmatic replacement of overbuilt
sections of pipe
Option 3 -Alternate Solution $200,000 January December
#1/Reduced Funding Option: Complete
programmatic replacement of overbuilt
sections of pipe at a reduced rate
Option 4 -Alternate Solution #2/Attempt Unknown Unknown Unknown
to enforce Avista's easement rights
Business Case Justification Narrative Page 2 of4
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 247 of 414
Gas Overbuilt Pipe Replacement Program, ER 3006
Option 1 -Do nothing/Defer project
Under this alternative Avista would continue to operate overbuilt facilities without replacement.
There is significant risk associated with not remediating these facilities at all and this would be
a violation of the Code of Federal Regulations subjecting Avista to potential State and Federal
fines associated with operating facilities that are out of compliance. The financial impact of this
alternative is very difficult to estimate as penalties for non-compliance are on a case by case
basis. Known risks cannot be mitigated without replacement of these facilities or remediation
of the overbuild condition. This option is not recommended.
Option 2 -Preferred Solution/Complete programmatic replacement of overbuilt sections of
pipe
It is recommended as part of a programmatic approach to identify and replace sections of
existing pipes that can no longer be operated safely as they have experienced encroachment
or have been overbuilt by customer constructed improvements. Since there is no required
compliance timeline for mitigation of overbuilt facilities, completing this type of work as part of
a program will allow for Avista to manage the risk overall and prioritize overbuilt facilities
based upon those instances with the highest risk to customers as well as operationally. This
methodology is also more proactive and is anticipated to have less overall cost impact than by
addressing each specific issue as it is encountered or addressing all know overbuilds at one
time as an individually funded project. This program aligns with Avista's organizational focus
to operate safe and reliable infrastructure for all of our customers in each of our service
territories.
The current funding level balances available manpower with other programs administered at
the District Offices and allows crews to also work on other compliance and risk reduction type
activities. Annual levels of spending may need to be adjusted in this program as the risks in
DIMP are reassessed annually.
Option 3 -Alternative Solution #1/Reduced funding option: Complete programmatic
replacement of overbuilt sections of pipe at a reduced rate
Another option is to approach the risk associated with overbuilds with reduced funding.
Reduced funding will result in replacement of fewer sections of overbuilt piping. The reduced
funding alternative would still allow us a benefit by addressing some of the overbuilt facilities
with known risk, but at a pace slower than we feel appropriate to address these safety
concerns and maintain compliance. The outcome, should this option be selected, would result
in the continued operation of facilities known to be out of compliance and which are currently
operating with higher risk to customers and operations personnel. Additionally, Avista is often
required to return to an overbuild location multiple times in attempt and complete a leak survey
or other maintenance tasks that cannot be completed due to the overbuild. This will continue
to result in increased operations & maintenance related costs. This option would be a partial
employment of both Options 1 and 2 and is not recommended.
Option 4 -Alternative Solution #2/Enforce Avista's easement rights.
A final option to this program is to attempt to enforce Avista's "rights" and try to force the
owners, renters, or mobile home parks owners to be liable for these fixes, however the original
piping in these locations typically has weak or no easement protection. The ability to prove
that the existing customer was responsible for the overbuild can be difficult and sometimes
impossible. Avista has experienced in the past that attempts to force customer to pay for these
modifications are difficult and often legal fees approach the cost of the work. Legal actions
often take an extensive time and resource commitment. Additionally the negative public
relations associated with such a philosophy would be very difficult to overcome. This option is
not recommended.
Business Case Justification Narrative Page 3 of4
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 248 of 414
Gas Overbuilt Pipe Replacement Program, ER 3006
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Overbuilt Pipe Replacement
Business Case and agree with the approach it presents and that it has been approved by the
steering committee or other governance body identified in Section 1.1. The undersigned also
acknowledge that significant changes to this will be coordinated with and approved by the
undersigned or their designated representatives.
Signature:
Jeff Web~t1(,,,I/ Print Name:
Date: Z----l?-zo
Title: Manager Gas Engineering
Role: Business Case Owner
Signature:
Mik~ Print Name:
Date:
Title: Director of Natural Gas
Role: Business Case Sponsor
5 VERSION HISTORY
Version# Implemented Revision Approved Approval Reason
By Date By Date
1.0 Seth Samsell 04/17/2017 Jeff Webb 04/17/2017 Initial version
2.0 Seth Samsell 02/12/2020 Jeff Webb Revised for 2020 Oregon
GRC Filing
Template Version: 02/24/2017
Business Case Justification Narrative Page 4 of 4
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 249 of 414
Gas PMC Program, ER 3055
Business Case Justification Narrative Page 1 of 7
EXECUTIVE SUMMARY

Avista is required by state commission rules and tariffs in WA, ID, and OR to annually
test gas meters for accuracy and ensure proper metering performance. Execution of this
program on an annual basis ensures the continuation of reliable gas measurement for
our customers and compliance with the applicable state tariffs.
The Planned Meter Change-out (PMC) Program uses a statistical sampling
methodology based on ANSI Z1.9 “Sampling Procedures and Tables for Inspection by
Variables for Percent Nonconforming”. Sample sizes and acceptance criteria are
defined in the ANSI standard. The annual test results of gas meters that have been
removed from the field are analyzed and a determination of the accuracy of each meter
family is made. If the analytics determine a meter family (defined as a manufacturer
year and model/size) is no longer metering accurately enough to meet the tariff, then
that entire meter family will be replaced. Conversely, if the analytics determine a meter
family is testing well (close to 100% accurate), the sample size (number of meters in
that family required to be tested) can be reduced. These analytics help control costs
and remove meters quickly that are not performing well.
This program includes only the labor and minor materials associated with the PMC
Program. Major materials (meters, pressure regulators, and Encoder Receiver
Transmitter (ERT)) will be charged to the appropriate Gas Growth Programs. The
annual cost for the program varies depending on the results of the previous year’s
statistical analysis. On average approximately 6,000 meters are removed for this
program resulting in an average cost of $1,500,000 ($250/meter).

VERSION HISTORY
Version Author Description Date Notes
1.0 Jeff Webb Initial Version 03/16/2017
1.1 Jeff Webb 04/07/2017
2.0 Dave Smith Revised for 2020 Oregon
GRC filing
2/17/2020
2.1 Smith-Webb
Updated to the refreshed
2020 Business Case
template
7/10/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 250 of 414
Gas PMC Program, ER 3055
Business Case Justification Narrative Page 2 of 7
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Avista is required by state commission rules and tariffs in WA, ID, and OR to test
meters for accuracy and ensure proper metering performance. Execution of this
program on an annual basis ensures the continuation of reliable gas measurement
and compliance with the applicable tariffs.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer.
This program is a mandatory requirement to be in compliance with state
commission rules and tariffs in WA, ID, and OR.
The following state rules regulate Avista’s PMC Program:
Oregon:
o OAC 860-023-0015 “Testing Gas and Electric Meters”
o Tariff Rule #18
Idaho:
o IDAPA 31.31.01.151 through .157 “Standards for Service”
Washington:
o WAC Chapter 480-90-333 through -348 “Gas companies – Operations”
o Tariff Rule #170
Our customers benefit from this program because it assures that natural gas use
is measured accurately in all jurisdictions.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred.
Avista would not be in compliance with state commission rules and tariffs in WA,
ID, and OR if this program is not completed annually.
Requested Spend Amount $1,500,000
Requested Spend Time Period Annually
Requesting Organization/Department Gas Engineering
Business Case Owner | Sponsor Jeff Webb/Dave Smith | Mike Faulkenberry
Sponsor Organization/Department B51 – Gas Engineering
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 251 of 414
Gas PMC Program, ER 3055
Business Case Justification Narrative Page 3 of 7
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The PMC Program uses a statistical sampling methodology based on ANSI Z1.9
“Sampling Procedures and Tables for Inspection by Variables for Percent
Nonconforming”. Sample sizes and acceptance criteria are defined in the ANSI
standard. The annual test results of gas meters that have been removed from the
field are analyzed and a determination of the accuracy of each meter family is
made. If the analytics determine a meter family (defined as a manufacturer year
and model/size) is no longer metering accurately enough to meet the tariff, then
that entire meter family will be replaced. Conversely, if the analytics determine a
meter family is testing well (close to 100% accurate), the sample size (number of
meters in that family required to be tested) can be reduced. These analytics help
control costs and remove meters quickly that are not performing well.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem.
• Gas PMC Program Standard Operating Procedure
• ANZI Z1.9 “Sampling Procedures and Tables for Inspection by Variables for
Percent Nonconforming”
• The following state rules regulate the PMC program:
Oregon:
o OAC 860-023-0015 “Testing Gas and Electric Meters”
o Tariff Rule #18
Idaho:
o IDAPA 31.31.01.151 through .157 “Standards for Service”
Washington:
o WAC Chapter 480-90-333 through -348 “Gas companies – Operations”
o Tariff Rule #170
These documents are saved on the Avista network drive c01d44 and can be made
available upon request.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
The meter accuracy testing results collected annually from the program are
documented in an Excel spreadsheet. This spreadsheet performs calculations
based on ANSI Z1.9 to determine the following year’s sampling requirements and
identify which meter families do not meet the accuracy standards and must be
removed.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 252 of 414
Gas PMC Program, ER 3055
Business Case Justification Narrative Page 4 of 7
The recommended solution is to complete this mandatory programmatic work.
Completion of this program will keep Avista in compliance with state rules and
tariffs and assure that our customers’ natural gas use is measured accurately.
Partial completion of this program will result in Avista being out of compliance with
state rules and tariffs.

Option Capital Cost Start Complete
Recommended Solution, Fully complete the
programmatic work described
$1,500,000 January December
2.1 Describe what metrics, data, analysis or information was considered
when preparing this capital request.

Historical program costs are used to determine the average labor costs to remove
and test each meter. The number of meters required to be removed varies each
year depending on the previous year’s testing results. The average cost per meter
is then multiplied by the anticipated number of meters to be removed to determine
the estimated program cost for the following year.
2.2 Discuss how the requested capital cost amount will be spent in the
current year (or future years if a multi-year or ongoing initiative). (i.e. what
are the expected functions, processes or deliverables that will result from the capital spend?).
Include any known or estimated reductions to O&M as a result of this
investment.
The program is completed between January and December of each year.
Gas Engineering, Gas Operations, Gas Meter Shop, and Technical Services work
together to administer the PMC program. Gas Operations and the Gas Meter
Shop remove the meters from the customer’s premise and install new ones. If a
large meter family fails Avista may hire a contractor to assist in the removal of the
meters. The Gas Meter Shop completes physical calibration tests on the meters
and the Technical Services group then analyzes the test results at the end of the
year to determine the status of each family of gas meters. The results of this
analysis will define the meter removal and testing requirements for the following
year. Gas Engineering develops an annual report which is made available to the
state commissions upon request.
Completion of this program may result in a reduction to O&M because there may
be less high bill complaints from customers as a result of inaccurate meters.
2.3 Outline any business functions and processes that may be impacted
(and how) by the business case for it to be successfully implemented.
Replacing gas meters is not a new process for Avista. Existing processes and
technologies will be utilized for this program.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 253 of 414
Gas PMC Program, ER 3055
Business Case Justification Narrative Page 5 of 7
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The only alternatives are to either partially fund this program or to not fund it at all.
If this program were not completed fully Avista would be out of compliance with
state rules and tariffs and could be exposed to fines from the various state utility
commissions. Also, the accuracy of measurement of our customers’ natural gas
usage could not be assured.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the
customer.
The program will be completed between January and December of each year.
The gas meters are purchased as a pre-capital material item under ER 1050 (Gas
Meters). The meter will become used and useful upon installation.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This program aligns with Avista’s organizational focus to maintain a safe and
reliable infrastructure to achieve optimum life-cycle performance, safely, reliably,
and at a fair price for our customers.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project.
This program must be completed to ensure our customer’s meters remain
accurate throughout their service life. Accuracy data is obtained and analyzed
each year to ensure the program is testing the appropriate number of meters and
removing ones that no longer meet Avista’s accuracy requirements.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business
case.
All Avista natural gas customers benefit from this program because it ensures their
gas meters remain accurate throughout their service life.
Business case stakeholders include Gas Engineering, Gas Operations, Gas Meter
Shop, Technical Services, and state commissions.

2.8.2 Identify any related Business Cases
ER 1050 Gas Meters

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 254 of 414
Gas PMC Program, ER 3055
Business Case Justification Narrative Page 6 of 7
3.1 Steering Committee or Advisory Group Information
Gas Engineering is ultimately responsible for the PMC plan and annual reports
that are developed and made available to each of the state commissions.

3.2 Provide and discuss the governance processes and people that will
provide oversight.

Gas Engineering, Gas Operations, Gas Meter Shop, and Technical Services work
together to administer the PMC program and ensure compliance with the various
state rules and tariffs related to gas meter testing.

3.3 How will decision-making, prioritization, and change requests be
documented and monitored.
Meter accuracy testing results are compiled and analyzed in a spreadsheet. An
annual report is developed by Gas Engineering and made available to the state
commissions upon request. This report defines the program requirements for the
following year.
The undersigned acknowledge they have reviewed the Gas PMC Program, ER
3055 and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Print Name: Jeffrey A Webb
Title: Mgr Gas Engineering
Role: Business Case Owner

Signature: Date:
Print Name: Michael J Faulkenberry
Title: Director Natural Gas
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
7/10/2020
7/10/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 255 of 414
Gas PMC Program, ER 3055
Business Case Justification Narrative Page 7 of 7
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 256 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 257 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 258 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 259 of 414
Gas HP Pipeline Remediation Program, ER 3057
1 GENERAL INFORMATION
Requested Spend Amount $3,000,000
Requesting Organization/Department Gas Engineering
Business Case Owner Jeff Webb, David Smith
Business Gase Sponsor Mike Faulkenberry
Sponsor Organization/Department 851 - Gas Engineering
Category Program
Driver Mandatory & Compliance
1.1 Steering Committee or Advisory Group lnformation
The Gas Compliance department is responsible for ensuring Avista is compliant
with Federal and State Regulations governing the distribution of natural gas.
When a new regulation is brought into effect, the Gas Compliance department will
determine if Avista is meeting the requirement or not. lf the new requirement is
not being met, the Gas Compliance department will notify the appropriate work
group and work with them to determine the appropriate path forward to ensure
compliance. Gas Engineering is responsible for managing this program.
2 BUSINESS PROBLEM
Current industry Pipeline Safety code requires pipeline operators to have pressure
test documentation and material specifications for pipelines distributing natural
gas. Avista has some deficiencies in these types of records, but industry
regulators (state inspectors) historically have not placed much emphasis on this,
specifically for facilities that operate at lower stress Ievels and therefore at a lesser
risk to the public. Avista's history, very similar to that of other utilities, involves
pipeline construction during times when the pipeline safety code was not in effect
or taken to be that important. Also, Avista has acquired properties from other
companies and therefore had no control over their testing practices and record
keeping prior to the acquisition. The regulatory climate is now changing and more
scrutiny is being placed on having these records.
The Pipeline and Hazardous Materials Safety Administration (PHMSA) is actively
working on a new rule that is expected to be published in December o12017 called
"Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines". When
implemented, it will require pipeline operators to have "traceable, verifiable, and
complete" Maximum Allowable Operating Pressure (MAOP) records for its
transmission facilities. Our understanding of the Rule is that Avista will now need
to begin aggressively addressing portions of our system in order to be in
compliance. Until the Rule is published, it is not clear yet what the timeframe will
be to create a plan and mitigate all deficiencies.
Business Case Justification Narrative Page 1 of3
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 260 of 414
Gas HP Pip eline Remediation Program, ER 3057
3 PROPOSAL AND RECOMMENDED SOLUTION
Optlon Capltal Coet Start Complets
Option 1 - Do nothing / Defer project $o
Option 2 - Preferred Solution,
Continue to remediate segments of
high pressure pipeline.
$3,000,000 2016 2022
Option 3 - Alternative Solution,
Reduced funding option: Replace
segments of high pressure pipeline.
$1,500,000 2016 2022
Option 1 - Do nothing / Defer project.
lf segments of transmission pipeline without traceable, verifiable, and complete
MAOP records are not mitigated, Avista will be non-compliant with Federal
Pipeline Safety Codes, especially when the Rule mentioned above becomes final
lf the work in this program is not completed, Avista will be going against industry
guidance and trends. Once the Federal Rules become final, penalties and fines
may be imposed for not completing this work.
Option 2 - Preferred Solution, Continue to remediate segments of high pressure
pipeline.
As stated above, the proposed Federal Rule will force action to address lack of
sufficient MAOP records. Transmission pipelines without traceable, verifiable, and
complete MAOP records will be replaced or mitigated within this program.
Reasons for this work will include, but are not limited to; incomplete construction
and pressure test documents, pipe quality deficiencies from the manufacturing
process, and risk reduction in densely populated areas. As a result of completing
this option, public and employee safety will be improved by replacing at risk pipe.
Officials and spokesmen from both PHMSA and the American Gas Association
(AGA) have stated it is not prudent for operators to wait for the Federal Rule to
become finalized before bettering their systems in this category of work. Avista
has been in the process of remediating pipelines under this program since 2015
lncidentally, many of these facilities have been in service for over 30 years.
Depending on the final language of the Rule, the annual levels of spending may
need to be adjusted in this program. However, as best as Avista is able to tell at
this time, what is proposed is the correct pace to complete this Program. The
current rate of work is reasonable with Avista's Engineering and construction
workforces.
Avista will address replacement or mitigation of its pipelines in the order of highest
operating stress and highest levels of record deficiencies. This program will be
prioritized in all three of its natural gas operating states and will analyze risks and
Business Case Justiflcation Narrative Page 2 of 3
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 261 of 414
Gas HP Pipelin e Remediation Program, ER 3057
priorities regardless of jurisdiction. The projects in 2017 will likely all be in Oregon.
Replacement projects in 2018 and beyond have not yet been determined.
Option 3 - Altemative Solution, Reduced funding option: Replace segments of
high pressure pipeline.
Reduced funding will result in replacing fewer pipeline segments with insufficient
MAOP records. This will be at a pace slower than has been accomplished
historically and slower than what we feel is the ideal rate as described above. The
outcome, should this option be selected, may be pipeline segments being out of
compliance with Federal Regulations and a greater amount of backlog to work
through once the Rule is published.
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas HP Pipeline
Remediation Business Case and agree with the approach it presents and that it has
been approved by the steering committee or other governance body identified in
Section 1.1. The undersigned also acknowledge that significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
clM Date:l-r z-r7
Date: L1 -?
--ryffiw"bb
Manager Gas Engineering
Business Case Owner
Director of Natural
Business Case Sponsor
5 VERSION HISTORY
Tem plate Version : 02124 12017
[Vorclon#
lmplemented
By
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Dato
Approved
Bv
Approval
Date
Roason
1.0 Dave Smith 03t09t2017 Mike
Faulkenberry
041't7t2017 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 262 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 263 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 264 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 265 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 266 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 267 of 414
Gas Regulator Station Replacement Program, ER 3002
Business Case Justification Narrative Page 1 of 2
EXECUTIVE SUMMARY

This annual program will replace or upgrade existing at-risk Gate Stations, Regulator
Stations and Industrial Meter Sets (“stations”) located throughout Avista’s gas territory in
WA, ID, and OR that are at the end of their service life and/or not up to current Avista
standards. Additionally, it will address enhancements that will improve system operating
performance, enhance safety, replace inadequate or antiquated equipment that is no
longer supported, and ensure the reliable operation of metering and regulating
equipment.
These stations require annual maintenance per 49 CFR 192.739 and if the equipment at
the station is obsolete and replacement/maintenance parts are no longer available, then
proper maintenance cannot be completed. Incomplete maintenance could cause Avista
to be out of compliance and be exposed to fines from the various state utility
commissions.
Avista’s gas customers from all jurisdictions benefit from these types of projects by
having a safer, more reliable, well maintained distribution system. Also, this is a prudent
way to spend resources because many deficiencies at a station can be remedied under
just one project.
Annual cost to fund this program is $1,000,000.

VERSION HISTORY
Version Author Description Date Notes
1.0 Jeff Webb Initial version 3/17/2017
1.1 Jeff Webb 4/07/2017
2.0 Jeff Webb Revised for 2020 Oregon GRC
filing
2/17/2020
2.1 Smith-Webb Updated to the refreshed 2020
Business Case template 7/10/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 268 of 414
Gas Regulator Station Replacement Program, ER 3002
Business Case Justification Narrative Page 2 of 3
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Existing stations located throughout Avista’s gas territory in WA, ID, and OR have
a finite service life and will eventually no longer meet Avista’s current design
standards, may feature obsolete equipment, or may develop operational or safety
issues that need addressed in order to delivery safe and reliable gas service to
customers.
Another category of work in this program is moving regulator stations located
underground in a vault to a more traditional above ground configuration. Stations
located in vaults are difficult to maintain because of the limited working room for
tools and workers. Additionally, water in the vault can make maintenance more
difficult. Regulator Stations in a vault are also a safety concern as they are
confined spaces and can trap harmful levels of natural gas should a leak be
present.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer.
This program’s primary driver is asset condition. By replacing obsolete stations,
we will continue to deliver safe and reliable gas service to customers.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred.
This work is needed now because there is already a backlog of stations needing
replacement. The list of stations needing replacement continues to grow as
stations meet the end of their service life. Postponing the work will cause the list
of stations needing replacement to outpace the number of stations remediated.
Requested Spend Amount $1,000,000
Requested Spend Time Period Annually
Requesting Organization/Department B51 – Gas Engineering
Business Case Owner | Sponsor Jeff Webb/Dave Smith | Mike Faulkenberry
Sponsor Organization/Department B51 – Gas Engineering
Phase Execution
Category Program
Driver Asset Condition
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 269 of 414
Gas Regulator Station Replacement Program, ER 3002
Business Case Justification Narrative Page 3 of 4
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The success of the program can be measured by the completion of station
replacement projects. These stations are a vital link to providing gas service and
replacing obsolete stations will help Avista continue to deliver safe and reliable gas
service to customers.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem.
A master list of stations with reported deficiencies is maintained by Gas Engineering
and is shown below.
Image 1 – Master List of Stations with Deficiencies
This list saved on the Avista network drive c01d44 and can be made available upon
request.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
The master list of stations with reported deficiencies referenced in section 1.5.1
summarizes the issues at each station.
The requested level of spending for this program allows the high priority projects to
be completed every year. The list of new requests continues to grow as stations
meet the end of their service life. At this pace, the number of stations remediated
will slowly outpace the number added each year. The workforce available to do
this type of work is responsible for both maintenance of these stations and the
rebuild efforts. This level of spend complements their available time well without
requiring additional headcount.
Since these stations are a vital link to providing customers with reliable gas,
planned work is better than unplanned work. Unplanned work during times of high
gas use (normally the winter) can be more difficult to perform and have negative
impacts to customers if it fails to operate properly.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 270 of 414
Gas Regulator Station Replacement Program, ER 3002
Business Case Justification Narrative Page 4 of 5
Option Capital Cost Start Complete
Recommended Solution, Replace at risk stations at
requested funding level
$1,000,000 January December
Alternative Solution, Replace at risk stations at a
reduced funding level
$500,000 January December

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
A master list of stations with reported deficiencies is maintained by Gas
Engineering. Each year this list is evaluated by subject matter experts in Gas
Engineering and Gas Operations and the stations are prioritized by risk level.
Stations with the highest risk level are selected for completion while others are
deferred to future years. The workforce available to do this type of work is
responsible for both maintenance of these stations and the rebuild efforts. The
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 271 of 414
Gas Regulator Station Replacement Program, ER 3002
Business Case Justification Narrative Page 5 of 6
requested level of spend in the Recommended Solution complements their
available time well without requiring additional headcount.

Image 2 – Partial list of of stations ranked by priority
(only 2020-2021 are shown)
2.2 Discuss how the requested capital cost amount will be spent in the
current year (or future years if a multi-year or ongoing initiative). (i.e. what
are the expected functions, processes or deliverables that will result from the capital spend?).
Include any known or estimated reductions to O&M as a result of this
investment.
Gas Engineering, Gas Operations, and the Gas Meter Shop work together to
prioritize and administer the work for the year. The work is generally
prioritized early in the year and then implemented throughout the spring,
summer, and fall. The work is typically comprised of several individual station
replacement projects.
Completion of this work may reduce unplanned O&M costs because obsolete
stations are being removed from the system resulting in an increase in the
overall reliability of the gas distribution system.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Gas Operations rely on station replacement projects as a vital part of their work.
The current level of spend complements their available time to do this work
without requiring additional headcount.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 272 of 414
Gas Regulator Station Replacement Program, ER 3002
Business Case Justification Narrative Page 6 of 7
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
There are two outcomes if this program is funded at a reduced rate. One is to
replace fewer regulator stations and industrial meter sets. There is already a
backlog of high-risk stations to be replaced, so this approach would take an
even longer time to get through that backlog while new stations are continually
added to the list every year. Secondly, an alternative to rebuilding the entire
station would be to replace only the individual components that are antiquated
or outdated. If this short-sided course were chosen, the work would be less
productive and the opportunity to bring the entire station up to current
standards would be lost. This option is not recommended.
If the program were to not be funded, Avista would be forced to operate at-risk
stations in an unsafe, unreliable, and sometimes non-code compliant manner.
O&M costs would escalate as the number of unplanned visits to these stations
would likely increase due to operating them at or beyond their useful lives.
This option is not recommended.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the
customer. spend, and transfers to plant by year.
The program will be completed between January and December of each year.
The investments become used and useful to the customer at the completion of
each station rebuild project.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This program aligns with Avista’s organizational focus to maintain a safe and
reliable infrastructure to achieve optimum life-cycle performance, safely,
reliably, and at a fair price for our customers.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project.
The requested funding level is prudent to continue to serve safe and reliable
gas service to customers. A master list of stations with reported deficiencies is
maintained by Gas Engineering. Each year this list is evaluated by subject
matter experts in Gas Engineering and Gas Operations and the stations are
prioritized by risk level. Stations with the highest risk level are selected for
completion while others are deferred to future years. The workforce available
to do this type of work is responsible for both maintenance of these stations
and the rebuild efforts. This level of spend complements their available time
well without requiring additional headcount.
2.8 Supplemental Information

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 273 of 414
Gas Regulator Station Replacement Program, ER 3002
Business Case Justification Narrative Page 7 of 8
2.8.1 Identify customers and stakeholders that interface with the business
case.
Avista gas customers in WA, ID, and OR benefit from this program as these
stations are utilized in all territories to deliver safe and reliable gas service.
Stakeholders including Gas Engineering, Gas Operations, and the Gas Meter
Shop work together to ensure a successful program execution.
2.8.2 Identify any related Business Cases.
N/A.
Steering Committee or Advisory Group Information
Gas Engineering is ultimately responsible for prioritizing the projects and reporting
out financial updates to the Capital Project Group.
2.10 Provide and discuss the governance processes and people that will
provide oversight.
Gas Engineering, Gas Operations, and the Gas Meter Shop work together to
administer this program. Year to date spend and budget updates are reviewed
monthly. Annually, the Gas Engineering Prioritization Investment Committee
(EPIC) reviews the 5-year plan and ensures the budget level is appropriate given
other categories of work and risk on the gas system.
2.11 How will decision-making, prioritization, and change requests be
documented and monitored.
A master list of Regulator Stations and Industrial Meter Sets with reported
deficiencies is maintained by Gas Engineering. Gas Operations and the Gas
Meter Shop report concerns while performing regular maintenance and these
deficiencies are collected on the master list. Annually, subject matter experts from
Gas Operations and Gas Engineering review the master list and risk rank the work
for the following year. Stations with the highest risk (typically due to multiple
different concerns) are prioritized over stations with only minor issues. Prioritizing
this work annually with the subject matter experts provides a consistent approach.
Through this process, the highest risk projects are selected to be funded. The
spend for each individual project that falls under this ER is monitored on a monthly
basis by the Project Engineers. Changes to the total annual spend for this ER is
monitored by the business case owner.
The undersigned acknowledge they have reviewed the Gas Regulator Station
Replacement Program, ER 3002 and agree with the approach it presents.
Significant changes to this will be coordinated with and approved by the
undersigned or their designated representatives.

Signature: Date: 7/10/2020
Print Name: Jeffrey A Webb
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 274 of 414
Gas Regulator Station Replacement Program, ER 3002
Business Case Justification Narrative Page 8 of 8
Title: Mgr Gas Engineering
Role: Business Case Owner

Signature: Date: 7/10/2020
Print Name: Michael J Faulkenberry
Title: Director Natural Gas
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 275 of 414
Gas Rathdrum Prairie HP Gas Reinforcement, ER 3301
1 GENERAL INFORMATION
Requested Spend Amount $10,000,000
Requesting Organization/Department Gas Engineering
Business Case Owner Jeff Webb, David Smith
Business Case Sponsor Mike Faulkenberry
Sponsor Organization/Department 851 -Gas Engineering
Category Project
Driver Performance & Capacity
1.1 Steering Committee or Advisory Group Information
The Gas Planning department routinely runs an analysis (load study) on Avista's
gas distribution system to identify areas of the system with insufficient capacity to
serve existing Firm customer loads on a design day (Avista defines design day as
the projected system demand for a "coldest day on record" weather event). These
deficient areas are given a priority level based on the severity of the risk
associated with insufficient system capacity. The areas with the highest priority are
selected for remediation and the project is assigned to Gas Engineering to
evaluate options to provide sufficient capacity to meet Firm gas demands on a
design day. Options are reviewed with Gas Planning, Gas Operations, and other
interested parties. The pros and cons of each option are then reviewed with the
Gas Engineering Manager and a preferred alternative is selected to proceed with a
funding request.
2 BUSINESS PROBLEM
Based on load studies performed by the Gas Planning department, load growth on
the Williams Northwest Pipeline (NWP) Coeur d'Alene Lateral pipeline has
exceeded both Avista's contractual delivery amounts as well as the physical
capacity of the NWP Coeur d'Alene Lateral pipeline. In addition, the distribution
system in the Hayden Lake, Idaho area will experience insufficient pressure during
periods of peak demand on a design day. Sufficient capacity is defined as
pressures at or above 15 pounds per square inch (psig) in the distribution system
on a design day analysis. Without a reinforcement project, Avista will not have
sufficient capacity to serve Firm customer load in the Coeur d'Alene, ID to Kellogg,
ID corridor on a design day scenario.
Business Case Justification Narrative Page 1 of 5
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 276 of 414
Gas Rathdrum Prairie HP Gas Reinforcement, ER 3301
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Start Complete
Cost
Option 1 -Do nothing $0
Option 2 -Preferred Solution, Avista to $10,000,000 11/2015 12/2018
construct approximately six miles of high
pressure distribution pipeline in two
phases to reinforce the distribution
system in the greater Post Falls and
Coeur d'Alene area.
Option 3 -Alternative Solution, $10,000,000 11/2015 12/2019
Compensate Williams Northwest Pipeline
(NWP) for a mainline expansion of their
Coeur d'Alene Lateral pipeline.
Option 1 -Do nothing
Without a reinforcement project Avista does not have sufficient capacity to serve
existing Firm customer load in the Coeur d'Alene, ID to Kellogg, ID corridor on a
design day scenario, and cannot support any future customer growth. See Image
1 below for a load study analysis showing the Hayden Lake area distribution
system with insufficient capacity. Approximately 3900 customers are at risk of
losing their gas service during a cold weather event.
It is important to note that if service is lost during severe cold weather, gas service
may not become available again until weather warms and customer demand
decreases. Depending on the length of the outage, this can cause severe injury up
to and including death to some customers.
Option 2 -Preferred Solution, Avista to construct approximately six miles of high
pressure distribution pipeline in two phases to reinforce the distribution system in
the greater Post Falls and Coeur d'Alene area.
This option capitalizes on the capacity available from the recently constructed
Chase Road Gate Station (supply point into Avista's system) located on the GTN­
TransCanada (GTN) pipeline. This option consists of a multi-year project
comprised of a two phase high pressure distribution pipeline reinforcement that will
shift gas usage from NWP to GTN, and will also allow Avista to choose a portion of
gas nominations from either NWP or GTN to take advantage of price differentials.
This additional capacity will be used to support customer growth in the Post Falls,
ID and Coeur d'Alene, ID area currently served from NWP. This option also
inherently increases system reliability by having two independent interstate
pipeline gas sources, which will reduce the risk of customer outages in the event
of an abnormal operating condition. Another benefit of this option is that it will be
completed approximately one year before Option 3, which will accommodate the
existing needs and support additional customer growth sooner. Phase one and
phase two both consist of installing approximately three miles of 6" high pressure
distribution pipeline and two Regulator Stations (pressure reductions stations)
within Avista's system, with phase one scheduled to be constructed in 2017 and
Business Case Justification Narrative Page 2 of 5
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 277 of 414
Gas Rathdrum Prairie HP Gas Reinforcement, ER 3301
phase two constructed in 2018. See Image 2 below for a load study analysis
showing how the proposed reinforcement provides sufficient capacity to the
Hayden Lake, ID area distribution system.
Option 3 -Alternative Solution, Compensate Williams Northwest Pipeline (NWP)
for a mainline expansion of their Coeur d'Alene Lateral pipeline.
The NWP expansion would include the installation of up to 6 miles of 1 O" pipe
beginning at or near the WA/ID border (west of Post Falls, ID), which involves
investing significant money into the Williams NWP system instead of Avista's
infrastructure. Additionally, Avista would be required to refurbish and expand at
least four Gate Stations (NWP supply point into Avista's system) along the NWP
Coeur d'Alene Lateral to accommodate the projected load growth. This option is
estimated to take 4 years to complete, which does not provide a timely
reinforcement to the deficient Hayden Lake area, nor does it offer timely support of
continued customer growth. Another disadvantage of this option is that Avista
would not gain the ability to have two independent interstate pipeline gas sources
into one of the largest load centers in our system, which would reduce system
reliability in the event of an abnormal operating condition.
Fa<llhlnColorBy:
Pressure (pall)
D o.oo
• 0.01-15,00
D 15,01-ao.oo
• 30,01 -45.00
• 45,01 -II0.00
• >IO.Ol
Image 1 -Distribution System Pressures before Proposed Reinforcement
Business Case Justification Narrative Page 3 of 5
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 278 of 414
Gas Rathdrum Prairie HP Gas Reinforcement, ER 3301
FacllltleaColorBy:
Prellure (P•ltl D o.oo
• 0.01-15.00
D 15.01 -ao.oo
• 30.01 -45.00
• 45,01 -60.00
• >80.01
Image 2 -Distribution System Pressures after Proposed Reinforcement
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Rathdrum Prairie HP
Reinforcement Business Case and agree with the approach it presents and that it
has been approved by the steering committee or other governance body identified
in Section 1.1. The undersigned also acknowledge that significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.
Signature: Date: v -11-11
Print Name:
Title: Manager Gas Engineering
Role: Business Case Owner
Signature: Date:
Print Name:
Title: Director of Natural Gas
Role: Business Case Sponsor
Business Case Justification Narrative Page 4 of 5
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 279 of 414
Gas Rathdrum Prairie HP Gas Reinforcement, ER 3301
5 VERSION HISTORY
[Verslo Implemented Revision Approved App~oval Reason
n# By Date By Date
1.0 Dave Smith 4/17/2017 Initial version
Template Version: 02/24/2017
Business Case Justification Narrative Page 5 of5
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 280 of 414
Gas Reinforcement Program, ER 3000
Business Case Justification Narrative Page 1 of 7
EXECUTIVE SUMMARY

This annual program will identify and provide for necessary capacity reinforcements to
the existing natural gas distribution systems in WA, ID, and OR. Avista has an obligation
to serve existing firm gas customers by providing adequate capacity on design day
conditions. Sufficient capacity is defined as pressures at or above 15 pounds per square
inch (psig) in the distribution system on a design day analysis. Periodic reinforcement of
the system is required to reliably serve firm customers due to increased demand at
existing service locations and new customers being added to the system. Execution of
this program on an annual basis will ensure the continuation of reliable gas service that
is of adequate pressure and capacity.

Typical projects completed under this Business Case may include (but are not limited
to) upsizing existing gas mains, looping existing gas mains (bringing in a second source
to an area), and installing new regulator stations (pressure reduction stations). When a
reinforcement is done by looping a system, there is a secondary benefit of higher
reliability to the area. Most of these projects will have a unique project number assigned
to them, but the lower cost (smaller scope) projects may be completed under the
blanket project numbers set up for each district.

VERSION HISTORY
Version Author Description Date Notes
1.0 Jeff Webb Initial draft version 03/17/2017
1.1 Jeff Webb Business Case Refresh PH 1 04/06/2017
1.2 Jeff Webb Revised for 2020 Oregon GRC filing 2/17/2020
2.0 Harding-Webb Revised V2 Business Case Refresh PH 2 7/10/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 281 of 414
Gas Reinforcement Program, ER 3000
Business Case Justification Narrative Page 2 of 7
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Avista’s gas distribution systems are constantly changing as new customers are
added to the system and other construction activities occur. It is expected that
these systems are able to supply gas to all firm customers during high demand,
including cold ‘Design Day’ conditions. There are certain systems that currently do
not have adequate capacity to meet these needs. Reasons for this can include
increased customer loads, new gas customers being added to the system,
undersized piping, long piping lengths, and undersized valves and regulators.
1.2 Discuss the major drivers of the business case (Customer Requested,
Customer Service Quality & Reliability, Mandatory & Compliance,
Performance & Capacity, Asset Condition, or Failed Plant & Operations) and
the benefits to the customer.
This program is Performance & Capacity related. These reinforcements improve
system capacity and allow un-interrupted service to firm customers. Additionally,
these reinforcements reduce the likelihood of low-pressure outages for all
customers in effected areas.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred.
One of Gas Planning’s responsibilities include the identification of low pressure
areas on our distribution system, low pressure is synonamous with insufficient
capacity. Insufficient capacity can result in a gas outage during a cold weather
event. The impacts of a gas outage is very different than an electric outage. Even
after temperatures warm and pressures have recovered in a gas system, it can
take several days to restore service to customers, because each meter must be
first shut off and then individually turned back on by a serviceman performing a
safety check. To make matters worse, an outage will occur during extremely low
temperature conditions – a very serious safety concern when customers may not
have heat for days. This is a customer safety issue.

Requested Spend Amount $1,300,000
Requested Spend Time Period 1 Year / Perpetual Annual Request
Requesting Organization/Department B51 – Gas Engineering
Business Case Owner | Sponsor Tim Harding - Jeff Webb | Mike Faulkenberry
Sponsor Organization/Department B51 – Gas Engineering
Phase Execution
Category Program
Driver Performance & Capacity
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 282 of 414
Gas Reinforcement Program, ER 3000
Business Case Justification Narrative Page 3 of 7
Additionally, according to tariff language, firm customers are paying for a reliable
fuel source at all times short of a “Force Majure”. Therefore it would be unfair to
have customers paying for firm service while Avista is intentionally operating a
system that cannot meet the intent of the tariff.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Seasonal pressure recorders are placed at key locations in our distribution
systems each winter. These devices record and regularly transmit pressure data
that is reviewed remotely. This monitoring allows the Gas Planning department to
cross-check and calibrate the computer model data with actual system pressures.
By doing this, they are better able to suggest new reinforcements, while also
verifying improved performance from previously installed reinforcements.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the
problem.
Load studies, using computer models are run annually. Their findings are best
reviewed graphically and are too numerous to display in this document. Gas
Planning stores copies of load study results.
1.5.2 For asset replacement, include graphical or narrative
representation of metrics associated with the current condition of
the asset that is proposed for replacement.
Sample Reinforcement Priority List:
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 283 of 414
Gas Reinforcement Program, ER 3000
Business Case Justification Narrative Page 4 of 7

Option Capital Cost Start Complete
Proposal / Recommended Solution – Strategically
install assets
$1,300,000 01 2020 12 2020
Alternative Solution – Reduced funding option:
Strategically install assets with reduced funding
level
$800,000 01 2020 12 2020
2.1 Describe what metrics, data, analysis or information was considered
when preparing this capital request.

The current budget request is based on past historical spending. This is a
reasonable amount of construction work to divide between Engineering and
Operations resources. There continues to be about a 6 year backlog of high
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 284 of 414
Gas Reinforcement Program, ER 3000
Business Case Justification Narrative Page 5 of 7
and medioum priority projects within this program. A reduced budget will
increase the backlog and increase the risk of low-pressure outages.
2.2 Discuss how the requested capital cost amount will be spent in the
current year (or future years if a multi-year or ongoing initiative). (i.e.
what are the expected functions, processes or deliverables that will result from
the capital spend?). Include any known or estimated reductions to O&M as
a result of this investment.
The money spent for this budget goes directly to the design and installation of
new assets. Installations typically happen in Q2, Q3 and Q4 across all three
states.
2.3 Outline any business functions and processes that may be impacted
(and how) by the business case for it to be successfully implemented.
N/A
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Alternatives include halting reinforcement efforts, or reducing program funding.
Failing to meet firm customer demand, resulting in customer outages due to
low pressure conditions are circumstances that Avista needs to avoid. These
situations can have financial implications for the Company, reduced levels of
Customer Experience, and legitimate safety concerns for vulnerable
customers.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the
customer.
These projects typically take place in Q2, Q3, and Q4. The assets become
used and useful upon installation and are transferred to plant soon after
completion.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Reinforcement projects allow the natural gas system to operate safely and
reliably, meeting customer demands during all reasonable conditions.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project.
As the gas systems expand and customer growth continues, there continues
to be a need for capacity reinforcements. Projects will be reviewed and
prioritized on an annual basis by Gas Planning.

When reinforcements are successfully installed, the risk for customer outages
due to low pressure conditions are greatly reduced. This positively impacts
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 285 of 414
Gas Reinforcement Program, ER 3000
Business Case Justification Narrative Page 6 of 7
the Pressure Controlmen and Servicemen groups because of the reduced
number of incidents they must respond to.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the
business case.
This program touches on all service territories that Avista serves. Construction
of these projects is done by both contractors, as well as in-house crews.
Design duties are split between Gas Engineering and local CPCs. All Avista
gas customer are stakeholders in these projects.
2.8.2 Identify any related Business Cases.
N/A
3.1 Steering Committee or Advisory Group Information.
The Steering Committee/Advisory Group for this program consists of Gas Planning
and Gas Engineering.
3.2 Provide and discuss the governance processes and people that will
provide oversight.
The Gas Planning department annually runs an analysis (load study) on Avista’s
gas distribution system to identify areas of the system with insufficient capacity to
serve existing firm customer loads on a design day (Avista is consistent with other
utilities in the industry and defines design day as the projected system demand for
a “coldest day on record” weather event). These deficient areas are given a
priority level based on the severity of the risk associated with insufficient system
capacity. The areas with the highest priority are selected for remediation and the
project is assigned to Gas Engineering to evaluate options to provide sufficient
capacity to meet firm gas demands on a design day.
Year to date spend and budget updates are reviewed monthly. Annually, the Gas
Engineering Prioritization Investment Committee (EPIC) reviews the 5-year plan
and ensures the budget level is appropriate given other categories of work and risk
on the gas system.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored.
The Gas Planning department formally sends a list of proposed reinforcements to
the Gas Engineering group each year. As described above, the highest priority
projects are assigned to Gas Engineering to be completed that year. Any
proposals for re-prioritization is reviewed by Gas Planning. In a typical year there
is a backlog of several years’ worth of work (from a budget perspective). Top
priority projects, that fit within the annual budget, are assigned to specific
engineers to manage.
The undersigned acknowledge they have reviewed the Gas Reinforcement
Program and agree with the approach it presents. Significant changes to this will
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 286 of 414
Gas Reinforcement Program, ER 3000
Business Case Justification Narrative Page 7 of 7
be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date: 7/10/2020
Print Name: Jeffrey A Webb
Title: Manager Gas Engineering
Role: Business Case Owner

Signature: Date: 7/10/2020
Print Name: Michael J Faulkenberry
Title: Director Natural Gas
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 287 of 414
Gas Telemetry Program, ER 3117
1 GENERAL INFORMATION
Requested Spend Amount $200,000
Requesting Organization/Department B51 -Gas Engineering
Business Case Owner Jeff Webb I Dave Moeller
Business Case Sponsor Mike Faulkenberry
Sponsor Organization/Department B51 Gas Engineering
Category Program
Driver Performance & Capacity
1.1 Steering Committee or Advisory Group Information
The Gas Measurement Engineer works with the Gas Telemetry Technicians, Gas
Planning, Gas Engineering, Metering Automation, Gas Operations, Gas Control
Room, Supervisory Control and Data Acquisition (SCADA), and Gas Supply groups
to determine possible projects or locations for new telemetry sites or upgrades of
existing equipment. The Gas Engineering Manager reviews the recommendations
from the Gas Measurement Engineer and approves the specific projects within this
program. A five year plan is also created by the Gas Measurement Engineer and
approved by the Gas Engineering Manager.
2 BUSINESS PROBLEM
Avista's commitment to safety and reliability dictates that we monitor our gas
system to ensure safe and reliable operation and accurate metering and
accounting for gas purchased and sold. This includes compliance with Federal and
State Gas Control Room Management Rules.
Gas Telemetry provides data that is used pro-actively for early detection of
abnormal operating conditions before they become major problems which may
affect safety or gas delivery. Additionally, telemetry is used to remotely monitor
system pressures, volumes, and flows from areas of special interest such as gate
stations which supply gas to Avista's system, gas transportation customers,
regulator stations which reduce and regulate pressure, selected large industrial
customers, end of line pressures, and per CFR 192. 7 41 requirements, pipeline
systems with more than one source of gas.
Alarm set points in the field instruments such as flow computers, electronic volume
correctors, and electronic pressure monitors to alert the Gas Control Room of
abnormal operating conditions such as low or high pressure, high flow, high or low
gas temperatures indicating problems with gas heaters at gate stations, and
transducer failures. Communication with the instruments is via cellular modems or
telephone lines.
Business Case Justification Narrative Page 1 of 4
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 288 of 414
Gas Telemetry Program, ER 3117
An important example is the detection of degraded pressure regulator
performance resulting in high or low pressures caused by dithiazine deposits in
our regulators. In 2019 this occurred over 100 times at sites with telemetry. This is
a mix of early detection by pro-active human analysis by evaluating pressure
trends recorded in Pl and pressure alarms received in SCADA. More pressure
monitoring with telemetry is planned at additional stations relating to this issue. By
proactively monitoring these sights, Avista can dispatch field personnel during
normal business hours instead of waiting to respond to an alarm that may happen
at any time of the day.
Additionally, data from these telemetry sites is used to validate the system
modeling tool that Gas Planning creates every year. Since the data collected is
electronic, it can be represented graphically to quickly analyze any anomalies. In
addition to permanent equipment, around 50 temporary, portable pressure
recorders with cellular modems are connected to piping in areas of interest where
permanent equipment has not yet been installed, will not be needed, or is not
practical.
The Gas Supply department benefits from these projects by having metering data
from Gate Stations that is calculated and transmitted independently of the
interstate pipeline's metering and billing info based on our instrument's measuring
pressure and temperature and calculating gas volume based on pulses from the
Pipelines meter. This aids in finding calculation or metering errors at the Gate
Stations. Billing errors left unfound can create problems that lead to extra work
and manual corrections between Avista and the interstate pipelines. This also
provides data for cases when the Pipelines' do not have data on their side.
The customers and general public benefit from Avista having good "visibility" to the
gas transmission and distribution system. This allows for a quicker response and
better decision making from the Gas Control Room and Gas Operations when an
abnormal or emergency situation occurs.
For example, we are quickly notified electronically of low pressure situations that if
not addressed in a timely manner could result in significant loss of gas service to
our customers. We are also notified of high pressures which could be hazardous
or result in blowing gas such as when a pressure relief valve opens to limit the
pressure in our piping.
If there were no telemetry, Avista would have to wait for customers to call in after
they've lost gas service which at that point would have a significant impact to our
customers and require substantial time and manpower to restore service. Costs
could range from a few thousand dollars to a million dollars. In the case of high
pressure and relief valve venting at one of our stations, we could be releasing gas
Business Case Justification Narrative Page 2 of 4
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 289 of 414
Gas Telemetry Program, ER 3117
to atmosphere for extended periods until a passerby notified us of the noise or a
gas odor.
Avista strives to replace equipment that has reached the end of its reasonable
service life with new equipment that makes use of current technology before
reliability is significantly degraded or maintenance costs are excessive. We also
review existing installations for opportunities to improve reliability, acquire more
data, or more efficient ways of collecting the data.
Enhancing the gas telemetry system increases situational awareness and visibility
of the gas system to help analyze operational concerns and monitor cold weather
performance by the Gas Control Room Operators, Gas Operations, and Gas
Engineering and Planning.
This program will continue the installations and upgrades of gas telemetry
throughout Avista's gas service territory in Oregon, Washington, and Idaho. Over
the last several years, costs have averaged approximately 45% spent in OR, 35%
in WA, and 20% in ID.
3 PROPOSAL AND RECOMMENDED SOLUTION
Option .· Capital Start Complete . Cost
Option 1 -Do nothing $0 N/A
Option 2-Preferred Solution, Replace/install $200,000 January December
telemetry at the current funding level
Option 1 -Do nothing
To make no further additions or upgrades to Avista's gas telemetry system would
result in less capability to see "real time" performance of the gas system, inability
to see operational abnormalities in a timely fashion, subject our customers to
increased chances of low or high pressure situations and their related safety risks,
and the reliability of the existing system would decline due to equipment failures.
More equipment would reach end of life and maintenance costs would increase.
Option 2 -Preferred Solution, Replace/install telemetry at the current
funding level
At the current funding level, Avista adds approximately 10 new sites and upgrades
approximately 15 sites per year. Costs per site typically range from $5,000 for a
simple upgrade to $50,000 for adding telemetry to a gate station.
The cost of this option represents a minimal amount and may need to be
increased in future years depending on equipment failures. Some years more
work is required and costs may be shared with other departments such as in 2019
Business Case Justification Narrative Page 3 of 4
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 290 of 414
4
5
Gas Telemetry Program, ER 3117
when Verizon Wireless announced it was turning off 3G cellular service starting at
the beginning of 2020 so we replaced approximately 170 3G cellular modems with
4G modems.
Based on current failure rates and funding, on the average this funding level has
allowed upgrades as instrumentation fails and allows for modest enhancements to
the system. This allows the high priority sites to be addressed as the need arises
or equipment fails.
APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Telemetry Program
(ER3117) and agree with the approach it presents. Significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatives.
Signature: ~(l(I/L Date: 2,--f?-ZcJ
Print Name: -Jeff Webb
Title: Manager Gas Engineering
Role: Business Case Owner
Signature:
~er~
Date: 2.(rr ( 20
Print Name:
Title: Director of Natural Gas
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Cmt Review
VERSION HISTORY
[Versio Implemented Revision Approved Approval Reason
n# By Date By Date
1.0 Jeff Webb 03/14/2017 Initial version
1.1 Jeff Webb 04/07/2017
2.0 Dave Moeller 2/17/2020 Jeff Webb 2/17/2020 Revised for 2020
OreQon GRC filinQ
Template Version: 02/24/2017
Business Case Justification Narrative Page 4 of 4
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 291 of 414
Jackson Prairie Joint Proiect
1 GENERAL INFORMAT¡ON
Requested Spend Amount $ 1,626,667
Requesting Organ ization/Department Gas Supply
Business Gase Owner Jody Morehouse
Business Case Sponsor Jason Thackston
Sponsor Organ ization/Department Gas Supply
Gategory Project
Driver Performance & Capacity
1.1 Steering Committee or Advisory Group lnformation
The Risk Management Committee (RMC) oversees decisions to enter into a joint
projects such að Jackson Prairie Storage Project (JP). The RMC is comprised of
the following:
. Scott Morris, Chairman, President & Chief Executive Officer, Chair of Risk
Management Committee
¡ Dennis Vermillion, Senior Vice President Avista Corporation - President
Avista Utilities
o Mark Thies, Senior Vice President & Chief Financial Officer
. Marian Durkin, SeniorVice President, General Counsel, Corporate Secretary
& Chief Compliance Officer
. Jason Thackston, Senior Vice President Avista Corporation - Vice President
of Energy Resources Avista Utilities
o David Meyer, Vice President & Chief Counsel for Regulatory &
Governmental Affairs
o Ryan Krasselt, Vice President, Controller & Principal Accounting Officer
o Patrice Gorton, Director of Finance, Assistant Treasurer
. Tracy Van Orden (non-voting), Director of lnternal Audit
Additionally, the JP Management Committee meets quarterly to review and approve
the capital budget status for the current year as well as for vetting of any ongoing or
future expenseé. A business owner representative from each of the 3 partners has
final authority on the Committee. Currently, these representatives are
o Lynn Dahlberg of Williams NWP
. Ron Roberts of Puget Sound Energy
. Jody Morehouse of Avista'
2 BUSINESS PROBLEM
Avista must provide solutions for the following gas supply needs:
Business Case Justification Narrative Page I of 3
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 292 of 414
Jackson Prairie Joint Proiect
o
A flexible, diverse portfolio with components that enable Avista to serve
customers during peak load demand'
Risk mitigation methods for shielding customers from extreme daily gas price
volatility during cold weather or other events affecting the natural gas
commodity market.
A mechanism or methodology for purchasing gas at lower prices during off-
peak periods for use during high cost periods.
3 PROPOSAL AND RECOMMENDED SOLUTION
No viable singular caPital Project options exist for replacing JP Storage at this time.
Because JP Storage Provides benefits/solutions for an array of business problems,
it's likely that in its absence,a combination of solutions would be packaged together
For meeting peak load requirements, an option is purchasing additional
leased pipeline transport on GTN at an estimated cost of $9,900,000 per year
for 90,000 dth/day at $0.30/dth. This expense would flow through the PGA.
Another solution that has been assessed in past Gas lRPs to meet peaking
needs and/or transport needs is to build an LNG storage facility. The capital
cost estimates have been in the multi-million dollar range and have proven
to be cost prohibitive. The timeline to design and build an LNG facility would
be 4 or more years.
Replacing the optimization benefit JP provides to customers with other
options would be difficult if not impossible. Over the 2016 - 2017 gas
procurement year, the storage optimization saved gas customers an
estimated $20,000,000. This benefit currently flows through the PGA.
Without storage, the flexibility is lost to purchase gas during seasonal periods
of lower gas prices (typically summer), to use or sell back into the market
when maikets are higher (typically winter). The estimated savings for this
seasonal buying approach varies, but has been as high as $10,000,000 over
a gas procurement year.
To replace JP storage capacity with leased capacity would be estimated at
more than $34,000,000/year plus additional pipeline transport. This is based
on storage capacity lease estimates of approximately $4/dth for equivalent
a
a
a
o
a
o
Option Capital Cost Start Gomplete
Do nothing - this is not an oPtion
Package together various solutions to fulfill Gas
Supply obligations
None - See
below for
expenses that
would flow
through the PGA
Continue with ownership in JP and fund necessary
annual capital expenditures
$ 1,626,667 01/01/2017 12/31/2017
Build LNG Storage Cost prohibitive
Business Case Justification Narrative Page 2 of 3
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 293 of 414
Jackson Prairie Joint Proiect
working gas capacity
The recommended solution is to continue to fund 1/3 of the capital budget for
Jackson Prairie (JP) Underground Storage Facility. Avista owns this facility as a 1/3
partner with Puget Sound Energy and Williams' Northwest Pipeline. Puget Sound
Energy is the managing partner for the facility which is located in Chehalis, WA. The
requested capital represents Avista's 1/3 share of the capital needed to maintain the
existing facility and maintain equal ownership status.
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Jackson Prairie Storage
Project and agree with the approach it presents and that it has been approved by
the steering committee or other governance body identified in Section1.1. The
undersigned also acknowledge that significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
J rehouse
Date:
Date
Template Version: 03107 12017
y'"/ s 'zot 7
Director Gas Supply
Business Case Owner
)Y
ffion Thackston
SVP & VP Energy Resources
@
5 VERSION HISTORY
Version lmplemented
By
Revision
Date
Approved
By
Approval
Date
1.0 Jody
Morehouse
04t13t2017 Jason
Thackston
04t1412017 lnitialversion
Business Case Justification Narrative Page 3 of 3
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 294 of 414
Apprentice_Craft Training
Business Case Justification Narrative Page 1 of 5
EXECUTIVE SUMMARY
Avista manages 11 Federally regulated apprenticeships that require instructional aides and equipment deemed
necessary to provide quality instruction. [Regulated by 29 CFR 29 & 30] The Joint Apprenticeship Training Committee
(JATC) administers these apprenticeships. These funds are used to purchase tools, materials and equipment for
training apprentices and journey workers in all crafts. These tools and materials provide for related instruction that is
closely correlated with the practical experience and training received on the job. The trained and competent workforce
produced through the various apprenticeship’s benefits customers in all Avista service territories. These apprenticeship
programs further benefit Avista’s customers by providing a safe, proficient and skilled workforce.

Support of apprenticeship at Avista through this capital program aligns strategically to Avista’s Mission and Focus
Areas. In order to deliver innovative energy solutions safely, responsibly, and affordably, Avista must have a field
workforce of highly proficient professionals. This professionalism is achieved through apprenticeship. Without this
funding, Avista will not have the ability to train in-house. This leaves Avista’s customers without critical craft positions
needed for energy delivery. Further, there is a potential that regulating bodies may de-certify Avista’s Apprentice
program, leaving Avista without the ability to train in-house and require significant expense to meet labor demands and
maintain required skillsets. This project will train apprentices in all Avista states and service territories, the rate
jurisdiction is Common Direct – Allocated All. The total capital expense to support this ongoing project is $375,000
over 5 years or $75,000/year.

VERSION HISTORY
Version Author Description Date Notes
Draft Joe Brown Executive Summary Only 7/1/2020 Business Case 2020 Refresh
1.0 Joe Brown Updated for Approval 7/28/2020 Full amount approved

GENERAL INFORMATION

Requested Spend Amount $375,000
Requested Spend Time Period 5 years
Requesting Organization/Department Craft Training [I02]
Business Case Owner | Sponsor Joe Brown | Jeremy Gall
Sponsor Organization/Department Human Resources
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 295 of 414
Apprentice_Craft Training
Business Case Justification Narrative Page 2 of 5
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
This capital program provides for tools, materials and equipment for training apprentices and journey workers
across eleven skilled crafts or trades. This training consists of hands-on skills development that builds
competency in a safe learning environment that may not always be available or controllable in the field. A well
trained and competent workforce ensures reliable delivery of energy to Avista’s customers and maintains a safe
environment for employees, customers and the general public in all Avista Utilities service territories. Being
unable to provide these needed tools, materials and equipment leaves apprentices and journeyman without the
resources needed for their related instruction.

As stated previously, support of apprenticeship at Avista through this capital program aligns strategically to
Avista’s Mission and Focus Areas. In order to deliver innovative energy solutions safely, responsibly, and
affordably, Avista must have a field workforce of highly proficient professional. In addition to creating a safe and
skilled workforce, this training helps Avista to deliver timely training on new and emerging technologies as well
as meet several federal and state mandated regulations including:
• Department of Labor, Standards of Apprenticeship – Title 29 CFR 29.5 (b)(4) and (b)(9) – Apprentice on
the job training and related instruction
• Department of Labor, Occupational Safety and Health Standards – Title 29 CFR 1910.269 (a)(2) – Electric
Power Generation, Transmission, and Distribution training
• Department of Transportation, Transportation of Natural Gas and Gas by Pipeline: Minimum Federal
Safety Standards - Title 49 CFR 192.805 (h) – Qualification of Pipeline Personnel, Qualification Program
training
• State of Washington – WAC 480-93-013 (4) – Covered Tasks: Equipment and facilities used by pipeline
company for training and qualification of employees
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The primary driver of this business case is Mandatory & Compliance with the secondary drivers being Customer
Service Quality & Reliability and Performance & Capacity. Avista must meet comply with the laws, rules and
regulations associated with apprenticeship. Further, customer service and asset performance will benefit from
a highly skilled workforce.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Avista will not have the ability to train in-house if this program is not funded. This leaves Avista’s customers
without critical craft positions needed for energy delivery. Further, there is a potential that regulating bodies
may de-certify Avista’s Apprentice program, leaving Avista without the ability to train in-house and require
significant expense to meet labor demands and maintain required skillsets.
1.4 Supplemental Information
1.4.1 Please reference and summarize any studies that support the problem
The cost to outsource hands-on-training and field simulations would be approximately $473,000 a
year for facility rental alone. This is based on current training programs that have averaged over
530 hours per year at the training center. The overall annual costs including travel, lodging, meals
and registration are estimated to more than triple this rental cost and be classified as operations
and maintenance costs. It is estimated this total cost would be approximately $2.4M in O&M
expense over 5-years. Again, this would result in a negative impact to Avista’s customers
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 296 of 414
Apprentice_Craft Training
Business Case Justification Narrative Page 3 of 5
1.4.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
NA

The recommended solution (Option 1) is to provide the resources needed for related instruction of craft personnel.
Option Capital Cost Start Complete
1. On-Going Capital Improvement Program $375,000 01 2021 12 2025
2. Outsource Training [No Facility] $2.4M (O&M) 01 2021 12 2025

2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The cost to outsource hands-on-training and field simulations would be approximately $473,000 a year for
facility rental alone. This is based on current training programs that have averaged over 530 hours per
year at the training center. The overall annual costs including travel, lodging, meals and registration are
estimated to more than triple this rental cost and be classified as O&M costs.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
Under this program, projects could include items such as building new facilities or expanding existing
facilities, purchase of equipment needed, or build out of realistic utility field infrastructure used to train
employees. Examples include new or expanded shops, truck canopy, classrooms, backhoes and other
equipment, build out of “SmartCity”- commercial and residential building replicas, and distribution,
transmission, smart grid, metering, gas and substation infrastructure.

2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
The greatest impact will be seen by Avista’s Operations and Avista’s Customers. Operations will have
employees with the knowledge and skills to do their jobs professionally, and customers will be served by
these competent professionals.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The primarily alternative for this program is to outsource training. If this is done, at great expense, there
will be significant impact on operating budgets, company culture, and possibly labor relations.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
The projects associated with this business case will be planned on an annual basis and be used and useful
during the calendar year in which they are implemented.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 297 of 414
Apprentice_Craft Training
Business Case Justification Narrative Page 4 of 5
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Support of apprenticeship at Avista through this capital program aligns strategically to Avista’s Mission and
Focus Areas. In order to deliver innovative energy solutions safely, responsibly, and affordably, Avista must
have a field workforce of highly proficient professionals. This professionalism is achieved through
apprenticeship. This is an investment in Our People. Providing Avista’s employees with the tools, equipment
and materials they need to train in a safe, simulated environment is essential: This is an investment in the
people of Avista and allows these apprentices to deliver value to customers and the communities they serve.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Apprentices are the future workforce of Avista. Ensuring that they have the facilities, equipment, tools and
materials they need to become successful journeyman is an investment in the future. Taking care now to invest
in the future workforce will benefit Avista’s customers and operations.
This project will be evaluated annually in the Craft Training Department and ensure projects of the highest need
area addressed.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
The key stakeholders associated with this business case are primarily internal Avista employees and
departments.
2.8.2 Identify any related Business Cases
NA

3.1 Steering Committee or Advisory Group Information
As part of the Craft Training annual planning process, the list of projects for apprenticeships will be
established, vetted and managed within the department. The manager of Craft Training & OQ will be
accountable for the business case and annual funding.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Oversight will be provided by the Manager of Craft Training & OQ, and through periodic meetings with the
Sr. Manager of Safety & Craft Training.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The manager of Craft Training & OQ will be accountable for making decisions on the business
case in coordination with the Sr. Manager of Safety & Craft Training.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 298 of 414
Apprentice_Craft Training
Business Case Justification Narrative Page 5 of 5
The undersigned acknowledge they have reviewed the Apprentice Craft Training
Business Case and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.

Signature: Date:
Print Name: Joe Brown
Title: Mgr Craft Training & OQ
Role: Business Case Owner

Signature: Date:
Print Name: Jeremy Gall
Title: Sr. Mgr Safety & Craft Training
Role: Business Case Sponsor

Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
7/29/2020
7/30/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 299 of 414
Capital Equipment Program (ER7005/7006)
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Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 300 of 414
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Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 301 of 414
Capital Equipment Program (ER7005/7006)
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Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 302 of 414
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Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 303 of 414
Capital Equipment Program (ER7005/7006)
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Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 304 of 414
Capital Equipment Program (ER7005/7006)
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Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 305 of 414
Capital Equipment Program (ER7005/7006)
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Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 306 of 414
Capital Equipment Program (ER7005/7006)
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Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 307 of 414
Capital Equipment Program (ER7005/7006)
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Schedule 9, Page 308 of 414
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Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 309 of 414
Capital Equipment Program (ER7005/7006)
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Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 310 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 311 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 312 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
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Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
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Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
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Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
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Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 324 of 414
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 325 of 414
ER 7001/ 7003 Structures and Improvements
Business Case Justification Narrative Page 1 of 16
EXECUTIVE SUMMARY

This program is be responsible for the capital maintenance, site improvement, and
furniture budgets at over 40 Avista offices, storage buildings, and service centers (over
900,000 total square feet) Companywide. This program is intended to systematically
address: lifecycle asset replacements (examples: roofing, asphalt, electrical, plumbing),
lifecycle furniture replacements and new furniture additions (to support growth) and
business additions or site improvements.

Facilities apportions approximately 50% to Asset Condition work that is identified using
Paragon Asset Condition software (Terracon), 30% is set aside for Manager Requested
projects, and 20% is kept aside for unexpected capital needs and furniture
replacements. There is currently a $7M Asset Condition backlog identified using
Paragon Asset Condition software. A funding of $3.5M will allow us to maintain a flat
backlog over the next 5 years.

This program supports Avista’s entire Service Territory and all service codes and
jurisdictions. Performing adequate Asset Management allows the Company to preserve
and fully utilize their properties while reducing expensive repairs in the long term. It also
ensures a safe environment for people and equipment. Damaged or poorly maintained
facilities can create very real safety risks and associated liability for employees,
customers, and contractors.

VERSION HISTORY
Version Author Description Date Notes
1.0 Lindsay Miller Initial Version 07/10/2018 Initial Version
2.0 Lindsay Miller Executive Summary Only 07/07/2020 Revised Template

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 326 of 414
ER 7001/ 7003 Structures and Improvements
Business Case Justification Narrative Page 2 of 16
GENERAL INFORMATION

1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Many of the service centers in Avista’s territory were built in the 1950s and 60s and
are starting to show signs of severe aging. Almost half of Avista’s Assets were built
before 1980. Most of our building systems are also past their recommended life
based on recognized industry standards defined by Building Owners and
Managers Association (BOMA), and International Facility Management Association
(IFMA) and are requiring renovation or replacement. Many of the original campus
layouts and buildings at our Service centers are no longer optimal today due to
changes in our vehicle sizes, materials storage, and operations flow. These
changes have required the need for project funding to address changing business
and site requirements as well.

Coeur d’Alene Service Center th Coeur d’Alene
Requested Spend Amount $3,500,000
Requested Spend Time Period Yearly
Requesting Organization/Department Facilities
Business Case Owner | Sponsor Eric Bowles | Dan Johnson
Sponsor Organization/Department Shared Services
Phase Planning
Category Program
Driver Asset Condition
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 327 of 414
ER 7001/ 7003 Structures and Improvements
Business Case Justification Narrative Page 3 of 16
Dollar Road Fleet Shop 2015 2,406 N. Dollar Road Spokane WA
Dollar Road Service Center 2019 2406 N. Dollar Road Spokane WA
Dollar Road Truck Storage 2014 2406 N. Dollar Road Spokane Wa
Dollar Road Wash Bay 2018 2406 N. Dollar Road Spokane Wa
Downtown Network Center 2016 1717 W. 4th Ave Spokane WA
Downtown Project Center 2016 1717 W. 4th Ave Spokane WA
Elk City Facility 2017 Hwy 14 Elk City ID
Goldendale 2015 912 E. Broadway Goldendale WA
Grangeville Facility 1933 201 E. Main Street Grangeville ID
Grangeville Pole Yard 2016 Grangeville ID
Grants Pass Service Center 1960 618 SE J Street Grants Pass OR
Jack Stewart North Line
Trailer 1985 8308 N. Regal Spokane WA
Jack Stewart Office Modular 2012 8307 N. Regal Spokane WA
Jack Stewart South Line
Trailer 1993 8309 N. Regal Spokane WA
Jack Stewart Training Center 1999 8307 N. Regal Spokane WA
Kamiah Facility 1992 No Kidd Rd. Kamiah ID
Kellogg Covered Vehicle
Storage 2012 121 Hill Street Kellogg ID
Kellogg Materials Storage 1980 122 Hill Street Kellogg ID
Kellogg Service Center 1960 120 Hill Street Kellogg ID
Kettle Falls Generating Plant
Offices 1976 1151 Hwy 395 N Kettle Falls WA
Klamath Falls Service Center 2008 2825 Dakota Ct. Klamath Falls OR
Klamath Falls Storage
Building 2012 2826 Dakota Ct. Klamath Falls OR
LaGrande Service Center 1994 10201 F Street LaGrande OR
Lewiston Call Center 1976 803 Main Street Lewiston ID
Main Campus
Café/Auditorium 1959 1412 E. Mission Ave. Spokane WA
Main Campus Canopy 5 1959 1411 E. Mission Ave. Spokane WA
Main Campus Central
Operating Facility 1959 1411 E. Mission Ave. Spokane WA
Main Campus Investment
Recovery 2011 1411 E. Mission Ave. Spokane WA
Main Campus Mini Line Dock 1970 1411 E. Mission Ave. Spokane WA
Main Campus New Fleet
Building 2017 1411 E. Mission Ave. Spokane WA
Main Campus Oil Storage
Vault 1996 1412 E. Mission Ave. Spokane WA
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 328 of 414
ER 7001/ 7003 Structures and Improvements
Business Case Justification Narrative Page 4 of 16
Main Campus Parking
Garage 2019 1411 E. Mission Ave. Spokane WA
Main Campus Ross Park
Building 1903 1411 E. Mission Ave. Spokane WA
Main Campus Service
Building 1959 1411 E. Mission Ave. Spokane WA
Main Campus Warehouse
Building 1959 1411 E. Mission Ave. Spokane WA
Main Campus Waste and
Asset Recovery 2014 1411 E. Mission Ave. Spokane WA
Medford Outdoor Storage
Canopy 1994 581 Business Park Drive Medford OR
Medford Service Center 1994 580 Business Park Drive Medford OR
Noxon Bunkhouse 1959 33 Avista Power Road Noxon MT
Orofino Service Center 1970 1051 Michigan Ave Orofino ID
Othello Service Center 1974 36 South 4th Avenue Othello WA
Pierce Facility 1985 104 Moscrip Dr. Pierce ID
Post Street Mobius / Annex
Parking 1903 337 N. Post Street Spokane WA
Pullman Mechanic Shop 2012 5704 SR 270 Pullman WA
Pullman Service Center 1959 5702 SR 270 Pullman WA
Pullman Shed 1959 5704 SR 270 Pullman WA
Pullman Storage Canopies 1959 5703 SR 270 Pullman WA
Ritzville Facility 1955 401 E First Ritzville WA
Roseburg Service Center 2004 1404 Green Siding Road Roseburg OR
Sandpoint Covered Storage 1985 103 N. Lincoln Sandpoint ID
Sandpoint Service Center 1957 100 N. Lincoln Sandpoint ID
Sandpoint Storage Bays 1957 101 N. Lincoln Sandpoint ID
Sandpoint Truck Canopy 1985 102 N. Lincoln Sandpoint ID
Spokane Valley Call Center 1979 14523 E. Trent Ave. Spokane
Valley WA
St Maries Offsite Garage and
Pole Yard 2011 St. Maries ID
St. Maries Service Center 1974 528 College Avenue St. Maries ID
Tekoa Facility 1971 West 101 Main Street Tekoa WA

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 329 of 414
ER 7001/ 7003 Structures and Improvements
Business Case Justification Narrative Page 5 of 16

Funding backlog
There is currently an identified backlog of $6.8M in Asset Condition work needed
across the system of assets Facilities manages. In 2017 Terricon identified $6M in
work on their initial assessment. This list is growing every year as our buildings
age and new items are identified that need replacement. At the current funding
level this backlog of capital work will continue to grow. The backlog is growing
faster than our current funding model can accommodate.

$-
$1,000,000
$2,000,000
$3,000,000
$4,000,000
$5,000,000
$6,000,000
$7,000,000
$8,000,000
2017 2018 2019 2020
ER 7001/ 7003 Requested vs Funding
Requested Funding Asset Condition Backlog
ER 7001/ 7033 Funding Breakdown
Manager Requested Asset Condition
Furniture (7003)Drop In/ Safety
Project Center Asphalt- Asset Condition
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 330 of 414
ER 7001/ 7003 Structures and Improvements
Business Case Justification Narrative Page 6 of 16
Capital Lifecycle Asset Replacements ER 7001
This portion of the Structures and Improvements Program is based on the results
of the Facilities Condition Assessment Survey. This survey will take into account
the condition and lifecycle of each Facilities asset. Assets will be graded and those
requiring replacement within the next 10 years will be estimated and scheduled for
replacement at an appropriate year during the 10 year time frame of the survey.
Buildings as a whole will be assigned a Facilities Condition Index (FCI) as part of
the survey to help compare future capital needs and drive the decision of
continued capital expenditures vs. possible replacement.

Examples (asphalt and structural issues):

Furniture Replacement or Additions ER 7003
This portion of the program is for furniture replacements based on industry
standard lifecycles, condition, and availability of parts. The program is also meant
to support new furniture additions required on approved building projects.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 331 of 414
ER 7001/ 7003 Structures and Improvements
Business Case Justification Narrative Page 7 of 16
Examples:

Business Additions or Site Improvements ER 7001
This portion of the program is intended to support site improvement requests and
productivity or business-related needs. Project requests are made by Operations
site managers in June the year before. The list is then vetted for validity and
business need by director-level management. Approved projects are then
prioritized vs. capital asset replacement priorities, and assigned per available
capital funding. Projects that are tied to compliance, safety, or productivity will be
given funding preference.

Example (security fencing and gate, weld shop crane):

A robust operations and maintenance program will be required to help further
extend the lifecycle of our Facilities assets and help to lessen capital replacement
needs. Conversely, limited O&M maintenance programs will result in shorter than
standard asset lifecycles, and ultimately increased Capital spending.
As the condition of our Facilities improve, capital asset replacements should
lessen in future years of the program. This is again dependent on sufficient O&M
maintenance budgets and workforce.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 332 of 414
ER 7001/ 7003 Structures and Improvements
Business Case Justification Narrative Page 8 of 16
1.2 Discuss the major drivers of the business case (Customer Requested,
Customer Service Quality & Reliability, Mandatory & Compliance, Performance
& Capacity, Asset Condition, or Failed Plant & Operations) and the benefits to
the customer
The major driver of this business case is Asset Condition. Facilities apportions
approximately 50% to Asset Condition work that is identified using Paragon
Asset Condition software (Terracon), 30% is set aside for Manager Requested
projects, and 20% is kept aside for unexpected capital needs and furniture
replacements.
Customers benefit from this project by Facilities providing a safe, usable
buildings through which our Operations teams provide electricity and gas to our
customers.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
As previously stated there is an identified backlog of Asset Condition work of
$6.8M. This list is growing every year as our buildings age and new items are
identified that need replacement. Deferring this work will cause a large bowel
wave of Capital investment in future years. Providing a level investment over
the next 10 years will allow us to prevent equipment failures and the need for a
large one time capital investment.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
At this time, the only measure that can be used is to design solutions that
provides room for growth, expands technology requirements, and adheres to
safety and security best practices. Some of these solutions would include items
such as:
1) Materials/ Storage: Provide spaces that meet the needs of the Stores team
and Operations
2) Environmental/ Compliance: Ensure that the building and site meets with
Avistas environmental standards
3) Employee/ Customer Impacts: Room for employee or operations growth
4) Operational Efficiency: Ensure that operational needs of employees are
being met
5) Asset Condition: Provide systems and materials that meet with Avista
standards

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 333 of 414
ER 7001/ 7003 Structures and Improvements
Business Case Justification Narrative Page 9 of 16
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the
problem
The Asset Condition Study and Asset Condition Report for all of Avista’s
Assets is used to help determine the best options to resolve the various
Asset Condition needs.
1.5.2 For asset replacement, include graphical or narrative representation
of metrics associated with the current condition of the asset that is
proposed for replacement.
The Asset Condition Study and Asset Condition Report for all of Avista’s
Assets is used to help determine the best projects to fund in any given
year. Projects are prioritized by the Paragon Asset Condition program
using metrics such as risk, impact and ROI. This prioritized list is then
used to create the Asset Condition project list for the coming year.

Recommended Solution – Fund Program at full amount
This will allow us to address capital asset replacements and business needs.
Safety, compliance, and productivity requests are rated highest and given priority
first. Many of these replacements can create safety risk if not addressed (sidewalks,
structural repairs). Not systematically addressing maintenance needs could
ultimately result in complete replacement of the buildings at some point.

Option Capital Cost Start Complete
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.

There is currently an identified backlog of $6.8M in Asset Condition work
needed across the system of assets Facilities manages. In 2017 Terricon
identified $6M in work on their initial assessment. This list is growing every
year as our buildings age and new items are identified that need replacement.
At the current funding level this backlog of capital work will continue to grow.
The backlog is growing faster than our current funding model can
accommodate. It is the goal of this program to maintain a level backlog that
projects are selected from using Terracon’s risk assessment and the impact
the item has on the Company’s ability to perform its work, making the highest
priority projects readily apparent.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 334 of 414
ER 7001/ 7003 Structures and Improvements
Business Case Justification Narrative Page 10 of 16
Even funding this program at the $3M level we will never be able to completely
reduce the backlog. Providing more than the $3M requested would require
additional Project Management personnel and possibly FTE’s. Facilities can
accommodate this request within their current staffing model. It is the goal of
this program to maintain a level backlog that projects are selected from using
Terracon’s risk and the impact the item has on the Company’s ability to
perform its work, making the highest priority projects readily apparent.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital
spend?). Include any known or estimated reductions to O&M as a result of
this investment.

Average funding splits based on project priorities
This program is be responsible for the capital maintenance, site improvement,
and furniture budgets at over 40 Avista offices, storage buildings, and service
centers (over 900,000 total square feet) Companywide. This program is
intended to systematically address the following needs:
 Lifecycle asset replacements (examples: roofing, asphalt, electrical,
plumbing)
 Lifecycle furniture replacements and new furniture additions (to support
growth)
 Business additions or site improvements (examples: adding a welding
bay, vehicle storage canopy, expanding an asphalt yard. Can
sometimes include property purchases to support site expansions.)
This program would encompass capital projects in all construction disciplines
(roofing, asphalt, electrical, plumbing, HVAC, landscaping, expansions,
remodels, energy efficiency projects). Facilities apportions approximately 50%
to Asset Condition work that is identified using Paragon Asset Condition
software (Terracon), 30% is set aside for Manager Requested projects, and 20%
is kept aside for unexpected capital needs and furniture replacements.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.

This Business Case will impact the employees that work out of the offices and
locations where projects are completed. Other teams that may be impacted are:
ET, ET Security, Radio Relay, Environmental and Stores/ Warehouse.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.

Alternative #1 – Partially Fund Program based on priority
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 335 of 414
ER 7001/ 7003 Structures and Improvements
Business Case Justification Narrative Page 11 of 16
This option would decrease the capital program and increase existing O&M
budgets to prolong structures’ lifecycles beyond rated life, and reduce capital
needs. This option is not the preferred approach over the long-term. Capital
investments can be limited with a corresponding increase in O&M dollars. As
building systems continue to decline O&M burden will increase.

The estimated replacement value of Avista’s assets when the Terricon survey
was taken in 2017 was approximately $242 million, with estimated maintenance
and replacement requirements based on the Terracon report of $8,800,640 per
year, which equals 3.64% of the current replacement value of the assets. The
graph above clearly demonstrates that the amount spent by Avista (the green
bars) typically does not reach the minimum level of O&M expenditures (the blue
bars) standard in the building industry for basic sustenance of facilities. This
level of underfunding would need to be addressed if the choice is made to
underfund this program.
Business site improvement requests are intended to address changing business
needs. These projects are usually linked to an enhanced productivity outcome.
Having the ability to incorporate structures and equipment that fall within the
improvement and business needs category can help support improved processes
and lead to enhanced safety and longer lifecycles. When the budget needs to be
reduced, reductions are first made to requests in this category.
Replacement is intended to replace aging units to achieve more predictable
capital requirements and avoid replacement peaks caused by large-scale
failures. Cutting into these requests over an extended period could lead to
reduced efficiency and have safety impacts.

Alternative #2 – Do nothing
This option is not recommended. Building improvements are capital events that
materially extend the useful life of a building and/or increase the value of a building.
Building improvements are capitalized and recorded as an addition of value to the
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 336 of 414
ER 7001/ 7003 Structures and Improvements
Business Case Justification Narrative Page 12 of 16
existing building. Sites will continue to decline due to normal wear and tear. The
failure of certain systems, such as roofing or HVAC, can cause major damage to
other areas of the building. Walkways and structural issues not being addressed
could have safety impacts to employees, visitors and customers.
When failures occur the capital investment must be made, regardless of funding.
This program provides an avenue to PLAN these capital investments.

2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
The majority of projects in the Facilities Structures and Improvements program
begin work in the 2nd or 3rd quarter of each year, and will usually transfer to plant
before the end of the year. Some of the larger projects, or projects with extensive
design, can carry over to the following year.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.

The major reason to perform this project is to align with Avista’s strategic vision
of customer performance and reliability. Being able to provide service to our
customers safely and efficiently is a cornerstone of Avista and the current
Pullman Operations office does not allow employees to meet those goals.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project

Hopefully the business problems described earlier makes a strong case that this
investment makes sense, as to avoid significant operational, reliability, and
performance risks. As the project progresses, the scope and budget will be re-
baselined as required. And hopefully the project can come in possibly under
budget and ahead of schedule. Full oversight of the scope and budget will be
provided to the Facilities Steering Committee (see Section 3.1 (A)) for their
review and evaluation as described in Section 3.2 and 3.3.

2.8 Supplemental Information

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 337 of 414
ER 7001/ 7003 Structures and Improvements
Business Case Justification Narrative Page 13 of 16
2.8.1 Identify customers and stakeholders that interface with the business
case
The project within this business case will impact the Pullman Service
Center Team. The team will be able to work out of the current service
center during construction but we will be reaching out to the team during
the design and construction phases.

2.8.2 Identify any related Business Cases
None

3.1 Steering Committee or Advisory Group Information
ER7001 Facilities Structures and Improvements is a 5-year program created to
address the capital lifecycle asset replacements and business/site
improvements at all of Avista’s regional sites and offices. Asset lifecycle
replacements are compiled by Facilities and are based on an asset condition
report and industry recognized lifecycles. Site improvement projects are
approved based on productivity and/or business need.

Asset Lifecycle Replacement Projects
In 2017 Avista hired Terracon Consultants to perform a condition assessment
on 76 Avista-owned facilities and 35 real estate sites at 34 different locations,
comprising approximately 981,000 square feet. These facilities were
constructed between 1903 and 2016. Terracon estimated the value of this
infrastructure at approximately $242 million.
The Terracon study was highly detailed and in depth. They examined every
characteristic of each facility from a variety of perspectives. External structures
from asphalt in the parking lot to roof condition, fences, curbs, work, and storage
areas were examined to ascertain and score condition and to identify issues
and note concerns. Internal aspects such as walls, carpets, and furniture
condition were evaluated.
They surveyed building systems including plumbing, heating and cooling,
electrical, lighting, air quality, drainage, and security. They also looked at safety
aspects from both the customer and employee perspective. Then each item in
the facility was rated based upon its condition and assigned a budget category
of O&M Preventative Maintenance, O&M Deficiency Repairs, Capital
Replacement, and Capital Renewal/In-Kind Replacement. Terracon’s list is
sorted by relative risk and the impact the item has on the Company’s ability to
perform its work, making the highest priority projects readily apparent. Of the
363 “at risk” items Terracon identified, nearly 60% had a risk rating higher than
5 (on a 1 to 10 scale) and 20% were identified as having an actual impact on
operations. This rating is what is used to identify the highest risk replacements
needed and the project list is created using this information.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 338 of 414
ER 7001/ 7003 Structures and Improvements
Business Case Justification Narrative Page 14 of 16

Site Improvement Projects
These types of requested facilities projects undergo a multi-level internal review
process. It begins with the related manager who either identifies the capital need
themselves or is notified of an issue that needs to be resolved by an employee.
If the manager believes the project is in the best interests of his group and the
Company, the proposal is submitted to that manager’s director. If the director
also sees the value of the request, it is submitted to a group known as the
Facilities Capital Request Board.
This Board meets every fall to review the requested projects for the upcoming
year. Managers from each major business area send a representative (the
employee chosen usually changes every year). In addition, there is a
requirement of at least one person from Operations, Environmental Affairs,
Materials Management, and Facilities. This broad mixture of perspectives is
designed to provide a neutral and “outside” perspective while having access to
the expertise and experience of the directly related and impacted business
entities.
By the time the Board receives the list of requests, it has already been vetted
twice within its related department. The requests are prioritized based on the
Capital Request form that was filled out and approved. At the Board level, each
request is reviewed for required criteria such as risk, safety, environmental
impact, and compliance. Thus this process is designed to ensure that multiple
stakeholder participation provides a thorough and robust analysis of all facility
needs and alternatives across the Company.

3.2 Provide and discuss the governance processes and people that will
provide oversight
Facilities Capital Steering Committee
Once the project list is assembled, the finalized list of projects is approved by
the Capital Facilities Steering Committee. This Committee of Directors is
responsible for approving the submission of Business Cases to the Capital
Planning Group and approval of projects and any changes within this program.
In the past this has most often been:
 Director of Shared Services
 Director of Environmental Affairs
 Director of Financial Planning and Analysis
 Director of Generation, Production, Substation Support
 Director of IT and Security
 Director of Natural Gas
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 339 of 414
ER 7001/ 7003 Structures and Improvements
Business Case Justification Narrative Page 15 of 16

The project shall use certain Project Management Professional (PMP)
guidelines and procedures during the course of this project.
A Project Execution Plan, consisting of the documents below, will be drafted and
approved by the SteerCo described in Section 3.1 (A).
 Project Charter, Change Management Plan, Communication
Management Plan, Cost Management Plan, Procurement Management
Plan, Project Team Management Plan, Risk Management Plan and Risk
Register, Schedule Management Plan, Scope Management Plan, and
Project Execution Approval Form.
Each month, the project manager will provide the following information either at
the scheduled SteerCo meeting, or via email.
 Approved Yearly Budget, Accrued Yearly to Date, Year Estimate at
Complete, Year Variance at Complete, Approved Lifetime Budget,
Accrued Life to Date, Lifetime Project Estimate at Complete, and Lifetime
Project Variance at Complete.
Each month, the SteerCo will make decisions on cost, scope, or budget items
as required by the Project Execution Plan. The project manager reserves the
right to present items not outlined in the Project Execution Plan if he/she
determines its importance is relevant to SteerCo input.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The final decisions regarding these items, especially certain change requests
as required by the Project Execution Plan, will be presented to, and voted upon
by the SteerCo. The decisions will be documented in a monthly meeting minutes
of the SteerCo for documentation and oversight.
It will be the Project Manager’s role to monitor the scope, budget, and schedule
and present the results to the SteerCo, regardless of they are within tolerances,
or not.

The undersigned acknowledge they have reviewed the ER 7001/ 7003 Structures
and Improvements and agree with the approach it presents. Significant changes to
this will be coordinated with and approved by the undersigned or their designated
representatives.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 340 of 414
ER 7001/ 7003 Structures and Improvements
Business Case Justification Narrative Page 16 of 16
Title: Corporate Facilities Manager
Role: Business Case Owner

Business Case Sponsor

Steering/Advisory Committee Review

Template Version: 05/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 341 of 414
Telematics 2025
Business Case Justification Narrative Page 1 of 11
EXECUTIVE SUMMARY
Fleet operations across the US and within the utility industry are implementing telematics
solutions to solve complex business problems. The Advisory Group has identified five
ways that vehicles on the road impact Avista. The first represents the first generation of
telematics and is focused on utility owned trucks. The next four have the potential to
positively or negatively impact our business but they are vehicles not owned by the Avista.
It could be the contractor working for Avista in a contractor owned truck, a contractor in
their personal vehicle, Avista’s employee’s doing business on behalf of the utility in their
personal vehicle and crews responding to mutual aid in our service territory. Telematics
has been implemented on the Avista’s fleet since 2012. The first generation of telematics
was implemented to streamline and track the inspections of trucks and mounted
equipment. The digitization of inspections has been very successful and has improved
the tracking of federally required inspections and the administration of those records as
required by the same authorities.
In February 2022 our current provider has notified us that the 3G network that nearly 500
devices connect to will sunset. This network shut down forces us to invest capital in an
upgrade. Additionally, customer requirements and our strategy to put the customer at the
center of every decision necessitate the need for us to leverage vehicle location data on
a modern and timely platform. Finally, best in class utilities are using telematics to provide
both coaching to drivers and collecting leading indicators on decisions a fleet of drivers
are making. The Advisory Group’s recommendation is to replace Zonar telematics with a
modern cloud platform system from Verizon Connect or Utilimarc-Geotab. Both platforms
address latency issues and integrate more info sources than ever before. The final
estimated cost for this is upgrade $2,387,500 spread over three years. An upgraded
system will integrate location data with the CX platform to give our customers accurate
response info, safer roads for all and lower overall costs by streamlining our operations
with data. We must begin this investment in 2021 with the February 2022 shutdown of the
AT&T 3G network coming. In doing nothing we will lose our ability to complete a critical
compliance function by being unable to complete our daily vehicle inspections.
Additionally, we fail to meet our customers where they expect us to be in today’s digitally
connected economy.

VERSION HISTORY
Version Author Description Date Notes
ExeSum Greg Loew Exe summary only 7/7/20
Rev1 Greg Loew Completed case 7/24/20

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 342 of 414
Telematics 2025
Business Case Justification Narrative Page 2 of 11
GENERAL INFORMATION
Requested Spend Amount $2,387,500
Requested Spend Time Period 3 years
Requesting Organization/Department Fleet Services
Business Case Owner | Sponsor Greg Loew | Dan Johnson
Sponsor Organization/Department Energy Delivery
Phase Planning
Category Project
Driver Asset Condition
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 343 of 414
Telematics 2025
Business Case Justification Narrative Page 3 of 11
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Advances in technology, customer requirements and safety are driving the need to
invest capital in our connected vehicle systems. Implementing the next generation of
telematics in vehicles on the road operating on behalf of Avista have the opportunity
to delight our customers, reduce our liability exposure and improve operational safety.
Technological Changes: Telematics works by connecting the vehicle to the cellular
data network. Currently, most telematics connectivity use third generation networks
(3G) provided by the major carriers. In February 2022 this network will no longer be
supported and many carriers are already preventing new 3G devices on their
networks. To ensure current functionality we will need to equip our vehicles to connect
to the fourth and fifth generation networks (LTE and 5G respectively). We also know
that connected worker solutions are proliferating across our workforce. This has driven
numerous data connections inside and outside of the vehicle. Telematics technology
has advanced to allow the consolidation of connections. Leading telematics providers
have embraced a platform perspective. They have acknowledged that original
equipment manufacturers are controlling some of the data flow from the vehicle or like
Caterpillar it is just build in to the equipment computer. This migration to a platform is
beneficial for Avista as we advance solutions for the fully digitized worker of the coming
decade.
Customer Requirements: Our customers are being influenced by Amazon and Google
and other leading customer experience companies. They expect timely and relevant
communications from everyone they do business with. The utility is not exempt from
these expectations. Next generation telematics is an enabling technology for a fully
integrated and digital field work process. The connected vehicle and worker,
integrated with the mobile work management system and customer experience
platform will provide greater visibility about where our field personnel are and when
they will arrive. The information will be available to employees and to customers,
improving our ability to provide firm estimates of when we will be there to complete the
work. The platform will also improve emergency response times through improved
routing and real time location services. Finally, providing more crew location
information to our dispatchers will allowing us to dispatch the crew closet to the work
saving valuable time and resources.
Safety: The impact of telematics on the overall safety to a fleet of vehicles is under
estimated. Telematics allows the capture of data around all facets of the drive cycle.
More importantly, telematics is to several leading indicator safety metrics. Next
generation telematics integrations will allow us to see items as specific as seat belt
usage, the engagement of reverse or how close we backed up to an object. Telematics
also has the ability to coach drivers in real time and or provide them a summary of
their performance on a pre-determined interval. Finally the next generation systems
will provide metrics on the co-location of supervisors to the crews which has been
proven to be a major predictor in crew safety performance
Additionally, as the Advisory Group has engaged internal stakeholders we have
created a required functionality list. Based on current published Zonar capabilities the
following issues with Zonar were identified:

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 344 of 414
Telematics 2025
Business Case Justification Narrative Page 4 of 11
Issue Impact on Capability
Dynamic Reporting Provides inconsistent data points
Server based system 5-8 minute lag in actual unit status
Only support Android operating system Avista has standardized on iOS
No vehicle as a hotspot capability Multiple connections and expense
Driver coaching Requires dedicated tablet
Workflow management No integrations or partnerships
Behavior metrics No metrics outside of speed to posted
Auxiliary system data capture No 3rd party device integration
Point designed solution No platform capabilities at this time
No manufacture API integration Requires us to always us an ancillary
device

Telematics 2025 will initially provide a platform for compliance. We can and will continue to
measure inspections completions and other safety related functions. We will use this
platform to capture, track and communicate this information to users and leaders. A
feedback loop to the driver on their driving performance will be a key feature of this initiative.
Over time the advanced telemetry data from this system will help us shrink the gap between
actual behaviors and expected behaviors.
The Driver Safety team that was stood up in 2017 identified a dozen key actions to improve
our vehicle incident rate. These recommendations where based on the analysis of multiple
best in class companies and the programs/practices they had in place to achieve such
results. Every program we looked at had some sort of driver performance feedback
mechanism.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
Asset Condition
Telematics 2025 is also an enabling platform for Customer Experience
advancements and Business Intelligence. We could measure improvements in
customer satisfaction, reduced maintenance costs, and lower overall cost per
customer being driven by fleet related activities.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The 3G network that Zonar currently operates on will cease operations in February of
2022. Our DOT/FMCSA compliance with CFR49 and the inspections required before
and after operation are digitally managed. Not doing anything will force our commercial
vehicle operators to complete inspections by pen and paper and creates a document
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 345 of 414
Telematics 2025
Business Case Justification Narrative Page 5 of 11
management challenge because we must keep them for 12 months before disposing
of them. Failure to do so opens the company to additional liability.
1.4 Identify any measures that can be used to determine whether the investment
would successfully deliver on the objectives and address the need listed
above.
Cost Savings: Estimated savings to the organization will be driven both directly and
indirectly through multiple factors. Savings are ranked from initial platform
deployment to additive next generation work management solutions to be deployed
by future
 Compliance and regulatory costs—Avoided cost from effort and resources to once
again track vehicle inspections with paper and the increased risk due to the
inspection records not being correctly maintained per US Department of
Transportation regulations 49CFR
 Automated recording of miles—Current work flow requires over 50% of Avista
vehicles to submit mileage in paper form. Up to 25% of mileage is not turned in and
as such vehicle use cost are not being fairly distributed to all users.
 Assuming data plan aggregation can occur while still supporting the critical business
functions of the workers in the field, anticipated savings from reduced network
connections in the vehicles are estimated as follows:
Vehicle Quantity Data Plan Cost
80 $40.52/month
Total Cost Savings Per Year $38,900
 Improved utilization—Currently, we average 11% less in miles and hours than the
industry. 30% of fleet vehicle get less than 50% of the class average miles per year.
By improving utilization we can spread our fixed cost across more miles and work to
lower the fleets total fixed costs by reducing complement.
 Improved maintenance using advanced business intelligence tools and data—
Revised maintenance programs could save up to $170,000 per year in total
maintenance costs. This would be achieved by moving vehicles to a usage based
maintenance model in which the collection of mileage data by the system alerts us
to do a PM only when it approaches a use threshold.
 Less vehicles because of improved capabilities to share assets among some groups
of workers—Reduced total fleet acquisition costs, higher utilization, reduced fixed
and variable expenses.
 Improved routing and fuel savings—New operations driven tools could reduce total
fuel consumption by expediting vehicles from job to job.
 Customer Service savings driven by reduced calls to the call center—The three year
average for complaint calls related to vehicles and the potential whereabouts of
people doing work on behalf of Avista totals 55 call hours per year using customer
complaint records and an average call duration of 6.5 minutes.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 346 of 414
Telematics 2025
Business Case Justification Narrative Page 6 of 11

1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
See the Driver Safety Team report out February 2018 by Greg Loew and Tony
Klutz
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
The current network for Zonar will cease operation in 2022. As noted in section
1.1 several functions were noted as missing for future anticipated business
processes.

Option Capital Cost Start Complete
Implement Telematics 2025 $2,385,500M 01 2021 06 2023
Partial implementation of Telematics 2025 $1,850,000M 01 2021 12 2021
Upgrade Zonar to 4G devices $157,500 03 2021 10 2021
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 347 of 414
Telematics 2025
Business Case Justification Narrative Page 7 of 11
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.

Reference key points from external documentation, list any addendums, attachments etc.

Problem Statement Identify a telematics solution that provides safety and compliance data on vehicles doing work
on behalf of Avista and enables or supports solutions connected to the digital worker of the
future.
Required
Functionality Details Alternatives
Priorit
y
Focus
Area
Electronic Inspections The completion and documentation of DOT required inspections plus pre-flight inspections Paper ComplianceRegulatory Mileage
Reporting Multiple federal and state agencies require exact mileage to be reported per state N/A ComplianceDiagnostic Alerting and
Reporting The ability for the truck to push diagnostic trouble codes to Fleet N/A Fleet
AssetWorks Integration Pushing mileage to database to act as system of record eliminating the need for the vehicle ledgerN/A Fleet
iOS Compatible Must work on iOS devices N/A ITDriver Behavior Scoring and Coaching Feed back mechanism to help drivers know how they are driving In cab or daily summary Safety
4G and 5G capable 3G network is at end of life N/A IT
Customer facing info Customer know who the worker is that will be serving them and visibility into when they will be thN/A
Customer
Service
Utilization Reporting and mechanisms for understanding under utilized equipment N/A Fleet
Idle Reduction Knowing what it productive idle and non-productive idle N/A FleetECM data/Vehicle
Performance Real-time performance data to build dynamic maintenance response
Maintain current system
of time base FleetIntegration for
Distribution Dispatch Showing vehicle assets to distribution dispatchers to improve dispatch capabilities N/A IT
Work Flow Management Match personnel and resources to work requiring completion (work management) (maybe a tie to N/A Operations
Driver Identification Knowing who is driving every single truck every time it moves
Assumptions based on
inspection Safety
Behavior Metrics Data analysis info to understand trends and habits N/A Safety
Accident Reconstruction Capability to record some amount of data that can be analyzed after minor crashes
Uses air bag computer
after major crashes SafetyIntegration of mulitple
telemetry data systems Trailers and other AVA assets can use different location systems.Put everything one syste FleetAuxiliary System Data
Capture Capability to capture data from other systems installed on the truck (back up sensors, seatbelt usa N/A SafetyGPS location for non
motorized units Find the lost trailer N/A Fleet
Vehicle Hotspot Vehicle based data connection point
Current system with
rugged laptops IT
Smart Phone App
App that could be installed on contractors phone to know where they are at in our system (think
gas survey)N/A IT
Productivity Expedited routing N/A Operations
Co-Location Where are supervisors (GFs, managers) in relations to crews N/A SafetyMobile Device Use
Reporting
Utilizing mobile device app integrated with telematics to know if the phone is used while vehicle
is in motion
App deployed with MDM
solution Safety
Satellite Connectivity For use in remote wilderness areas N/A Safety
Vehicle Pooling Dynamic assignment of available vehicle to worker requiring vehicle
One vehicle for each
worker Fleet
Driver Cameras Forward and rear facing in cab cameras
Forward facing camera
only Safety
Telematics Capabilities
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 348 of 414
Telematics 2025
Business Case Justification Narrative Page 8 of 11
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
Telematics 2025 will be implemented over a three year period beginning in 2021 in
order to meet 3G obsolescence. In year one our commercial fleet will be functional and
on the new systems. In years two and three we will bring our light duty vehicles fully on
to the platform plus trailers and complete integrations to systems like Assetworks,
Intelex and Oracle.
On an ongoing basis the operational costs for telematics flow to the Fleet Clearing
Account. From there a portion of the costs go to capital and some to O&M depending
on the class of vehicle. Vehicle rates for light duty trucks and trailers will see a small
impact from this technology.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Telematics 2025 will continue to be used by Fleet and Distribution Ops. The CX project
will use the data stream from this system as described in section 1.1. Vehicle
electrification efforts have the potential to tap into the platform.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Upgrade existing system. Preserve current functionality with technology that
does not meet current or future business needs across the enterprise.
Partial install on only the on-road portion of our fleet (excludes trailers)
Partial install of new system on commercial motor vehicles only. Preserves
current functionality does not integrate or capture almost a third of all Avista
owned vehicles. Many safety and operational benefits would not be met.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
$1.1M Q1-2021
Project
planning
Q2-2021
Product
ordering
Q3-2021
Vehicle installs
districts or orgs
completed
Q4-2021
Project
remaining TTP
$675K Q1-2022
SOW
Q2-2022
Integrations,
TTP
Q3-2022
Remaining 2nd
TTP
Q4-2022
$612.5K Q1-2023
SOW
Q2-2023
Integrations,
final TTP
Q3-2023 Q4-2022

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 349 of 414
Telematics 2025
Business Case Justification Narrative Page 9 of 11

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Enhancing the telematics in the fleet vehicles directly aligns with the four focus areas;
customers, people, perform and invent.
Customers are better served by providing a platform that enables notifications and
awareness of crew arrival times. Avista Employees are better served through
interactive coaching and feedback on their driving behavior. Performance is better
served through the enhanced integrations that are enabled and the information that can
be shared across multiple systems. Invention is served by recognizing that the
expectations of customer service has changed, and that technology is required, not
only in our back office but in the front-line vehicles that serve as the initial touchpoint
for many customer interactions
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
The majority of Telematics 2025 scope is the replacement of a system that will no
longer operate after February 2025. As outlined in section 1.1 our next generation
telematics will enable additional functions and help streamline analog processes.
Project management and business case owner will continue to review the scope of
the project for material changes.
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Stakeholder Name Department
Andrea Pike Customer Service
Reuben Arts Distribution Dispatch
Amy Parsons Finance
Mike Faulkenberry Gas Ops
Alexis Alexander GPSS
Mike Littrel Enterprise Technology
Jon Thompson Enterprise Technology

2.8.2 Identify any related Business Cases
None at this time

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 350 of 414
Telematics 2025
Business Case Justification Narrative Page 10 of 11

3.1 Steering Committee or Advisory Group Information
Mike Littrel Erica Ellis Kim Boynton
Matt Redding Eric Rosentrater Jason Johnson
Steve Aubuchon Russ Feist Jim Corder
3.2 Provide and discuss the governance processes and people that will
provide oversight
This project reports in with the executive advisory committee comprised of:
Heather Rosentrater Jason Thackston Jim Kensok
Bryan Cox

3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The project manager and the business case owner will be responsible for monitoring
and recording priority changes and material change requests. Full values and scope to
be determined at a later date.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 351 of 414
Telematics 2025
Business Case Justification Narrative Page 11 of 11

The undersigned acknowledge they have reviewed the Telematics 2025 and agree
with the approach it presents. Significant changes to this will be coordinated with
and approved by the undersigned or their designated representatives.

Date:

Business Case Owner

Date:

Business Case Sponsor

Date:

Steering/Advisory Committee Review

Template Version: 05/28/2020
Gregory Loew
Fleet Manager
7/24/20
Shared with committee on 7/24/20 via email
Dan Johnson
Director, Shared Services
7/28/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 352 of 414
Oil Storage Improvements
Business Case Justification Narrative Page 1 of 9
EXECUTIVE SUMMARY
In the 1990s, an underground vault was built at the Mission Campus to house several tanks intended to hold new oil, used but viable oil, and scrap oil, all related to substation maintenance and electrical distribution operations. This system connected the electric shop and the scrap oil
recovery areas through a series of manifolds and pumps to segerate the new and used oils. Several
incidents, including one holiday weekend overfill incident in 2010, brought to light the disadvantage of using an underground system, as problems could go undetected. This risk was further highlighted during a 2019 pipeline spill and subsequent investigation/excavation and cleanup.

In 2014, two new above-ground scrap oil storage tanks were built as part of the Waste & Asset Recovery (WAR) Building. This allowed for the two scrap tanks in the underground vault to be decommissioned, but the remaining four underground tanks, and associated underground piping, remain in use. This system still poses risks of undetected leaks. In addition, access to the
underground system becomes more problematic as we redevelop the campus. The vault space
itself limits use of the area. Finally, the vault has been subject to intrusion by water, and maintenance costs to ensure the vault provides proper containment are increasing. The recommended solution will build two additional new oil tanks by the WAR Building, with
several smaller “day” containers for the Electric Shop, allowing the underground vault to be
permanently removed, eliminating environmental risk. The recommended solution is estimated to cost $1.5 million (as of June 2020). Since the project is at the Mission Campus, the rate jurisdiction is Common Direct – Allocated All. The major
customer benefit would be the reduction in future O&M maintenance, and costs of clean up of
environmental events. Customers will also benefit with an enhanced oil storage process that will provide Avista employees with reduced overall environmental risk, time efficiencies and generally faster response times within substation maintenance. It is recommended to proceed with this business case as soon as possible to avoid any additional environmental risk and inefficiencies
utilizing the existing system.

VERSION HISTORY
Version Author Description Date Notes
0.0 Vance Ruppert Initial draft to be approved by Sponsors 7/6/2020
1.0 Vance Ruppert Final Draft, Sponsor edits incorporated 7/10/2020

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 353 of 414
Oil Storage Improvements
Business Case Justification Narrative Page 2 of 9
GENERAL INFORMATION
Requested Spend Amount $1,500,000
Requested Spend Time Period 2 years
Requesting Organization/Department Shared Services (Facilities)
Business Case Owner | Sponsor BC Owner: Eric Bowles
Johnson
Sponsor Organization/Department Environmental / GPSS / Shared Services
Phase Initiation
Category Project
Driver Asset Condition
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 354 of 414
Oil Storage Improvements
Business Case Justification Narrative Page 3 of 9
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
In the 1990s, an underground vault was built at the Mission Campus which housed several
tanks that were intended to hold new oil, used but viable oil, and scrap transformer oil, all
related to substation maintenance and electrical distribution operations. Over time, there
have been several incidents of an environmental regulatory nature that began to question
the ongoing practicality of retaining this asset.
A. The prime event occurred in September 2019, when an Electric Shop Electrician
discovered a pipe rupture into the containment vault after operating the system for
approximately 30 minutes. The pipe connects the vault and the Electric Shop (a
substation maintence shop) within the Service Building (one of several standalone
buildings on the Mission Campus). The leak released an estimated two hundred gallons
of oil, and required excavation to a depth of 15 feet deep and approximately 31 cubic
yards of soil. The system is currently curtailed to direct pumping operations from the
containment building, which is cumbersome to Avista personnel. We are awaiting
confirmation from Washington State Department of Ecology for a “no further action”
letter regarding site cleanup..
B. Another incident occurred in 2010, when an oil transfer occurred on a Friday with electric
shop personnel and a contractor. The wrong tank was selected to fill, the oil overflowed
out of the tank and oil was allowed to float on the floor for over three days as it was a
holiday weekend. It is unknown if the oil significantly penetrated the concrete floor but
some concrete may have been contaminated. Designation and disposal will occur under
this business case.
C. O&M dewatering - The roof to the underground vault is an asphalted lid that doubles as
a drive path for Avista vehicles. However, water seeps down into the vault through
cracks and porous surfaces. This problem has accelerated through the years and
requires a hazardous waste technician to pump out the water, and screen it for oil/PCB
contamination before disposing of it. This occurs 5-10 times per year.
D. The oil storage vault is a “stranded asset” as multiple stakeholders claim use of the
resource, without a single stakeholder that “owns” the asset for O&M checks or
maintenance. O&M checks are currently performed by Hazardous Waste Technicians
and Security contractors to ensure that oil isn’t present in the containment on a weekly
basis.
1.2 Discuss the major drivers of the business case and the benefits to the
customer
The major driver for this Business Case is “Asset Condition,” due to its containment failures
and environmental risks as outlined in Section 1.1. The major customer benefit would be
the offset of any future O&M maintenance or clean up of environmental events. Customers
will also benefit with an enhanced oil storage process that will provide Avista employees
with time efficiencies and generally faster response times within substation maintenance.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
With the past failures as outlined above, it is Avista’s belief that a major environmental event
with the underground vault is a matter of when, not if. Avista cannot predict when that event
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 355 of 414
Oil Storage Improvements
Business Case Justification Narrative Page 4 of 9
would occur, be it months or years. However, in general, the longer this Business Case is
not implemented, the greater the chance the risk could occur without the problem being
fixed.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
At this time, the only measure that can be used is to design a oil storage system that takes
lessons learned from the underground vault and uses them to mitigate risks. Some
measures include a system that will:
1) be easily viewable by multiple employees on a daily basis to check for leaks
2) not use any underground tanks or piping
3) use oil containment best practices such as: active electronic monitoring, modern pumping
equipment, reinforced single or double-walled tanks, weathertight roofing, purpose-built
concrete containment with impermeable coating.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
2010 CH2M Hill Assessment of Undergorund Storage Tanks for Avista. Available
on request (Facilities / Vance Ruppert).
1.5.2 For asset replacement, include graphical or narrative representation of
metrics associated with the current condition of the asset that is proposed
for replacement.
Pictures of the underground pipe oil leak as described in Section 1.1 (A) above
are available on request (Facilities / Vance Ruppert).
Pictures of the oil tank overflow as described in Section 1.1 (B) above are
available on request (Facilities / Vance Ruppert).
Pictures of the annual water roof leaks as described in Section 1.1 (C) above are
available on request (Facilities / Vance Ruppert).
Option Capital Cost Start Complete
Build new above ground tanks, demolish
underground vault and tanks
off-site, with a new tank(s) arrangement.
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The main intent of this project is to avoid significant environmental risks as described in
Section 1.1 Any risks that actually occur carry with it significant O&M costs as well. For
instance, the underground pipe oil leak as described in Section 1.1(A) had a remediation
cost of approximately $100,000.
If (and when) a major environmental risk were to occur with the underground vault, such
as a burst oil tank and vault containment failure, a remediation cost of the soil below the
vault would probably start at $200,000, and would potentially reach multiples of that
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 356 of 414
Oil Storage Improvements
Business Case Justification Narrative Page 5 of 9
amount if the contamination reached groundwater. Avista would be subject to
environmental enforcement, penalties, and significant reputational harm.

Avista Facilities employee time to contend with the other issues in Section 1.1 can range
from a few hours to several days. A conservative estimation of an average Avista
Facilities maintenance employee labor rates, which includes hour rates, overhead, and
benefits, is at least $60 an hour. If an average estimate of each event requires 2
employees for 4 hours, 1 time a month, then yearly O&M savings could be assumed to
be $5,760.

In addition, the Avista senior hazardous waste technician ($75 per hour) spends at least
two and a half hours per event (with 5-10 events every year) to dewater the vault as
described in Section 1.1 (C). The 10 event estimate would calculate to a yearly O&M
savings of approximately $1,875, plus disposal costs of approximately $1000. Should
cross contamination of water occur, costs would increase by orders of magnitude.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). Include any
known or estimated reductions to O&M as a result of this investment.
The requested capital cost amount of $1.5M will be broken out between two years. In
2020, $300K will be requested to design, permit, and competitively bid the project to a
general contractor. In addition, some monies will be used to conduct environmental
investigations to determine if there are any additional unknown contaminations or failures.
The remaining $1.2M will be primarily for construction in 2021.
The project will provide the following new equipment and processes:
Two new 10,000 gallon tanks, one for new oil, and one for used but viable oil. They shall
be installed near the existing tanks at the Waste & Asset Recovery Building (WAR Bldg).
The tanks shall be above ground, surrounded by a concrete spill containment. They will
also require a covered roof/canopy, and may also require metal siding to prevent
snow/rain accumulation in the containment.
A smaller racked oil storage containers will be purchased for the Electric Shop for day use.
The new oil tank will be filled as needed by our oil supply vendor. The used but viable oil
tank will be filled by our Electric Shop (ES), a department within Avista’s Generation
Production Substation Support (GPSS) business unit.
A 500 gallon portable storage tote to be filled with new oil from the tank mentioned above.
It will be filled as required by the ES, but it is expected to be no more than 2-3 times a
year.
A 300 gallon portable storage tote to be filled with used but viable oil, or to transport scrap
oil to, the tank mentioned above. It will be used as required by the ES, but it is expected
to be no more than 2-3 times a year.
A storage area (concrete slab or asphalted) will be provided for 20 empty 55 gallon drum
barrels for new or used oil as required by the ES.
A storage area (concrete slab or asphalted), with a covered roof/canopy, will be provided
for 12 full 55 gallon drum barrels for new oil as required by the ES. It may also require
metal siding to prevent snow/rain accumulation in the storage area.
The ES will forklift the totes to and from the WAR Building. Due to the storm water
containment systems and oil water separators that have been installed on the Mission
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 357 of 414
Oil Storage Improvements
Business Case Justification Narrative Page 6 of 9
Campus over the past decades, the risk of any major oil spill events from forklift traffic is
extremely low.
The new oil tank will also provide oil to an approx. 3000 gallon Isuzu tanker truck or an
8000 gallon tanker trailer Avista owns and stores at our Beacon Substation. Both pieces
of equipment will be used as needed for large substation equipment work at both at the
Mission Campus ES, and in the field / at any particular substation.
Demolish the exising underground vault. Technique of demolition T.B.D. Option 1: remove
the entire vault including the floor slab and footings, or Option 2: remove only 6 feet or so
top-down, with existing slab and footings to remain. The removed underground vault will
be replaced with a new asphalt parking lot, approximately the same footprint, for GPSS
use.
Possility of adding siding and slider doors to the (2) existing tanks at the WAR Bldg., due
to snow/rain/ice accumulation inside its concrete containment the past few years.
In addition to the O&M savings for Avista employees as described in Section 2.1, it can
be conservatively estimated that this new process will save at least 30 minutes for two ES
employees at least once a week. The yearly O&M savings, using a $75 ES employee rate,
can be assumed to be $3,900.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.

Current processes, metrics, & data:
1) Currently, the underground vault has four tanks that can be used by the Electric Shop
(ES). There are (2) 10,000 gallon tanks to hold oil, and (2) 5000 gallon tanks subdivided
into (4) 2500 gallon compartments that hold new or used but viable oil. The (2) 5000
gallon tanks can be used as queuing tanks from either of the 10,000 gallon tanks.
2) The 5000 gallon tanks were previously accessed by the ES through direct underground
plumbing coming from the vault directly into the ES. The controls for switching between
all the tanks, and also the (4) 2500 gallon subdivided tanks, are in the vault.
3) Inside of the ES, 55 gallon drums/totes (usually around four total) were being filled using
the direct plumbed line. This practice recently ended however, due to the discovery of
the leak in the underground piping as described in Section 1.1 (A). Now that the
underground plumbing is no longer usable, if the totes need refilling, they will be
forklifted over to the external, above-ground, hose hook up located at the vault.
4) Once the full totes are placed back in the ES, the oil is manually pumped into “smaller”
pieces of equipment, as needed. Since the smaller equipment doesn’t usually require
much oil, the totes only need to be refilled maybe twice, or three times a year.
5) However, the ES will sometimes require thousands of gallons at one time to work on
larger equipment such as power transformers or oil circuit breakers, on a scheduled or
emergency basis. Instead of using the totes, the ES has a separate process.
a. Use the large tanker trailer or the smaller Isuzu tanker truck stored at Beacon
Substation.
b. More often than not, the ES will work on large equipment in the field / at the
substation. They will fill the Isuzu or our tanker trailer at our vault at Mission
Campus. After filling, they will then drive to the substation to dispense.
6) Lastly, whenever the ES needs a refill of either 10,000 gallon tank in the underground
vault, they will usually have to “shuffle” some oil between the 10,000 gallon tanks and
the 5000 gallon tanks in order to receive the full approx. 8000 gallons of oil for any
tanker truck delivery from our vendor.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 358 of 414
Oil Storage Improvements
Business Case Justification Narrative Page 7 of 9

All of the above current processes will be replaced by the new processes as described
above in Section 2.2.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
There was some discussion to build a new GPSS Shops Maintenance Building either at the
Mission Campus, or at another off-site location. There is significant risk that the scope of
such a building could fluctuate and produce a project requiring anywhere from $15M - $25M.
At this time, this is not a reasonable solution to the main problem – the environmental issues
with the underground vault and tanks.
Doing nothing was also considered, but given the difficulties numerous departments such
as Facilities, Environmental, and GPSS have endured the past few decades, as well as the
risk of a major future environmental event, the do nothing option is also not reasonable.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
This business case is considered a project, as it is not intended to be an ongoing project
beyond 2021. The major milestones and timeline of the project is estimated to be the
following:
Complete Design Drawings: 5 months
Bidding / permits complete, General Contractor (GC) selection: 2 months
GC procure tanks and long lead items: 2-3 months
GC complete new tanks: 4 months
GC complete demolition of underground vault: 2 months
The project is expected to complete and become used and useful in early-to-mid Q4 of
2021, with all of its $1.5M transferring to plant in 2021, around the same timeframe.

2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
The major reason to perform this project is to align with Avista’s stragetic vision of
environmental stewardship. It is hopeful this Business Case clearly identifies the
environmental regulatory issues that could, and probably will, occur at some point if no
action is taken.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Hopefully the environmental regulatory issues and O&M maintenance described in the
business case earlier makes a strong case that this investment makes sense, as to avoid
significant operational and environmental risks. As the project progresses, the scope and
budget will be re-baselined as required, and hopefully the project can come in possibly
under budget and ahead of schedule.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 359 of 414
Oil Storage Improvements
Business Case Justification Narrative Page 8 of 9
2.8 Supplemental Information

2.8.1 Identify customers and stakeholders that interface with the business case
Major customers/stakeholders:
Environmental Department (Bruce Howard, Darrell Soyars, Bryce Robbert, Heath Peterson,
Casey Cardenas, Luke Pate)
Generation Production / Substation Support Department (Andy Vickers, Alexis Alexander,
Brad McNamara, Loren Davidson)
Facilities (Dan Johnson, Eric Bowles, Robert Johnson, Vance Ruppert)
Minor customers/stakeholders:
Electric Operations, Fleet Maintenance, Warehouse/Stores
2.8.2 Identify any related Business Cases
Not applicable.
3.1 Steering Committee or Advisory Group Information
A. The Steering Committee (SteerCo) (as of July 2020) shall consist of the following: Dan
Johnson, Mike Faulkenberry, Andy Vickers, David Howell, Jim Corder, Lauren
Pendergraft, and Bruce Howard.

B. The Advisory Group that assisted in shaping this Business Case consisted of the
following stakeholders:
Environmental Department (Bruce Howard, Darrell Soyars, Bryce Robbert)
Generation Production / Substation Support Department (Andy Vickers, Brad McNamara)
Facilities (Dan Johnson, Eric Bowles, Robert Johnson, Dave Schlicht, Nick Lasko, Vance
Ruppert)
3.2 Provide and discuss the governance processes and people that will
provide oversight
The project shall use certain Project Management Professional (PMP) guidelines and
procedures during the course of this project.
A Project Execution Plan, consisting of the documents below, will be drafted and approved
by the SteerCo described in Section 3.1 (A).
• Project Charter, Change Management Plan, Communication Management Plan,
Cost Management Plan, Procurement Management Plan, Project Team
Management Plan, Risk Management Plan and Risk Register, Schedule
Management Plan, Scope Management Plan, and Project Execution Approval
Form.
Each month, the project manager will provide the following information either at the
scheduled SteerCo meeting, or via email.
• Approved Yearly Budget, Accrued Yearly to Date, Year Estimate at Complete, Year
Variance at Complete, Approved Lifetime Budget, Accrued Life to Date, Lifetime
Project Estimate at Complete, and Lifetime Project Variance at Complete.
Each month, the SteerCo will make decisions on cost, scope, or budget items as required
by the Project Execution Plan. The project manager reserves the right to present items not
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 360 of 414
Oil Storage Improvements
Business Case Justification Narrative Page 9 of 9
outlined in the Project Execution Plan if he/she determines its importance is relevant to
SteerCo input.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The final decisions regarding these items, especially certain change requests as required
by the Project Exectuion Plan, will be presented to, and voted upon by the SteerCo. The
decisions will be documented in a monthly meeting minutes of the SteerCo for
documentation and oversight.
It will be the Project Manager’s role to monitor the scope, budget, and schedule and present
the results to the SteerCo, regardless of they are within tolerances, or not.
The undersigned acknowledge they have reviewed the Oil Storage Improvements
Business Case and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.
Date:
Eric Bowles
Corp Facilities Manager
Business Case Owner
Date:
Dan Johnson
Director of Shared Services
Business Case Sponsor
Date:
Bruce Howard
Sr Director of Environmental Affairs
Business Case Sponsor
Date:
Andy Vickers
Director GPSS
Business Case Sponsor
Template Version: 05/28/2020
July 8, 2020
7/8/2020
7/10/2020
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 361 of 414
Campus Repurposing Phase 2
I GENERAL INFORMATION
Requested Spend Amount $28,000,000
Requesting Organization/Department Facilities
Business Gase Owner Vance Ruppert i Eric Bowles, Facilities
Business Case Sponsor Anna Scarlett, Manager, Shared Services
Sponsor Organization/Department Shared Services
Gategory Project
Driver Performance & Capacity
1.1 Steering Gommittee or Advisory Group Information
The Campus Repurposing Phase 2 Steering Committee is made up of a cross
section of directors that represent groups impacted by the projects, as well as a
couple members not directly affected to add an outside view. The current group is as
follows:
o Director of Environmental Affairso Director of Shared Serviceso Director of lT and Security. Director of Natural Gaso Director of Financial Planning and Analysiso Director of Operations
Advisors may contribute input; approvals, or information as needed, and include:
o Vice President of Energy Deliveryo Executive Officerso End Users
Each project within this business case is reviewed and approved by the Steering
Committee group, and regular updates are provided during project execution.
2 BUSINESS PROBLEM
The Campus Re-Purposing Plan is a multiyear plan (Phase 1 and Phase 2) that
address the following issues:
. Employee space needs. lmproving safety and efficiency of campus traffic flowo Outdated fleet maintenance space and processeso Lack of materials storage yards, no short-term flexibility
Business Case Justification Narrative Page 1 of20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 362 of 414
Campus Repurposing Phase 2
Alignment of campus parking and number of employees based at main
campus
The Avista corporate campus comprises 28 acres located next to the Spokane River
in heart of the Logan Neighborhood. The campus in just north of the downtown
Spokane corridor. Avista also owns eight additional acres of property directly
adjacent to the campus at the north end. This parcel is separated from the main
campus by North Genter Street (a main city arterial).
Avista's corporate campus footprínt is currently bound to the east by the Spokane
River, and to the west and south by the Mission Park and Burlington Northern
Railroad, leaving minimal flexibility to manage company parking, employee and
materials space needs.
The Avista corporate campus was built in 1958 to consolidate and house all utility
operations that were at that time spread throughout the community. As business
needs changed over time, one-off expansion projects were to reactively address
changes in business need. Employee growth and materials storage increases
through the years have created the need to locate employees and materials at
offsite locations, requiring space leases and other non-optimal solutions to meet
growing company space needs.
Business Case Justification Narrative Page 2 of 20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 363 of 414
Campus Repu ng Phase 2
Strategic property purchases to the North of the campus have been ongoing since
1988 as they become available to help address the issue and grow the campus to
give us future flexibility. The final properties between Avista and the neighboring
Riverview Retirement Community were purchased in 2014, now allowing us to
develop them for company use.
The decision was made in 2011 to take a holistic approach to these issues and
create a single proposed solution for the Corporate Campus that would address
current issues, and future needs. The campus repurposing planning group began
working in 2011 to find a way to address the growing employee space needs,
parking issues, campus materials storage issues, safety and traffic flow issues
(Operations traffic and employee traffic mixing), as well as look into addressing the
changing business needs of our vehicle fleet and operational processes.
The result of this approach is a total campus plan that repurposes the existing
campus for the next 50 years, minimizing our reactive approach and ensuring the
best long term results for the Company and Ratepayers.
3. PROPOSAL AND RECOMMENDED SOLUTION
Campus Repurposing Phase 2 includes three major projects:
1. North Genter Re-Route
2. Construct New Fleet Building
3. Construct Parking Garage
These three projects are connected and largely dependent on each other because of
location, timing and the overall campus design. The projects will ultimately allow us
to:o Expand and consolidate the campus footprint while establishing a formal
boundary between the Avista campus and the Riverview campus.o Modernize the aged Fleet Building and address Fleet queuing needs.. Expand and locate campus parking to align the available number of parking
spaces with the number of employees working onsite, improving employee
and public safety by reducing parking sprawl.. Separate operations traffic from pedestrian traffic to improve safety and
i ncrease workflow efficiencies.
Business Case Justification Narrative Page 3 of 20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 364 of 414
Campus Repurposing Phase 2
7.72 ^<t6Pr6i cilb.n.Ur ¡ilpint fùrn
[!:: ia I n'"t-
Í6!rcmnt Resh
Proiect 1: North Center Street Re-Route
Avista-owned properties separated from campus by North Genter Street
North Center Street currently divides us from the eight acres of property owned to
the north on Ross Court. Re-routing North Center Street will allow us to
consolidate our campus to include these properties. As North Center Street is a
major city arterial that connects lndiana Street to Upriver Drive, a considerable
amount of traffic uses the street daily. This traffic creates an ongoing safety risk to
employees moving back and forth between the properties. lt also creates
challenges with securing the lots during business hours (gates, entrances, etc.).
Beginning in 2013, Avista began discussion with Riverview to plan the future
development of each of our campuses. Riverview management expressed
concern with future development on our adjacent properties due to the proximity of
these properties to their resident housing. With no formal separation between our
campuses, they were concerned with the height of proposed buildings as well as
idling dieseltrucks next to their resident properties.
Several options were considered (see options listed below). After many
discussions, there was interest on both sides to explore rerouting North Center
Street to the north in order to: 1) consolidate our properties into our secured
campus; and 2) give Riverview a formal separation between our campuses.
Business Case Justification Narrative Page 4 of20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 365 of 414
Campus Repurposing Phase 2
Ross CouÉ Property Optlons
(¡e-routo of North Center Street)
Gapltal
Cost
9fârt Complete RIsk Mitigatlon
Option 1 (Recommended):
North Center rerouted around our
Ross Court properties, adding eight
acres to the Campus
$6M 2016 2017 Riverview prefers this
option due to formal
separation.
Option 2: no reroute (minimum
development required to make
Ross Court property usable).
North Center Street remains in place
creating a separated campus to the
North, accessed by crossing North
Center. Fencing, gates, and lot
development still req uired.
$3,000,000 2016 2017 Risk involved in
transporting materials
across a major City
Arterial. Strong
opposition from
Riverview on any
development other than
basic storage.
Option 3: no reroute, with tunnel or
bridge connection to Ross Court
North Center Street would remain and
a tunnel or bridge would be created to
safely access Ross Court and create
a single secured Campus.
$8,000,000 2016 2017 Higher maintenance
costs for bridge or
tunnel. Strong
opposition from
Riverview on any
development other than
basic storage
Option 4: Do nothing $0 Basic storage use only with no development.
Property does require basic Civiland site
work to be usable though.
Option 7 hecommended): Reroute North Center Sfreef to consolidafe Ross Court
properties with the main campus.
The re-route of North Center Street would allow us to create a new operations entrance
to our campus, separating operations traffic from pedestrian traffic and resulting in
operations workflow efficiencies and improved safety of the company and employees.
Business Case Justification Narrative Page 5 of 20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 366 of 414
Campus Repurposrng Phase 2
Recommended Option
Positive Benefits Neqatives
Allows the creation of a new Operations entrance lssues with Citv permittino?
Riverview's preferred option due to formal separation. No
opposition to future developments options
Closure of North Crescent Street to
access aoartments behind Riverview
Single con nected/secured Campus
Better Operations traffic flow from entry, drop off, and
oarkino
Create a formal separation between Avista and Riverview
Better separation of employee and Operations traffic would
dramatically lessen safety risk to the company
Business Case Justification Narrative Page 6 of 20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 367 of 414
Campus Repurposing Phase 2
Options 2 and 3: No reroute. leave North Center Street in place and secure as
separate campus.
A minimum of Option 2 or 3 would be required to make the Ross Court properties
usable; however, these options would not allow separate operations entrance to be
added.
Optionsl and 2
Positive Benefits Negatives
Lower cost options
(Option I lower cost, Option 2 similar cost)
Development options we are considering would be
strongly opposed by Riverview due to direct
adjacency of our operations to their resident
properties
Slightly larger usable area vs Option 1 Two separate campuses requiring constant traffic
across North Center Street creates safety risk
(Alternative 2 only).
Alternative 2 would create a single Campus
access
Alternative 2 would require higher O&M cost for
tunnel or bridge
Quicker project execution These 2 alternatives will not allow for a new
Operations entrance
Business Case Justification Narrative PageT oÍ20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 368 of 414
Campus Repurposin g Phase 2
Proiect 2: Gonstruct New Fleet Ooerations Facilitv
Avista's existing fleet operations building is located in the heart of the main campus and
was originally built in 1958 to centralize all Avista fleet maintenance operations.
Vehicle and Building Size
The original fleet building was built to house smaller half-ton pick-ups and has been
expanded twice through the years to accommodate the increased size of the new
service trucks, once in 1978 and again in 1999. The size of vehicles in today's fleet
have continue to increase since 1999 and some of the current fleet is difficult to service
in the existing building. The current building is much smaller than City of Spokane and
Waste Management facilities, which utilize similar-sized vehicles. Many of our larger
trucks cannot be worked on in the existing space without leaving the doors open.
Existing Fleet Building Location
Business Case Justification Narrative Page I of 20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 369 of 414
Campus Rep osing Phase 2
CNG
Avista has added vehicles fueled by compressed natural gas (CNG) to our fleet over the
past four years. The existing fleet building is not CNG rated and all CNG-fueled vehicles
must be taken offsite for repairs. To make the building CNG compliant would require the
addition of a new emergency exhaust system. The estimated cost to make the building
CNG compliant is around $1.3 Million
Environmental
The hydraulic lift system installed in the existing building did not include secondary
containment when originally installed, and testing has indicated possible leakage of
hydraulic oil in the soil under the building. Relocation of the building will allow us to
completely encase all new hydraulic systems and mitigate any current or potential
leakage.
Safety
The existing fleet staging and queuing area is also in the heart of the campus and is
directly adjacent to multiple parking canopies and surface parking areas. This staging
area is small and requires multiple trips in and out of the area for day-to-day operations.
A main employee walkway also goes through this major traffic area and brings
considerable safety risk to the company as some of the pedestrian traffic can be hidden
by the parking canopies. Moving the fleet building to the north will allow for increased
queuing area and lessen the employee and operations traffic risk considerably.
Building Gonditions
ln addition to compliance, environmental and safety issues, the existing building has a
number of conditions that affect operations and employee safety and health, including
the issues below (see attachment Corp Fleet Building /ssues for complete list).
r Current facilities have bays less than 14' wide. Current trucks are 103" wide at the
mirrors, leaving limited space for maneuvering and working on vehicles.o We cannot lift rear tandem axle trucks with in ground lifts. We utilize wheel lifts which
add 38" to the width of the vehicle. This leaves less than 2' for the technician to
move himself and his tools into position. Tandem axle trucks make up 35% of the
Avista Fleet. This effects productivity.. Roof leaks at multiple points.
Options and Alternatives
Fleet Operatlons Optlons Capital
Gost
Start Gomplete Rlsk Mitlgatlon
Option 1 (Recommended): Build a
new CNG-compliant Fleet
Operations building at the north
end of the property and address the
existing issues.
o This options would allow us to use
the existing fleet footprint for the
Parkino Garaqe and move all
$10,000,000 2017 2018 Major safety risk
mitigated with
employee and Ops
traffic mixing.
Business Case Justification Narrative Page 9 of 20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 370 of 414
Campus Repurposrng Phase 2
Operations traffic to the North end
of the Campus.
Option 2: Address the major issues
in the existing building separately.
. Replace Hydraulic systems,
replace the constantly leaking roof,
and installa CNG compliant
exhausting system.
o lncrease the building in the future
if needed.
$4,000,000 2017 2018 . Location not optimal
in regards to safety
and risk
o Environmentaland
compliance issues
o Continued rising of
maintenance costs
due to age of the
building and
systems
Option 3: Do nothing $0 Still need to address the future impact of
larger fleet vehicle sizes, aging hydraulic
systems, non-compliant CNG space, and most
importantly the safety risk due to the constant
traffic and employee mixing.
Option 1 (recommendedl: Construct a new fleet operations facilitv at the north
end of the campus.
Constructing a new fleet operations center operations building strategically located at
the north end of the campus would achieve a number of objectives:
o Enable us to increase the size of bays to accommodate larger fleet vehicleso Address CNG compliance requirements and environmental issues related to the
aging current facilityo Increase efficiency and safety of pedestrians and operations traffic on campuso Increase efficiency of fleet operations
A pre-design BPI process was undertaken in early 2016 to look at efficiencies that
would be created by a new building and new processes. lt was discovered that the poor
layout of the existing building resulted in numerous extra steps taken each day resulting
in wasted time and resources. The new building was designed using industry best
practices, and observed employee workflow.
Business Case Justification Narrative Page 10 of20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 371 of 414
Campus Repurposing Phase 2
BPI Spaghetti workflow diagram
See attached buttet points for a comprehensive /isf of rssues that a new building would
address.
Recommended Option: New Fleet Building on Ross Gourt
Business Case Justification Narrative Page 11 of20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 372 of 414
Camp us Rep urposing Phase 2
Option 2: Address individual issues with existins buildins
Remodeling the existing building to accommodate fleet vehicles that no longer fit the
current facility is not possible within the current footprint's size. ln addition, this option
does not address environmental, compliance or safety concerns described above. To
make the building CNG compliant would require the addition of a new emergency
exhaust system. Íhe estimated cost to make the building CNG compliant is around $1 .3
Million
Option 3: Do Nothins:
Doing nothing is not a viable option. New hydraulic lifts would be required soon, and basic
space, environmental and compliance issues would still need to be addressed. We would
need to reevaluate how to continue servicing CNG vehicles.
Business Case Justification Narrative Page 12 of 20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 373 of 414
Campus Repu g Phase 2
Proiect 3: Parking Garage
As of June 2016, Avista has a headcount of approximately 1,280, including company
and contracted employees, reporting to the main campus facility. The number of parking
spaces available for employees is approximately 728 (not including visitor and disabled
parking). Assuming not all employees are on the property at any one time, a minimum
of 400 additional parking spaces are required each day to address the current existing
need as well as additional spaces for future flexibility. Avista leases parking space along
Perry Street from Burlington Northern Railroad (BNR), in an open-ended lease that can
be cancelled by BNR with 30 days written notice. Employees walk across railroad tracks
to get to and from the buildings and these parking areas. Additionally, loss of this lease
would result in the loss of almost 200 parking spaces.
Aligning campus parking with employee count has been addressed through the years
by relocating materials storage yards from the campus footprint and adding surface
parking lots (see below).
Mission Campus Parking Space Count 2008 538
2009 +57Added Spaces South Mission Lot
2009 +55Added Spaces Transformer Storage Lot
2012 +124Expanded North Pole Yard
2012 +49Added North Ross Court
823Total Current Parking Spaces
(includinq Disabilitv and Visitor Parkins)
728Total Parking Spaces Available
(excludinq Disability and Visitor Parking)
Estimated Employees/Contractors Assigned to Mission
Campus as of June 2016*
1282
Estimated Employee/Contractors e not at Mission Campus
on any one day (15Yo)
-129
425**Shortage of Parking Spaces to Meet Current Need for
Employees/ Contractors Assigned to Mission Gampus**
Year ParkingAction Taken
cesS
Business Case Justification Narrative Page 13 of20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 374 of 414
Campus Repu osing Phase 2
Using valuable campus real estate for parking lots has required us to take our
operations vehicles and materials storage offsite to our Beacon substation property
more than a mile away, increasing crew time and resources to access materials and
vehicles each day.
This daily deficit in parking is currently absorbed in gravel lots on Ross Court and along
the railroad tracks on Burlington Northern Railroad land. This parking is not in
compliance with City of Spokane parking code, and we could be required to cease at
any time. Additional parking overflow beyond these locations usually takes place in the
immediate neighborhoods around Avista, and has resulted in frustrated calls, threats,
and visits from our residential neighbors.
The proposed parking garage is intended as a long-term solution to the employee and
visitor parking deficiency and related safety concerns.
Safety
With our current parking conditions, employees and visitors face a number of ongoing
safety risks:
Business Case Justification Narrative Page 14 of 20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 375 of 414
a
a
a
a
Campus Repurposing Phase 2
The main building and service center, where the majority of regular and contract
employees are located, is separated from parking areas by railroad tracks, busy
arterials (Mission and Perry Streets), and operations areas, forcing pedestrians
to cross these areas throughout the day.
Operations traffic peaks in the mornings and afternoons, when employees are
often walking to or from their vehicles.
Parking areas are open and must be maintained throughout year to keep lots
safe and clear of seasonal conditions. Even with ongoing maintenance, lost work
days due to slipping and falls on the main campus (both inside and outside) is
estimated at 11,000 days since 1997.|n the first quarter of 2017, Avista
experienced a record number of slips, trips and falls related to icy conditions.
While we have full-time security on campus with cameras and patrol staff, there
is no security off campus to protect employees, visitors and their vehicles.
Parking lmpact 2016
Options and Alternatives
We analyzed three primary options for adding up to 500 parking spaces to fully solve
the parking issue and give protection against the loss of the BNR leased space:
. Option 1 (recommended) - Construct a parking garage in the location of the
original fleet building. The garage would be a four-story structure with five levels
of parking.
Business Case Justification Narrative Page 15 of20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 376 of 414
Campus Repurposing Phase 2
Option 2 - Convert property at the north end of campus (Ross Court) into
parking lots.
Option 3 - Purchase properties to the east of campus, across Perry Street, and
develop parking lots.
Roes Gsurt Property Options
{re-routs of North Center Street)
Gapltal
Gost
9tart Completo Risk Mitigation
Option I (Recommended): Build
Parking Garage
Build a 4-story 500-space parking
garage in the location of the
existing Fleet Building.
$12,000,000 2018 2018 o Coverage in the event
of the loss of BNR
leased space.
. Employees would not
need to park in the
neighborhood.
Option 2: Convert Ross Gourt
property into parking to
address current deficit
Pave the remaining four acres of
undeveloped Ross Court property
and make a parking lot. Would
need to include drainage swales,
parking island vegetation, and
sidewalks to be comply with city
code.
$3,000,000 2017 2018 . Not highest and best
use of existing property.
Will only net -175.
spaces.
o Would impact Fleet
construction project as
this space is earmarked
for the new building.
. Risk of impact from
losing BNR lease still
possible.
Option 3: Purchase properties
to the east of Avista to build 500
parking spaces (10 acres
required)
Purchase 10 acres of property
along Perry to the east and
develop to create 500 parking
spaces.
$16.2M 2016 2017 ¡ Risk of not getting all
properties.
o Highest maintenance
costs (snow removal,
crack seal, seal coat,
1S-year average
asphalt replacement)
Option 4: Do nothing $o a
a
a
Risk of City of Spokane compliance issues
with using Ross Park in its current form.
This can be called out at any time.
Negative perception from local neighbors
due to parking overflow in front of their
houses.
Loss of BNR lease would be catastrophic to
employee parking with no immediate
resolution.
Option I (recommendedt: Build a 4 storu Parkins Garase
This option will minimize the physical footprint required (only 0.71 acres). Constructing it
in the location of the original Fleet Building will locate parking density next to employee
workspace density, maximiz¡ng safety and operations efficiency.
a
a
Business Case Justification Narrative Page 16 of20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 377 of 414
Campus Repurposing Phase 2
Option I (Recommended): Buildins a four-etory parking garage with five levels of parkins
Positive Benefits Negatives
Locates parkinq densitv near emÞlovee densitv Customer perceotion of structure
Willdrastically reduce slips, trips and falls experienced by
employees walking through 20 acres of existing parking lots
each day, reducinq risk and L&l claims to the Company.
Possible environmental issues under
existinq fleet footprint
Majority of parking would now be secured within the Campus.
Will dramatically reduce the risk to the company from
emolovee and Operations traffic mixinq in the north lot areas.
Lowest O&M maintenance costs, and longest life vs. asphalt
lot.
Lowest snow removal cost vs.10 acres of traditional blacktop.
Could allow us to repurpose campus real estate back to
materials storaoe.
Parking Garage Footprint
Option 2: Convert Ross Court property into parking to address current deficit
Converting property on the north side of Campus (Ross Court), would only address part
of the current park¡ng deficit, with a net of approx. 175 spaces. This solution doesn't
address a potential BNR lease loss and would impact plans for the new fleet facility.
Option 2=Pave existing Ross Gourt properties to be used for parking
Positive Benefits Negatives
Lower cost vs. recommended Not highest and best use of purchased properties on Ross
Court. High cost vs strategic value (when including property
purchases). No option for a new Fleet Building.
Quickest Solution Solution would only address the current parking deficit, (only
net approx. 175 spaces) Doesn't address BNR lease loss.
Business Case Justification Narrative Page17 o120
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 378 of 414
Campus Repurposing Phase 2
Option 3: Purchase properties to the east of Avista to build 500 parkins spaces
Traditional parking lot construction for 500 spaces would require 10 acres of land to
accommodate 208 drainage swales, vegetation for heat island mitigation, and other
items required by the City of Spokane. The only available option for adding additional
land to the campus would be the properties to the east, on the other side of Perry
Street. These would be difficult and costly to acquire, and add additional challenges of
expanding the campus into a residential area separated by a major arterial.
500 spots using surface parking construction
Option 4: Do Nothins
This option would not solve the parking deficiency or the problems it has created:
o Operations vehicles and materials storage offsite at Beacon substation property. Non-compliantparkingo Neighborhood impacts
[:l I lcrcs -tÞJ ..
10.5 Â(res
pra¡¡ <lil, to ailbla aô¡p9rñ1. Îlrn
off ihc Àllorurañcd rooi to ç_tnø
Option 3: Purchase l0 acres to the east and build 500 spaces
Positive Benefits Negatives
Would net the full 500 spaces Highest cost option
High risk of not getting all properties required to build. Risk of
street vacations not beino approved.
lncreased risk of injury with 500 employees crossing Perry
Street dailv.
Highest cost maintenance option, (snow removal, crack seal,
sealcoat, complete asphalt replacement every 15-20 years).
Business Case Justification Narrative Page 18 of20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 379 of 414
Campus Repu ing Phase 2
Do Nothins
Positive Benefits Neqatives
Lowest Cost Does not address the current parkinq deficit
Still out of compliance with current City of Spokane parking
code
Frustration from neighbors due to employees parking in front of
their houses.
At risk if BNR lease is ever lost.
Ongoing Parking (O&M) Cost
S3oo
Szso
s2oo
s1s0
$i.oo
Sso
So
Alternate 1 Alternate 2
Ongoing O&M costs include snow removal, crack seal, seal coat, and asphalt renewalat 15 years.
Parking Garage useful life based on 45 years.
See attached PowerPoint Presentations for high level explanations
Ec(!
o-c!-
I
Preferred
Business Case Justification Narrative Page 19 of20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 380 of 414
Campus Repu ng Phase 2
APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Campus Repurposing
Phase 2 plan and agree with the approach it presents and that it has been approved
by the steering committee or other governance body identified in Section1.l. The
undersigned also that significant changes to this will be coordinated
with and approved ndersig or their designated representatives.
Signature:
Print Name:
Title:
Role:
Signature:
Print Name
Title:
Role:
Signature:
Print Name
Title:
Role:
Eric Bowles
Business Case Owner
Manager, Facilities
Date:sf, lrt
Date L1-Zg_t-7
-A* S2"*O"U-Date çl ,l (t
Anna Scarlett
Manager, Shared Services
Business Case Sponsor
Heather Rosentrater
Vice President, Energy Delivery
Steering/Advisory Com mittee Review
VERSION HISTORY
Tem plate Version : 02124 1201 7
Vercion lmplemented
By
Revleion
Date
Approved
By
Approval
Dato
Reason
1 Eric Bowles 04t24117 Heather Rosentrater 04t25t17 New template
Business Case Justification Narrative Page 20 of 20
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 381 of 414
Gas Operator Qualification Compliance
Business Case Justification Narrative Page 1 of 6
EXECUTIVE SUMMARY
As an operator of gas infrastructure, Avista Utilities is required by regulation to minimize the impact of safety
and integrity of the pipeline facilities due to human error that may result from an individual’s lack of knowledge,
skills, or abilities during the performance of certain activities, or covered tasks. Craft Training and Gas
Operations are responsible for ensuring a qualified and competent workforce. This is partially accomplished
by evaluating and qualifying internal and contract employees on Operator Qualification tasks specific to
Avista’s natural gas infrastructure.

This business case will provide the tooling, vehicles, and equipment necessary to enable internal Avista
Evaluators to evaluate Avista “non-peer” employees and contract personnel under the PHMSA regulations
for Operator Qualification. Further, the tooling, vehicles and equipment may be used by Avista’s Evaluators
to maintain proficiency in the tasks required by the program and to design, construct and implement new
testing tools, techniques and technologies. Not providing these resources would result in the Evaluators
being unable to perform their duties, possibly resulting in regulatory penalties and incidents that impact
Avista’s customers and the public. This project will support Avista’s gas operations in Idaho, Washington
and Oregon. The total cost of the recommended solution to support these activities is $185,000 over a 5-
year period or $37,000 annually.

VERSION HISTORY
Version Author Description Date Notes
Draft Joe Brown Executive Summary Only 7/6/2020 Business Case 2020 Refresher
1.0 Joe Brown Final version for 2020 capital update 7/29/2020 Full amount approved

GENERAL INFORMATION

Requested Spend Amount $185,000
Requested Spend Time Period 5 years
Requesting Organization/Department Craft Training and Operator Qualification [I02]
Business Case Owner | Sponsor Joe Brown | Jeremy Gall
Sponsor Organization/Department Human Resources
Phase Execution
Category Program
Driver Mandatory & Compliance
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 382 of 414
Gas Operator Qualification Compliance
Business Case Justification Narrative Page 2 of 6
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Growth and high attrition rates in the Natural Gas industry has led to a workforce shortage of trained and
competent personnel. Employing this workforce has resulted in several safety and quality control issues on
Avista’s natural gas infrastructure.
Currently, Avista Utilities evaluates internal personnel by utilizing loaned employees from Gas Operations to
evaluate other peer employees. The utilization of peer craft employees to conduct evaluations is not recognized
as a best practice in the natural gas industry.
Further, Avista’s Gas Contractors train and evaluate themselves on Avista’s covered tasks. These activities are
conducted independent of Avista’s oversight. Evaluation of contract employees by contract employees, with no
utility oversight, is not recognized as a best practice in the natural gas industry.
Recent safety and quality incidents in the field and questionable evaluation practices has demonstrated the need
for direct evaluation by internal, “non-peer”, Avista evaluators for Operator Qualification. This unbiased evaluation
practice will determine the knowledge, skill and ability of personnel and ensure the integrity of qualifications.
The following regulations outline the requirements of Operator Qualification that must be met by Avista as an
Operator of a natural gas utility. These requirements apply to both internal and contract employees.
1. Background. 49 C.F.R. §§ 192.803 through 192.809 prescribe the requirements associated with qualifications
for gas pipeline company personnel to perform "covered tasks." 49 C.F.R. § 192.801 contains a definition of
"covered task." In WAC 480-93-999, the commission adopts 49 C.F.R. §§ 192.801 through 192.809. However,
in this section, the commission includes "new construction" in the definition of "covered task."
2. Accordingly, for the purpose of this chapter, the commission defines a covered task that will be subject to the
requirements of 49 C.F.R. §§ 192.803 through 192.809 as an activity, identified by the gas pipeline company,
that:
a. Is performed on a gas pipeline;
b. Is an operations, maintenance, or new construction task;
c. Is performed as a requirement of Part 192 C.F.R.; and
d. Affects the operation or integrity of the gas pipeline.
3. In all other respects, the requirements of 49 C.F.R. §§ 192.801 through 192.809 apply to this chapter.
4. The equipment and facilities used by a gas pipeline company for training and qualification of employees must
be similar to the equipment and facilities on which the employee will perform the covered task.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant & Operations) and the benefits to the customer
The primary business driver for this business case is Mandatory & Compliance and the secondary drive is
Customer Service Quality. Avista must have and execute an OQ Program in order to maintain compliance with
laws, rules and regulations. Secondarily, the safety and quality of Avista’s gas delivery business is greatly
impacted by the testing program carried out through the implementation of the OQ program.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Avista’s OQ Program is in its implementation stage and must be funded. Deferring or canceling this funding
altogether exposes the company to regulatory risk and possible fines.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 383 of 414
Gas Operator Qualification Compliance
Business Case Justification Narrative Page 3 of 6
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The implementation of this new evaluation process for the OQ Program began on June 1, 2020. Monitoring,
metrics and reporting will be developed based on this implementation stage. Currently, Avista has more than
350 active contractors that go through testing and evaluation. Lagging safety and quality metrics may be used
in the future to assess the success of this change in program execution.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
No studies have been conducted to date. This business case supports an industry “best practice”
where non-peer employees with evaluate personnel on OQ tasks.
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
NOT APPLICABLE

The proposed solution is to obtain the resources needed for OQ Program evaluation
This is the least cost alternative from a capital perspective when considering the risks associated with outsourcing
the OQ evaluations to a third party, or fully funding all tools and equipment.

Option Capital Cost Start Complete
1. OQ Evaluator Tools and Material – Partial $185,000 01 2021 12 2025
2. OQ Evaluator Tools and Material – Full $460,000 01 2021 12 2025
3. Outsource OQ Evaluator Program $0 01 2021 NA
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
For the recommended solution (Option 1) [OQ Evaluator Tools and Material – Partial], this amount is based
on the estimate of tools and equipment that will need to be purchased and utilized annually in order to
support the program. The tools and equipment in this solution will be shared among the Spokane and
Oregon locations and there will not be significant duplicate. This will slightly increase O&M expense due
to travel and sharing of equipment among evaluators.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (i.e. what are the
expected functions, processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M as a result of this investment.
This is a compliance program and there are no O&M offsets associated with the project.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
The greatest impact of this business case is on Gas Operations and Avista’s Gas Customer. Gas
Operations contracted resources will be tested through this program which may result in safer, higher
quality work products. Avista’s Gas Customer may receive safer, better service in the areas where Avista
utilizes contract personnel for gas work.
Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 384 of 414
Gas Operator Qualification Compliance
Business Case Justification Narrative Page 4 of 6
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
For the recommended solution (Option 1) [OQ Evaluator Tools and Material – Partial], this amount is based
on the estimate of tools and equipment that will need to be purchased and utilized annually in order to
support the program. The tools and equipment in this solution will be shared among the Spokane and
Oregon locations and there will not be significant duplicate. This will slightly increase O&M expense due
to travel and sharing of equipment among evaluators.

For Option 2, it is estimated that Avista may need to spend $92,000 annually in order to purchase each
evaluator their own tools and equipment utilized for skill evaluations. This would include upgrading existing
equipment and replacing all outdated equipment. This includes many of the tools and materials utilized
by contractors, such as leak survey and locating, that are extremely capital intensive. We believe the
prudent decision is to share this equipment among the evaluation areas and reduce the overall capital
spend.

Finally, for Option 3, OQ skill evaluations could be outsourced to a 3rd Party contract resource. This
outsourced testing model has been adopted by some peer companies. This option is estimated to cost
more than $600,000 in O&M alone, not to mention the risk this option would pose from an employee morale
and labor relations perspective. Further, this option does not drive a culture of safety, compliance and
quality that we hope to achieve by executing on Option 1.
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the customer.
spend, and transfers to plant by year.
Equipment and tools will be purchased on an annual basis and will become ‘used-and-useful’ during the
year as the evaluators implement the resources in the field.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This investment aligns with two of Avista’s key Focus Areas of ‘Our Customers.’ and ‘Perform.’.
When it comes to Avista’s customers, this program promotes transparency in the safety, quality and
integrity of Avista’s work product delivered to each customer. The safety and integrity of the gas system
depends on a highly skilled workforce, and this program helps ensure these skills meet or exceed Avista’s
standards. Regarding performance, this program helps ensure customers are served with safe and
reliable infrastructure.

2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
Avista must comply with laws, rules and regulations as well as provide customers with safe, reliable gas
resources. This program helps ensure the safety and quality of Avista’s gas system. As stated previously,
this program was implemented on June 1, 2020 and monitoring, metrics and reporting will be developed
as part of the ongoing program as it is executed.
2.8 Supplemental Information

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 385 of 414
Gas Operator Qualification Compliance
Business Case Justification Narrative Page 5 of 6
2.8.1 Identify customers and stakeholders that interface with the business case
Key internal stakeholders include Craft Training, Gas Operations, and Compliance. Key external
stakeholders include Avista’s Customers and 3rd Party Contractors.
2.8.2 Identify any related Business Cases
NA
3.1 Steering Committee or Advisory Group Information
See the governance process below
3.2 Provide and discuss the governance processes and people that will
provide oversight
As a practical matter, the OQ Evaluators [3] will plan their needs for tools, materials and equipment with the
Manager or Craft Training &OQ. The team will prioritize their needs and manage the funds accordingly.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The Manager or Craft Training & OQ will be responsible for prioritization, change requests, documentation and
monitoring of this project.

Exhibit No. 11 Case Nos. AVU-E-21-01 & AVU-G-21-01 H. Rosentrater, Avista
Schedule 9, Page 386 of 414
Gas Operator Qualification Compliance
Business Case Justification Narrative Page 6 of 6

The undersigned acknowledge they have reviewed the Gas Operator Qualification
Compliance Business Case and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.

Signature: Date:
Print Name: Joe Brown
Title: Mgr Craft Training & OQ
Role: Business Case Owner

Signature: Date:
Print Name: Jeremy Gall
Title: Sr. Mgr Safety & Craft Training
Role: Business Case Sponsor

Signature: NA Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review

Template Version: 05/28/2020
7/29/2020
7/30/2020
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