20250306AVU to Staff 37 Attachment C.pdf

Staff PR 037 Attachment C
Business cases with actual transfers to plant between July 2022 through June 2024 that were not in
Avista's filed pro forma period and therefore no business case was provided in Direct Testimony.
Business Case Function Page
Asset Monitoring System Generation 2
Atlas ET 7
Base Load Hydro Generation 17
Base Load Thermal Program Generation 25
Cabinet Gorge Unwatering Pumps Generation 34
CIP v5 Transition - Cyber Asset Electronic Access ET 40
Clearwater Wind Generation Interconnection Transmission/Substation 46
Enterprise & Control Network Infrastructure ET 53
Enterprise Business Continuity ET 62
Gas ERT Replacement Program Natural Gas 70
Gas Overbuilt Pipe Replacement Program Natural Gas 82
Generation DC Supplied System Update Generation 89
High Voltage Protection(HVP) Refresh ET 96
KF_Fuel Yard Equipment Replacement Generation 105
LED Change-Out Program Electric Distribution 117
Long Lake Stability Enhancement Generation 126
Monroe Street Abandoned Penstock Stabilization Generation 136
Nine Mile HED Battery Building Generation 144
Nine Mile Powerhouse Crane Rehab Generation 153
Nine Mile Powerhouse Roof Replacement Generation 161
Noxon Rapids Spillgate Refurbishment Generation 168
Oil Storage Improvements Facilities 176
Primary URD Cable Replacement Electric Distribution 187
Protection System Upgrade for PRC-002 Transmission/Substation 191
Saddle Mountain 230/115kV Station(New) Integration
Project Phase 2 Transmission/Substation 197
Strategic Initiatives - South Landing (Catalyst) - Clean
Energy Fund 3 Strategic 204
Strategic Initiatives -UTASSIST Strategic 210
Telecommunication&Network Distribution location
Security ET 218
Upper Falls Trash Rake Replacement Generation 230
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Asset Monitoring Systems
EXECUTIVE SUMMARY
The yearly amount of $250k is based on Asset Monitoring Systems that are needed to
track the condition of our Assets. These systems are in both our Hydro and Thermal
Generation Plants. They are not part of the Generation Control System that is used for
real-time control and monitoring. There is a need to update the existing systems and
install new systems to monitor the condition of our Assets. These Asset Monitoring
Systems are used to influence our Maintenance and Capital planning. The budget
amounts are based on 2022 quotes for replacing, updating, and installing new systems.
These systems will interface with the corporate network and therefore need to be updated
periodically to keep up with changing software and security needs.
The risk of not approving this yearly amount will cause our Asset Monitoring Systems to
become obsolete and therefore move us back to a reactionary place upon assets failure.
This business case has been reviewed and approved by GPSS Management.
VERSION HISTORY
Version Author Description Date Notes
1.0 Glen Farmer Draft and review 4/8/2022
2.0 Glen Farmer SCRUM Update and Approval to move 511812022
forward.
2.1 Glen Farmer Submit for Approval 6/1/2022
2.2 Glen Farmer Finish Business Case Info 8/23/2022
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Asset Monitoring Systems
GENERAL INFORMATION
Requested Spend Amount $250,000
Requested Spend Time Period Per year
Requesting Organization/Department G07
Business Case Owner I Sponsor Glen Farmer Alexis Alexander
Sponsor Organization/Department GPSS
Phase Initiation
Category Program
Driver Asset Condition
1. BUSINESS PROBLEM
1.1 The Generation Plant Assets have asset monitoring that can give us indication
of performance and values that can give us trending condition of the asset.
These systems become outdated or obsolete based on the manufactures
software being unsupported. Also, some systems have a limited number of
testing that can be performed based on the system parameters.
1.2 The driver for these Asset Monitoring Systems is Asset Condition. When these
systems are working correctly was can use them to give us indication of
degrading condition. From there we can start the process of putting a Business
Case together before the Asset fails. In the past we would wait until the Asset
failed, then we would apply a temporary fix to give us time to start the Business
Case process.
1.3 The risk, if not approved, is we would be looking at an indicator of failure, then
doing a temporary fix then replace. This takes time to get things approved and
in the budget. Our budget is fixed and when failures happen then that moves
out other projects.
1.4 We have used these Asset Monitoring Systems to give us indication of the Asset
Condition. Based on the trending of the data the condition of the asset will at
some point be switched off-line when the Monitoring and Control Systems gives
us indication of a failure or potential failure. In the past we have reduced the
capacity of system or the runtime of the system to give us some time to get a
replacement project going. In these cases, the megawatt output is normally
reduced, and we are hoping that it will make it until the fix can be engineered,
procured, and installed.
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Asset Monitoring Systems
1.5 Supplemental Information
1.5.1 Manufactures letters indicating that product support will no longer be
available is the first indication that we receive. When that happens then
we can no longer update the computer systems that is running the
software. At some point the computer system must be upgraded which
brings about a new operating system. The new operating system requires
a new interface box, and the software must be upgraded to run on the
latest operating system.
2. PROPOSAL AND RECOMMENDED SOLUTION
The recommended solution is to update the Asset Monitoring Systems with the latest
manufactures supported equipment to stay current with the interface boxes and
updated software so that the computers can be upgraded as they become obsolete.
Option Capital Cost Start Complete
Update the Asset Monitoring System with latest $250,000/year 01/2023 12/2023
Manufactures supported equipment.
Don't replace system and disconnect from network $10,000/year 01/2023 12/2023
Hire Manufacture to run data collection and provide $375,000/year 01/2023 12/2023
recommendation report.
2.1 Working with the manufactures of the equipment we requested alternatives for
keeping the systems working and updated. To do this we need to purchase the
manufactures supported systems. Normally we can save the database and load
that in the new system so we can continue the trending of the asset. Sometimes
we must start over on the trending. We use industrial standard curves and data
points to quantify the asset condition.
2.2 The capital cost will go to the systems that have already failed or have been
obsolete and are no longer collecting data. We will concentrate on one Unit per
year or one type of system per year.
2.3 The Business Unit will use these Asset Monitoring Systems to trend the Asset
Condition which will provide time for the Business Cases to be developed
ranked and prioritized and put into our 5-year plan.
2.4 The alternatives of"Don't replace system and disconnect from network" is a risk
of not being able to indicate when we are having issues with an asset. That is
fine if we want to run to failure. If that is the case, then upon failure we must
figure out what is not going to be done in our plan. That effects manpower and
budget changes. Once approved then we must start the project process.
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Asset Monitoring Systems
The alternative of "HIRE MANUFACTURE TO RUN DATA COLLECTION AND PROVIDE
RECOMMENDATION REPORT' is a risk because it is just a snapshot of the
equipment condition at the time the data is taken.
2.5 Given that our install window is the last couple months of each year the material
will be purchased in the first year and the install and commissioning will happen
in the following year.
2.6 To be reliable we need to have these types of systems to give us data on the
condition trends of the Assets.
2.7 As we mature our Asset Management plans these systems will be key to
showing when we need to move forward with a capital replacement. They can
also give us indication of what Unit needs attention during the maintenance
cycles. We will be looking at the data from these systems on a quarterly basis
and do a report yearly.
2.8 Supplemental Information
2.8.1 The customers and stakeholders of these systems is the Asset Management and
Compliance Engineering team and Operations.
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The steering committee will be the Asset Management & Compliance
Engineering group. Each project will be discussed and prioritized with other
similar projects.
3.2 The governance oversight will be provided by Sr. GPSS Management.
3.3 Decision making on projects will be bast on failed equipment and prioritized
based on megawatts output. Changes will be documented in a spreadsheet for
tracking the projects.
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Asset Monitoring Systems
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Asset Monitoring Systems 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.
Glen Farmer Digitally signed by Glen Farmer
Signature: Date:
te:2022.08.3015:49:04 Date: 8/23/2022
Print Name: Glen Farmer
Title: Asset Management & Compliance
Engineering Manager
Role: Business Case Owner
Al ex i s Digitally signed by Alexis
Signature: Date:2022.09.0109:04:40 Date:
-07'00'
Print Name: Alexis Alexander
Title: Director, GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
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EXECUTIVE SUMMARY
Atlas is a multi-year year program to strategically replace the suite of custom Geographic
Information System (GIS) applications known as Avista Facility Management (AFM).
AFM is the system of record for spatial electric facilities in Washington and Idaho and gas
facility data in Washington, Idaho and Oregon and provides the connectivity model to
support GIS engineering and analysis applications. The AFM applications and data
model have been used for nearly two decades and have reached technology
obsolescence. The existing data model used by AFM is being replaced by a new industry
standard model called the Utility Network. The AFM is a cornerstone to Avista's ability to
provide responsive service across its territory. If AFM is not replaced with a modern GIS
platform, which can utilize the Utility Network model, the ability of Avista to meet customer,
regulatory, compliance requirements will be at risk. Replacing AFM will enable Avista to
take advantage of commercial GIS applications that provide improved mobile and desktop
functionality, increased collaboration capabilities and increased reliability.
Improvement of customer experience is at the core of Atlas Program. The proposed
next generation applications will enable Avista workers, both office and field, to respond
to customer requests faster; provide information to customers that is more accurate,
timely and complete; and improve customer experience when they interact with Avista.
Avista benefits of replacing the AFM applications include improved worker productivity,
improved asset data integrity, and the opportunity to reengineer work processes and
methods, supporting a continual improvement program. New commercial solutions also
provide Avista with the ability to meet changing demands of customers, enable effective
operation of an increasingly complex and dynamic distribution grid, and provide the
opportunity to create new service offerings to customers.
The total program budget for the 12-year plan is estimated to be $30.OM dollars. The
funds in this business case will be utilized to fund the phases of the Atlas Program as
detailed in the supplemental information referenced in section 1.5 below. The years
2020-2027 will be primarily focused on the project timeline and deliverables detailed in
the Utility Network Advantage Program Report, while also supporting Mobility in the
Field initiative which configures and deploys mobile GIS mapping and data applications.
VERSION HISTORY
Version Author Description Date Notes
1.0 Mike Littrel Initial draft of business case 04/2017
2.0 Mike Littrel Updated business case format 0712020
3.0 Mike Littrel Updated program details and timelines 0712021
4.0 Mike Littrel Updated program details and timelines 0712022
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GENERAL INFORMATION
Requested Spend Amount $30,000,000
Requested Spend Time Period 06/2015— 12/2027
Requesting Organization/Department Enterprise Technology
Business Case Owner I Sponsor Mike Littrel I Josh DiLuciano
Sponsor Organization/Department Energy Delivery Technology Projects
Phase Execution
Category Program
Driver Asset Condition
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Avista's AFM system has been used for nearly two decades and is approaching
technology obsolescence. The technology does not have the ability to utilize
the Utility Network data model and will not meet future business needs. The
software has already undergone two major conversions to extend the life to this
point. The first was a programing language conversion from Microsoft Visual
Basic to Microsoft .NET because Visual Basic was no longer a supported
language. The second was a geometric precision change to support the
requirements of the integration with Maximo. Both of these changes achieved
their goals; however, the code is now more fragile which increases the
complexity of supporting AFM. Additionally, the existing system is custom built
and requires continual maintenance and support by internal staff whose skillset
is becoming scarce, as the fundamental code and architecture is complex. In
parallel, most of the staff who were part of the original custom build of the AFM
system, have long since moved on. Certain AFM applications, such as electric
and gas edit and Outage Management Tool, do not have the full complement of
desired functionality and are unreliable at times due to the outdated architecture.
When a new configuration request is surfaced, the change cannot always be
implemented, as the custom code and architecture will not allow it. The existing
data model used by the AFM applications is being replaced by an industry
standard model called the Utility Network. It is important to begin the transition
to the next generation GIS technology while there is still staffing to support the
AFM system, and the current data model is still supported, because delaying
will increase the risk of customer impact caused by increasing system issues.
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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
Improvement of electric and gas customer experience is at the core of the Atlas
Program. These new tools will enable Avista workers, office and field, to respond
to customer requests faster; provide information to customers that is more
accurate, timely and complete; and improve customer satisfaction when they
interact with Avista.
In addition to replacing traditional desktop GIS applications, additional mobile
tools will extend the value of Avista's investment in the GIS system by providing
field staff with applications for near real-time editing and data collection. For
example, the Mobile Design Tool will enable functionality for a designer to
perform designs at a job site, providing an improved customer experience, and
will be fully compatible with the desktop design tool. In addition, the Mobile tools
will provide field personnel with powerful functionality to meet customer
responsiveness expectations; Global Positioning System (GPS) guided turn by
turn directions to work locations; electronic receipt sent to the customer's
communication preference (email, text, etc.) at completion of work orders;
access to GIS data in the field; capture of as-built configuration, compliance data
and materials electronically by taking advantage of a variety of data sources,
including digital image data, keyed data, bar code scanned data, and GPS
location data.
New commercial solutions and industry standard data model also provide Avista
with the ability to more fully integrate with industry standard gas and electric
planning and analysis tools. This will lead to a better understanding of where
weakness in the infrastructure may exist and proactively reinforce those areas
improving reliability for the customers.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The AFM system has been used for nearly two decades and is approaching
technology obsolescence. Continuing to utilize AFM would continue to create
Operating and Maintenance cost pressure while also creating risks and lost
opportunities. Additionally, any investment in the current system is a sunk cost,
as the system is limited in the functionality it can provide to our staff as they
serve both gas and electric customers. The current system is highly customized
and cannot leverage industry standard GIS platforms to share data sets that
provide field and office workers with more information about our assets and
those of other agencies, such as local, county and state governments. The
existing data model used by the AFM applications is being replaced with and
industry standard model. The GIS platform is a cornerstone to Avista's ability
to provide responsive service across its territory, if it is not replaced with a
modern GIS platform that can utilize the Utility Network data model, the ability
of Avista to meet current and future customer, regulatory, and compliance
requirements will be at risk.
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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.
Each project within the Atlas program will have a project charter which includes
project costs, schedule, deliverables and benefits. Each project will have a
steering committee assigned. Throughout the duration of each project the
steering committee will be provided status reports on a monthly basis. These
status reports will include updates on project scope, schedule and budget, as
well as any risks and/or issues that the project team is currently working on.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
Justification for system replacement is based on comprehensive
assessments of AFM technologies, processes and functions that were
performed in 2015 and 2019 by third-party consultants as part of the
project planning process. The details of the assessments are available in
the following supporting documents:
• Current State Report
• Future State Report
• Gap Analysis Report
• Industry Analysis Report
• Requirements Report
• Alternative Analysis Report
• Utility Network Advantage Program Report
• Atlas Roadmap
The Esri ArcGIS product and the Utility Network data model will continue
to be the foundational spatial data engine for next generation application
delivered through Atlas. Esri is the industry standard for GIS, so
continuing to use that platform provides the highest level of access to
commercial applications and standard integration to other enterprise
applications. The replacement will take place through a series of
targeted and incremental projects to maximize value and minimize risk.
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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.
Avista Facilities Management(AFM)
Electricand Gas Design
Electricand Gas Edit Distribution Management
Outage Management Tool System
Engineering Analysis
spatial data Gas
engine Model
'G[S-Geographic information System
Esri GIS serves as the foundational data structure on which AFM
applications are built or rely on. AFM is the system of record for spatial
electric and gas facility data and provides the connectivity model to
support the AFM applications. The following is a brief description of AFM
tools.
• Electric and Gas Edit are tools inherent in the system used for data
edits prior to committing final data changes and additions.
• Outage Management Tool is an in-house developed application that
supports outage analysis and management.
• Engineering Analysis is a commercial tool used for engineering
analysis modeling.
• Distribution Management System is a commercial application used to
monitor and control the distribution grid. It relies on the GIS data from
AFM to determine the current operating state.
The AFM applications and data model have been used for nearly two decades and is
approaching technology obsolescence. Continuing to utilize AFM would continue to
create Operating and Maintenance cost pressure while also creating risks and lost
opportunities. Additionally, any investment in the current system is a sunk cost, as
the system is limited in the functionality it can provide to our staff as they serve both
gas and electric customers.
Option Capital Cost Start Complete
Recommended Solution - Replace the custom $30.OM 06/2015 12/2027
AFM applications with Commercial Off The Shelf
Applications
Alternative - Continue to utilize the custom AFM $10.0M 06/2015 12/2027
applications
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2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Detailed documentation from industry experts as listed in section 1.5 above.
Additionally, project costs from recent comparable projects at Avista were used
to determine the amount of the capital funds request and duration of the
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.
The funds in this business case will be utilized to fund the phases of the Atlas
Program as detailed in the supplemental information referenced in section 1.5
above. The years 2020-2027 will be primarily focused on the project timeline
and deliverables detailed in the Utility Network Advantage Program Report,
while also supporting Mobility in the Field initiative which configures and deploys
mobile GIS mapping and data applications.
The Atlas Program has been and will continue to be divided into discrete
projects that when possible have a duration of one calendar year. This will allow
the capital expenditure for a given year to be transferred to plant in that year.
Project/Spend
($1000) 2023 2024 2025 2026 2027
ESRI Utility Network $1,450 $1,000 $1,475 $1,850 $1,280
Mobility in the Field $1,240 $1,080 $875 $875 $875
Totals $2,690 $2,080 $2,350 $2,725 $2,155
Modernizing Avista's GIS and deploying mobile GIS applications is anticipated
to provide the following indirect labor savings. The estimated savings are
based on a review a of current and previous GIS projects completed in the Atlas
Business case with a uniform efficiency value applied based on the types of
applications deployed. This method was used to forecast anticipated savings
for future projects because specific projects for 2023 - 2027 have not yet been
approved.
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Atlas Indirect Savings Estimates
GIS Mobile Applications Annual Indirect Offset Potential
Estimated Number of Users 75
Estimated Efficiency per User 15 minutes per day
Estimated Usage Days per year 200
Standard Hourly Labor Rate $85.00
Estimated Percent of Users in WA 75%
Estimated Annual Indirect Labor Offset $239,063
GIS Modernization Annual Indirect Offset Potential
Estimated Number of Users 200
Estimated Efficiency per User 10 minutes per day
Estimated Usage Days per year 200
Standard Hourly Labor Rate $85.00
Estimated Percent of Users in WA 75%
Estimated Annual Indirect Labor Offset $425,000
Total Annual Indirect Labor Offset $664,063
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Each project within the Atlas Program will include a business process and
stakeholder analysis to determine the organization change management and
training needs. This analysis will then be used to deliver communication to the
stakeholders throughout the project and develop end user training.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The current suite of AFM solutions has a recent history of performance
challenges which may only be mitigated with considerable investment or
replacement. Continuing to invest in a custom system with no vendor support is
not a sustainable long-term solution. There are network management
functionality limitations and performance related issues with the current data
model that are addressed in Esri's new Utility Network data model and platform.
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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 work was started in 2015 and is scheduled to complete in December 2026.
The Atlas Program has been and will continue to be divided into discrete
projects than when possible have a duration of one calendar year or less. This
will allow the capital expenditure for a given year to be transferred to plant in
that year.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Having a modern GIS will enable Avista to meet the changing needs in energy
delivery such as Distributed Generation and Smart Grids with Grid Edge
Intelligence. It will also enable the ability to model complex network and
equipment such as electric substations and gas regulator stations to provide a
more accurate view of the assets in the field. The increased accuracy and
currency of the data along with modern mobile applications will provide field
personnel with powerful functionality to meet customer responsiveness
expectations. Finally, the advanced modelling will enable improved analysis
and reporting capabilities.
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 AFM applications and data model have been used for nearly two decades
are approaching technology obsolescence. Continuing to utilize AFM would
continue to create Operating and Maintenance cost pressure while also creating
risks and lost opportunities. Additionally, any investment in the current system
is a sunk cost, as the system is limited in the functionality it can provide to our
staff as they serve both gas and electric customers. Replacing AFM will enable
Avista to take advantage of commercial GIS applications and an industry
standard data model that will provide improved mobile and desktop functionality,
increased collaboration capabilities and increased reliability far beyond the what
can be achieved with AFM.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Customers will interface with the technology in this business case both
through their interactions with Avista personnel who will be using the
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technology and through map-based information that they will have
access to through online methods such as the Avista website.
2.8.2 Identify any related Business Cases
The work in the business case closely is related to the work in the Outage
Management System and Advanced Distribution Management System
business case.
3.1 Steering Committee or Advisory Group Information
The Atlas Business Case has two levels of governance: The Executive
Technology Steering Committee (ETSC), and Project Steering Committees.
The committees review monthly project status reports, which identify project
scope, schedule and budget, as well as any risks and/or issues that the project
team is currently working on. The Atlas Program Team reports progress
monthly to the steering committees and other stakeholder groups.
3.2 Provide and discuss the governance processes and people that will
provide oversight
The Steering Committee for each project in the Atlas Program will be made up
of stakeholders from across the functional business units and Enterprise
Technology.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Status reports to the steering committees will be used as the official review and
approval process for prioritization and change requests. Risks, issues and
change requests will be documented in project logs and kept as artifacts of each
project within Enterprise Technology's project management software system.
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The undersigned acknowledge they have reviewed the Atlas Business Case and
agree with the approach it presents. Significant changes to this will be coordinated
with and approved by the undersigned or their designated representatives.
DocuSigned by:
Signature: NIiC�tat� U� Date: sep-02-2022 1 9:24 AM PDT
9DDE7FC206184AF...
Print Name: Mike Littrel
Title: Manager of Energy Delivery
Technology Projects
Role: Business Case Owner
DocuSigned by:
Signature: �6SL Vi(,u6Mh Date: sep-06-2022 11:01 AM PDT
A3C71874F6564D6_.
Print Name: Josh DiLuciano
Title: Director of Electric Engineering
Role: Business Case Sponsor
DocuSigned by:Signature: /��-S��/� /\JA`W Date: Sep-02-2022 1 9:49 AM PDT
E4E2D9C7EE4747F...
Print Name: Hossein Nikdel
Title: Director of Applications and
Systems Planning
Role: Steering/Advisory Committee Review
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Base Load Hydro
EXECUTIVE SUMMARY
Avista's Base Load Hydro plants are all located on the upper Spokane River and
are "run of river" plants which means they have little to no storage capacity and their
operation is subjected to the flow in the Spokane River and the lake level
requirements of Lake Coeur d'Alene, upstream of the plants. The facilities
considered in this program are: Post Falls, Upper Falls, Monroe Street and Nine
Mile Hydroelectric Developments. This program also includes capital projects at the
Generation Control Center and on the Generation Control Network. It can also
include some projects at the Post Street 115kV Substation where the two downtown
hydro plants are tied into the grid.
The operational availability for these generating units in these plants is paramount.
The service code for this program is Electric Direct and the jurisdiction for the
program is Allocated North serving our electric customers in Washington and Idaho.
The purpose of this program is to fund smaller capital expenditures and upgrades
that are required to maintain safe and reliable operation. Maintaining these plants
safely and reliably provides our customers with low cost, reliable power while
ensuring the region has the resources it needs for the Bulk Electric System (BES).
Projects completed under this program include replacement of failed equipment and
small capital upgrades to plant facilities. The business drivers for the projects in this
program are a combination of Asset Condition, Failed (or Failing) Plant, and
addressing operational deficiencies. Most of these projects are short in duration,
typically well within the budget year, and many are reactionary to plant operational
support issues. Without this funding source it will be difficult to resolve relatively
small projects concerning failed equipment and asset condition in a timely manner.
This will jeopardize plant availability and greatly impact the value to our customers
and the stability of the grid.
Due to the age of the facilities more and more critical assets, support systems and
equipment are reaching the end of their useful life. This program is critical in
continuing to support asset management program lifecycle replacement schedules.
The annual cost of this program is variable and depends on discovery of unfavorable
asset condition and the unpredictability of equipment failures.
VERSION HISTORY
Version Author Description Date Notes
Draft Bob Weisbeck Initial draft of original business case 6/29/20
1.0 Bob Weisbeck Updated for 2022-2026 Capital Plan 6/22/21
2.0 Bob Weisbeck Updated for 2023-2027 Capital Plan 5/10/22
Business Case Justification Narrative Page 1 of 8
Staff PR_037 Attachment C 17 of 237

Base Load Hydro
GENERAL INFORMATION
Requested Spend Amount $5,125,000
Requested Spend Time Period 5 years
Requesting Organization/Department C07/GPSS
Business Case Owner I Sponsor Bob Weisbeck Alexis Alexander
Sponsor Organization/Department C07/GPSS
Phase Initiation
Category Program
Driver Asset Condition/Failed Equipment
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Due to the age and continuous use of the Base Load Hydro facilities, more and
more critical assets, support systems and equipment are reaching the end of their
useful life. In addition, it is difficult to predict failures and unscheduled problems
of operating hydroelectric generating facilities. This program is critical in
providing funding to support the replacement of critical assets and systems that
support the reliable operations of these critical facilities.
1.2 Discuss the major drivers of the business case
The major drivers for this business case are Asset Condition and Failed Plant.
This program provides funding for small capital projects that are required to
support the safe and reliable operation of these hydro facilities. The cost-
effective operations and generating capacity of these plants, maximize value for
Avista and our customers.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred.
Critical asset condition and failed equipment jeopardize the safe and reliable
operation of these generating facilities. If problems are not resolved in a timely
manner, the plant and plant personnel could be at risk and failed or unavailable
critical assets and systems will limit plant availability. This could have a
substantial cost impact to Avista and our customers.
Without this funding source it will be difficult to resolve relatively small projects
concerning failed equipment and asset condition in a timely manner. This will
jeopardize plant availability and greatly impact the value to customers and the
stability of the grid.
Business Case Justification Narrative Page 2 of 8
Staff PR_037 Attachment C 18 of 237

Base Load Hydro
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.
Plant reliability and availability is measured as well as the frequency and nature
of forced outages. These metrics will contribute to prioritizing the projects in this
program. Historically, this program has funded multiple projects per year which
contributed to high unit availability.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
The historical drivers of the projects selected to be funded by the program
are a mix of Asset Condition, approximately 66% and Failed Plant,
approximately 34%. Projects are typically completed within the calendar
year.
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.
Being a program, this review will be performed on a project by project
basis. This decision will be made by the program Advisory Committee.
Option Capital Cost Start Complete
Base Hydro Program $5,125,000 0112023 1212027
Individual Capital Projects $5,125,000 0112023 1212027
Perform O&M maintenance 0
Business Case Justification Narrative Page 3 of 8
Staff PR_037 Attachment C 19 of 237

Base Load Hydro
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Review of the program budget over the period of the last six years has revealed
a realistic annual budget is $1 ,025,000, especially based on the age of the Base
Load Hydro plants.
The drivers of the projects selected to be funded by this program are mix Asset
Condition (approximately 66%) and Failed Plant (34%). Resolving issues
encountered in operating these plants in a timely manner benefits the customers
with providing safe, reliable, low cost power which supports the needs of Bulk
Electric System and provides value to Avista and our customers.
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 annual budget program, based on review of the past six years, is
approximately $1 ,025,000. Projects with the lowest risk will be postponed during
this period. The projects in this program typically take place within the calendar.
If capital funds were not available for the projects in this program, reliability of
the plant would decrease, and more O&M would need to be performed to repair
aging equipment instead of replacement. This would be an unacceptable and
substantial increase in the O&M expenditures.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
These projects vary in size and support needed based on the requests from the
department and from key stakeholders. The larger projects require formal
project management with a broader stakeholder team. Medium to small projects
can be implemented by a project engineer or project coordinator and many
cases can be handled by contractors managed by the regional personnel. All
these projects are prioritized and coordinated by the broader support team.
Business Case Justification Narrative Page 4 of 8
Staff PR_037 Attachment C 20 of 237

Base Load Hydro
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
One alternative would be to create business cases using the business case
template and process for each of these small projects. There are typically 20
projects a year funded by the program. This would overload the Capital Budget
Process with small to medium projects whose governance can be effectively
handled by the hydro organization. These projects are specific to these plants
and the leadership in hydro operations understand the best the nature and
context of these projects.
These projects are somewhat unpredictable. It would be difficult to forecast
unforeseen events such as equipment failures and identify critical asset
condition that could effectively be put in the annual capital plan.
Another alternative would be to attempt to repair this equipment instead of
replacing critical assets at the end of their lifecycle. This will be unacceptably
expensive and older equipment will become more and more unreliable until it
becomes obsolete. Operating in a run-to-failure mode is proven to be an
unsuccessful approach and subjects Avista and its customers to unacceptable
risk.
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 in this program typically take place during the outages for the Hydro
Plants which are typically in the summer and fall of each year. Some projects
may have the ability to be performed in the first two quarters of the year. Work
performed in and around the dams that require outages is safer and more cost
effective after run off has occurred in the rivers.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
The purpose of this program is to provide funding to small to medium size
projects with the objective of keeping our hydroelectric plants reliable and
available. This enables these plants to affordably support the power needs of
our company and our customers. By taking care of these facilities we support
our mission of improving our customer's lives through innovative energy
solutions which includes hydroelectric generation. By executing the projects
funded by the program, we ensure that hydro facilities are performing at a high
level and serving our customers with affordable and reliable energy.
Business Case Justification Narrative Page 5 of 8
Staff PR_037 Attachment C 21 of 237

Base Load Hydro
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
Review of the program budget has revealed that a realistic annual budget is
$1,025,000. Projects with the lowest risk will be postponed during this period. The
projects in this program typically take place within the calendar.
The drivers of the projects selected to be funded by this program are mix Asset
Condition (approximately 66%) and Failed Plant (34%). Resolving issues encountered
in operating these plants in a timely manner benefits the customers with providing safe,
reliable, low cost power which supports the needs of Bulk Electric System and provides
value to Avista and our customers.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
The list of primary customers and stakeholders includes: GPSS, Environmental
Resources, Power Supply, Systems Operations, ET, and electric customers in
Washington and Idaho.
2.8.2 Identify any related Business Cases
3.1 Advisory Group Information
The Advisory Group for this program consists of the four regional Hydro Managers and
the Sr Manager of Hydro Operations and Maintenance.
Business Case Justification Narrative Page 6 of 8
Staff PR_037 Attachment C 22 of 237

Base Load Hydro
3.2 Provide and discuss the governance processes and people that will
provide oversight
Projects are proposed through various organizations in Generation Production and
Substation Support (GPSS) and through key stakeholder such as Environmental
Resources, Dam Safety, and Safety and Security. The projects are vetted by the Hydro
Advisory Group. With the assistance of Operations, Construction and Maintenance
and Engineering, projects are evaluated to determine available options, confirm
prudency, and bring potential solutions forward.
This same vetting process is followed for emergency projects and may include other
key stakeholders. Over the course of the year, the program is actively managed by the
Sr. Manager of Hydro Operations, with the assistance of the Advisory Group. This
includes monthly analysis of cost and project progress and reporting of expected spend.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Each project request will be evaluated by the Advisory Group which will include
the scope, cost and risk associated with the project. The project will be
evaluated based on the impact or potential impact of the operation of the
Regulating Hydro plants. The selection and approval of the project will be based
on the experience and consensus of the Advisory Group.
Depending on the size of the project, a Project Manager or Project Coordinator
may be assigned. In this case, the project management process is followed for
reporting and identifying and executing change orders. Smaller projects will
have a point of contact and financials will be reviewed on a monthly basis by the
Advisory Group.
Business Case Justification Narrative Page 7 of 8
Staff PR_037 Attachment C 23 of 237

Base Load Hydro
The undersigned acknowledge they have reviewed the Based Load Hydro Program
business case and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.
Signature: Date: 05-23-2022
Print Name: Bob Weisbeck
Title: Manager, Hydro Ops and Maintenance
Role: Business Case Owner
Alexis Digitally signed by Alexis
Si nature: Date:2022.09.0108:54:01
g -07'00' Date:
Print Name:
Title:
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Template Version: 05/28/2020
Business Case Justification Narrative Page 8 of 8
Staff PR_037 Attachment C 24 of 237

Base Load Thermal Program 2023 - 2027
EXECUTIVE SUMMARY
This business case request is for Avista's base load thermal plants: Kettle Falls
and Coyote Springs 2. This program enables these plants to have operational
flexibility and are operated to support energy supply, peaking power, provide
continuous and automatic adjustment of output to match the changing system loads,
and other types of services necessary to provide a stable electric grid and to
maximize value to Avista and its customers. Smaller and emergent projects planned
for Kettle Falls are identified and prioritized through their plant Budget Committee.
The plant Budget Committee utilizes an in-house Maintenance Project Review
scoring matrix.
Projects planned specifically for Coyote Springs 2 are identified and prioritized
during the Annual Budgeting process, with emergent projects discussed during the
Monthly Owners committee meetings between Avista management and Coyote
Springs management. Some of the projects that fall within this business case are
joint projects between Portland General Electric (PGE) and Avista. Those
"common" projects are also reviewed in an owner committee setting during meetings
at the plant that take place on a monthly basis.
The operational availability for these plants is paramount. The service code for this
program is Electric Direct and the jurisdiction for the program is Allocated North
serving our electric customers in Washington and Idaho
Individual projects are identified and approved by the Manager of Thermal
Operations and Maintenance, specific plant managers and/or GPSS management.
Some specific jobs under this program may require additional financial analysis if
they are sufficiently large or there are several options that can be chosen to meet
the objective. These projects are reviewed with finance personnel to make sure that
they are in the best interest of our customers.
VERSION HISTORY
Version Author Description Date Notes
Draft Greg Wiggins Initial draft of original business case 71812020
Mike Mecham Updated 71612021 For years 2022-2026
Mike Mecham Updated 8/19/2022 For years 2023-2026
Business Case Justification Narrative Page 1 of 9
Staff PR_037 Attachment C 25 of 237

Base Load Thermal Program 2023 - 2027
GENERAL INFORMATION
Requested Spend Amount $13,950,000
Requested Spend Time Period 2023-2027
Requesting Organization/Department C06, K07 /GPSS
Business Case Owner I Sponsor Thomas Dempsey I Alexis Alexander
Sponsor Organization/Department C06, K07/GPSS
Phase Initiation
Category Program
Driver Asset Condition / Failed Equipment
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Due to the age and continuous use of the base load thermal facilities, more and
more critical assets, support systems, and equipment are reaching the end of
their useful life. In addition, it is difficult to predict failures and unscheduled
problems of operating thermal generating facilities. This program is critical in
providing funding to support the replacement of critical assets and systems that
support the reliable operations of these critical facilities.
1.2 Discuss the major drivers of the business case
The major drivers for this business case are Asset Condition and Failed Plant.
This program provides funding for small capital projects that are required to
support the safe and realiable operation of these thermal facilities. The flexible
operations and generating capacity of these plants maximize value for Avista and
our customers.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred.
Critical asset condition and failed equipment jeopardize the safe and reliable
operation of these generating facilities. If problems are not resolved in a timely
manner, the plant and plant personnel could be at risk and failed or unavailable
critical assets and systems will limit plant flexibility and availability. This could
have a substantial cost impact to Avista and our customers.
Without this funding source it will be difficult to resolve relatively small projects
concerning failed equipment and asset condition in a timely manner. This will
jeopordize plant availability and greatly impact the value to customers and the
stability of the grid.
Business Case Justification Narrative Page 2 of 9
Staff PR_037 Attachment C 26 of 237

Base Load Thermal Program 2023 - 2027
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.
Plant reliability and availability is measured, as well as the frequency and nature
of forced outages. These metrics will contribute to prioritizing the projects in this
program. Historically, this program has funded multiple projects per year which
contributed to unit availability.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
The historical drivers of the projects selected to be funded by the program are
a mix of Asset Condition and Failed Plant. Projects are typically completed in
the calendar year.
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.
Being a Program, this review will be performed on a project by project basis.
This decision will be made by the program Steering Committee.
Using funds from the Base Load Thermal Program, spend $2,790,000 per year in
2022-2026; to "keep the lights on".
Option Capital Cost Start Complete
Base Load Thermal Program 13,950,000 0112023 1212027
Individual Capital Projects 13,950,000 0112023 1212027
Describe what metrics, data, analysis or information was considered when
preparing this capital request.
2.1
Review of the recent program budget has revealed the a realistic annual budget
is $3,100,000. In order to support the capital budget goals of the GPSS
department, this budget has been reduced by 10% to $2,790,000 for years 2023
through 2027. Projects with lower risk will be delayed through this period.
Business Case Justification Narrative Page 3 of 9
Staff PR_037 Attachment C 27 of 237

Base Load Thermal Program 2023 - 2027
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.
If capital funds were not available for the projects in this program, reliability of
the plant would decrease and more O&M would need to be performed to repair
aging equipment instead of replacement. This would be an unacceptable and
substantial increase in the O&M expenditures.
The projects in this program typically take place during the outages which are in
the late spring and fall of each year. Most of the capital is deployed in the 2rd
and 4th quarter of each year.
If capital funds were not available for the projects in this program, reliability of
the plant would decrease and more O&M would need to be performed to repair
aging equipment instead of replacement. Due to the nature of the Capital
projects covered under the Base Load Generation Program, forced outages and
reliability are difficult to quantify. Should forced outages occur due to the inability
to cover Capital projects under this program, daily estimated Power Supply
outage costs associated with the Base Load Thermal facilities covered under
this Program are estimated to be:
Coyote Springs 2: $206,800
Kettle Falls Wood: $69,700
Kettle Falls CT: $400
(refer to 20220825 Thermal Daily Outage Cost Estimation Tool
CONFIDENTIAL.xlsx)
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Business Case Justification Narrative Page 4 of 9
Staff PR_037 Attachment C 28 of 237

Base Load Thermal Program 2023 - 2027
These projects vary in size and support needed from the Department and key
stakeholders. The larger projects require formal project management with a
broader stakeholder team. Medium to small projects can be implemented by a
project engineer or project coordinator and many cases can be handled by
contractors mananaged by the regional personnel. All of these projects are
prioritized and coordinated by the broader support team.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
One alternative would be to create business cases using the business case
template and process for each of these small projects. There are typically 40-
50 projects a year funded by the program. This would overload the Capital
Budget Process with small to medium projects whose governance can be
effectively handled by the Thermal Organization. These projects are specific to
these plants and the leadership in Thermal Operations understand the best the
nature and context of these projects.
These projects are somewhat unpredictable. It would be difficult to forecast
unforeseen events such as equipment failures and identify critical asset
condition that could effectively be put in the annual capital plan.
Another alternative would be to attempt to repair this equipment instead of
replacing critical assets at the end of their lifecycle. This will be unacceptably
expensive and older equipment will become more and more unreliable until it
becomes obsolete. Operating in a run-to-failure mode is proven to be an
unsuccessful approach and subjects Avista and its customers to unacceptable
risk.
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 projects in this program for Kettle Falls and Coyote Springs 2 typically take
place during the annual outages, which are typically in May-June of each year.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
The purpose of this program is to provide funding to small to medium size
projects with the objective of keeping our thermal plants reliable and available
to support the power needs of our company and our customers affordably. By
doing this we support our mission of improving our customer's lives through
innovative energy solutions which includes thermal generation. By executing the
projects funded by the program, we insure that Thermal Facilities are performing
at a high level and serving our customers with affordable and reliable energy.
Business Case Justification Narrative Page 5 of 9
Staff PR_037 Attachment C 29 of 237

Base Load Thermal Program 2023 - 2027
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
Review of the recent program budget has revealed the a realistic annual budget
is $3,100,000. In order to support the capital budget goals of the GPSS
department, this budget has been reduced by 10% to $2,790,000 for years 2022
through 2026. Projects with lower risk will be delayed through this period.
The drivers of the projects selected to be funded by this program are mix Asset
Condition and Failed Plant. Resolving issues encountered in operating these plants in
a timely manner benefits the customers with providing safe, reliable, low cost power
which supports the needs of Bulk Electric System and provides value to Avista and our
customers.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business
case
The list of primary customers and stakeholders includes: GPSS, Environmental
Resources, Power Supply, Systems Operations, ET, and electric customers in
Washington and Idaho
2.8.2 Identify any related Business Cases
None.
3.1 Steering Committee or Advisory Group Information
The Kettle Falls plant uses a Budget Committee to evaluate, prioritize, and oversee
project work at the station. This group consists of the Plant Manager, Asst Plant
Manager, Plant Mechanic and a Plant Technician.
The plant Budget Committee utilizes GPSS Department Project Ranking Matrix.
The review process focuses around Personnel and Public Safety, Environmental
Concerns, Regulatory/Insurance Mandates, Ongoing Maintenance Issues,
Decreasing Future Operating Costs, Increasing Efficiency, Managing Obsolete
Equipment and Assessing the Risk of Equipment Failure.
Business Case Justification Narrative Page 6 of 9
Staff PR_037 Attachment C 30 of 237

Base Load Thermal Program 2023 - 2027
For Coyote Springs 2, monthly owners committee meetings between Avista
management and Coyote Springs management discuss and prioritize projects.
Some of the projects that fall within this business case are joint projects between
Portland General Electric (PGE) and Avista. Those "common" projects are also
reviewed in an owner committee setting during meetings at the plant that take place
on a monthly basis.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Projects are proposed through various organizations in Generation Production and
Substation Support (GPSS) and through key stakeholder such as Environmental
Resources, and Safety and Security. The projects are vetted by the Advisory Group.
With the assistance of Operations, Construction and Maintenance and Engineering,
projects are evaluated to determine available options, confirm prudency, and bring
potential solutions forward.
This same vetting process is followed for emergency projects and may included
other key stakeholders. Over the course of the year, the program is actively
managed by the Plant Managers, with the assistance of their Advisory Groups. This
includes monthly analysis of cost and project progress and reporting of expected
spend.
Business Case Justification Narrative Page 7 of 9
Staff PR_037 Attachment C 31 of 237

Base Load Thermal Program 2023 - 2027
3.3 Provide and discuss the governance processes and people that will
provide oversight
Projects are proposed through various organizations in Generation Production
and Substation Support (GPSS) and through key stakeholder such as
Environmental Resources, and Safety and Security. The projects are vetted by
the Advisory Group. With the assistance of Operations, Construction and
Maintenance and Engineering, projects are evaluated to determine available
options, confirm prudency, and bring potential solutions forward.
This same vetting process is followed for emergency projects and may included
other key stakeholders. Over the course of the year, the program is actively
managed by the Plant Managers, with the assistance of their Advisory Groups.
This includes monthly analysis of cost and project progress and reporting of
expected spend.
3.4 How will decision-making, prioritization, and change requests be
documented and monitored
Each project request will be evaluated by the Advisory Group which will include
the scope, cost and risk associated with the project. The project will be
evaluated based on the impact or potential impact of the operation of the
Thermal plants. The selection and approval of the project will be based on the
experience and consensus of the Advisory Group.
Depending on the size of the project, a Project Manager or Project Coordinator
may be assigned. They will follow the project management process for reporting
and identifying and executing change orders. Smaller projects will have a point
of contact and financials will be reviewed on a monthly basis by the Advisory
Group.
The undersigned acknowledge they have reviewed the Base Load Thermal
Program Business Case and agree with the approach it presents. Significant
Business Case Justification Narrative Page 8 of 9
Staff PR_037 Attachment C 32 of 237

Base Load Thermal Program 2023 - 2027
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.
Digitally signed by Thomas C
Signature: Thomas C Dempsey Dempsey
g Date:2022.08.31 11:02:25-07'00' Date:
Print Name: Thomas Dempsey
Title: Manager, Thermal Operations & Maintenance
Role: Business Case Owner
Alexis Digitally signed by Alexis
Si nature: Date:2022.09.0109:36:47
g -07'00' Date:
Print Name: Alexis Alexander
Title: Director, GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee
Review
Template Version: 05/28/2020
Business Case Justification Narrative Page 9 of 9
Staff PR_037 Attachment C 33 of 237

Cabinet Gorge Unwatering Pump Upgrade
EXECUTIVE SUMMARY
Cabinet Gorge Hydroelectric Development (HED) is the second largest generating plant in Avista's
hydropower fleet. It is located on the Clark Fork River in Bonner County, Idaho. With four
generators, it has a 270 MW output capacity. Built in 1952, the plant has retained most of its
original equipment which is now aging and at end of life.This plant was designed for base load
operation, but today is called on to not only provide load but to quickly change output in response
to the variability of wind generation,to changing customer loads and other regulating services
needed to balance the system load requirement and assure transmission system reliability.
In order to respond to these new demands, it is necessary to upgrade many of the plant's original
systems. One of those critical systems are the unwatering pumps.The unwatering system at Cabinet
Gorge consist of two unwatering sumps,each housing three pumps,one 50HP and two 200HP pumps.
The 50HP (1,000 GPM) pumps are used to pump out water from normal plant leakage. The 200HP
(5,000 GPM) pumps are used to drain out generating units when performing routine maintenance.
The pumps, original to the plant, are progressively requiring increasing maintenance. Replacing all
six pumps with new pumps at a cost of$800,000 is recommended. Timing for this work is related to
Avista's entrance into the Energy Imbalance Market (EIM). The risks for not completing these
upgrades include an inability to perform critical maintenance, potentially flooding the plant, and
thereby jeopardizing Avista's ability to serve its customers.
VERSION HISTORY
Version Author Description Date Notes
Draft Chris Clemens Initial draft of original business case 10/25/2020
1.0 Chris Clemens Updated for Budget Year 2023 8/23/2022
Business Case Justification Narrative Template Version: 08/04/2020 Page 1 of 6
Staff PR_037 Attachment C 34 of 237

Cabinet Gorge Unwatering Pump Upgrade
GENERAL INFORMATION
Requested Spend Amount $800,000
Requested Spend Time Period 2 years
Requesting Organization/Department D07/GPSS
Business Case Owner I Sponsor Chris Clemens I Alexis Alexander
Sponsor Organization/Department A07/GPSS
Phase Execution
Category Project
Driver Asset Condition
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The problems being addressed are the plant unwatering pumps at Cabinet Gorge. These
pumps have reached the end of their life to provide reliable plant dewatering.
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 current plant unwatering pumps were installed during the original plant construction
in the early 1950's. These pumps can no longer be maintained, due to the manufacturer
not supporting the equipment. Customers will be benefited through higher reliability of
new pumps: i.e. reduced downtime during maintenance evolutions and manufacturer
support of the replaced equipment. Also, the original pumps were designed with an oil
lubricating system that has the potential to get oil into the river while the pumps are in
operation. The new pumps will have a water lubricating system that will meet current
environmental requirements.
Business Case Justification Narrative Template Version: 08/04/2020 Page 2 of 6
Staff PR_037 Attachment C 35 of 237

Cabinet Gorge Unwatering Pump Upgrade
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The pumps have reached the end of their service life. They are a critical plant system and
without their reliable operation, the plant could easily flood and/or limit the ability to
perform unit maintenance. As we go into the EIM market, unit maintenance outages will
be scheduled one year in advance and schedule adherence is crucial to plant operation. If
these pumps fail, we could jeopardize the maintenance schedule and forgo much needed
preventative maintenance activities. In addition, in the case of a failure, the replacement
parts or new pumps would have to be manufactured, increasing the length of the
downtime. The current systems are not environmentally-friendly so there is a risk in
continually polluting our rivers with these outdated oil lubricated pumps.
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.
By replacing the current pumps with new pumps,we will provide consistency with industry
standards. These upgrades will improve the plant's overall reliability. This will also reduce
current maintenance costs and provide many years of efficient, reliable and
environmentally-sound plant dewatering operations.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
No studies have been performed.
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.
2. PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Cost Start Complete
Replace all six pumps and check valves over a two- $800,000 01 2022 122023
year period.
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Capital planning consists of bids from manufacturers to determine the best cost and
schedule. Engineering and vendors have been consulted to determine industry best
practices and to determine installation costs and schedules
Business Case Justification Narrative Template Version: 08/04/2020 Page 3 of 6
Staff PR_037 Attachment C 36 of 237

Cabinet Gorge Unwatering Pump Upgrade
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.
Installations and commissioning of purchased equipment will take place in 2022.
Maintenance costs will be reduced because the current pumps require ongoing
maintenance. In 2019, Unwatering pump #1 was removed from service because of high
vibration and the motor was pulling 60 amps over the nameplate rating. The mechanical
crew spent 2 weeks removing the motor and sending it in to be cleaned, baked and dipped.
Then the bearings were replaced, and the motor was reinstalled. Neither problem
(vibration nor high amperage) was resolved. The cost to perform this maintenance was
$50,000. Due to the age of these original pumps, it is difficult to get parts. Similarly, it is
not sustainable to fix the vibration issues because the pumps and motors have been
modified through the years to keep them in service. It is believed that replacing the pumps
will be more cost effective than trying to maintain the current pumps. Reliability will be
improved because the new pumps will be maintenance-free for many years.
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 successful upgrade of the system will allow the plant to operate more reliably during
the future.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
There is an alternative in only replacing four of the six pumps.The smaller pumps have had
the motors replaced 20 years ago, but the pump itself was not overhauled. The larger
pumps, if replaced, could act as a backup if the smaller pump was to fail. Though the
smaller pumps would still be utilizing the oil lubricating system. They still should be
replaced in the future to meet environmental standards.
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.
This project would take place over a two-year period. We will procure and install all six
pumps within that timeframe. The work would take 1 week per pump, totaling six weeks.
We would purchase three pumps in January 2022 and start the installation in September
of 2022. Then purchase the additional three pumps in January 2023 and start the
installation in September of 2023. There would be no outages or generation lost during
these upgrades. We will be able to replace one pump at a time, keeping the plant
unwatering sumps in service.
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Staff PR_037 Attachment C 37 of 237

Cabinet Gorge Unwatering Pump Upgrade
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Upgrading the plant unwatering pumps at Cabinet Gorge contributes to the safe and
responsible design, construction, operation and maintenance of Avista's generating fleet.
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
We ranked this project based on a ranking matrix to ensure prudent consideration of cost,
scheduling and personnel resources. These six pumps are ranked in poor condition. There
are only a few assets within the Hydro Department with a poor rating.This shows the need
and urgency to replace these pumps.
CoPul l
CabinetPump#8
GorgeHED Asset Group
o
Rating , Pump Backup
jLb"E,11 (for 47)
Unwatering Pumps Marginal -0.8 2.8 2.8 9.3 4.2
Marginal
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
The Mechanical shop, Electric shop, Engineering, Operations, Environmental, and Project
Management are required.
2.8.2 Identify any related Business Cases
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The Steering Committee consists of the following members: Plant Manager, Chief
Operator, Station Mechanic and Station Electrician.
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Cabinet Gorge Unwatering Pump Upgrade
3.2 Provide and discuss the governance processes and people that will
provide oversight
Persons providing oversight include: Generation Mechanical Engineer, Mechanical Shop
Forman and Station Mechanic.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The persons identified in Section 3.2 will be called on to evaluate recommendations raised
from the Stakeholder Group. Documented decisions will be stored in the project folder
located on the department network drive.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Cabinet Gorge Unwatering Pump
Upgrade 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: C --e�_ Date: 08/30/2022
Print Name: Chris Clemens
Title: Cabinet Gorge Plant Manager
Role: Business Case Owner
Signature: Date:
Print Name: Alexis Alexander
Title: Director GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: 08/04/2020 Page 6 of 6
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EXECUTIVE SUMMARY
Avista, as a regulated utility, is required to meet North American Electric Reliability
Corporation ("NERC") Critical Infrastructure Protection ("CIP") Reliability Standards
("Standards"). Specifically, Avista must comply with the CIP Version 5 Standards (CIPv5).
Our current cyber transient asset solution for substation engineers and relay technicians
does currently meet the minimum compliance standard. However, the current process
and technical solution is not viable long term as technology advances and the compliance
standard changes in accordance with those advances. The requested amount is based
off of 2022 planning efforts to identify a compliant and robust transient cyber asset
technical solution.
Being compliant with industry standards and government agency mandates benefits
customers by reducing the risk of electric and gas service interruptions associated with
cyber or physical attacks. The requested funding amount is intended to achieve and
maintain compliance with the effective dates defined by the governing entity. Not being
compliant and accepting fines is not considered a viable alternative, as it puts Avista's
cyber and physical security posture at risk and increases costs due to penalties. The
recommended solution is to implement the controls necessary to achieve compliance.
VERSION HISTORY
Version Author Description Date Notes
Draft I Andru Miller Updated 5-year funding request 8/09/2022
Business Case Justification Narrative Page 1 of 6
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GENERAL INFORMATION
Requested Spend Amount $250,000
Requested Spend Time Period 1 year
Requesting Organization/Department C09/ Enterprise Security
Business Case Owner I Sponsor Andy Leija I Clay Storey
Sponsor Organization/Department Enterprise Technology
Phase Execution
Category Program
Driver Mandatory& Compliance
1. BUSINESS PROBLEM
Meeting compliance standards for both cyber and physical security measures is a
requirement for Avista and can result from regulatory and non-regulatory changes,
mandates, and executive orders from various agencies and industry groups. As
security threats become more and more sophisticated, security measures are also
adjusted in response. In addition to protecting gas and electric services, meeting
compliance standards by the specified timeframe will save Avista money from fines
associated with the violation of a standard.
1.1 What is the current or potential problem that is being addressed?
The Security Compliance business case addresses the following problems:
- Physical security: theft, vandalism, safety, service interruptions, fines
- Cyber security: customer accounts, payment transactions, identity theft,
intellectual property, safety, service interruptions, fines
1.2 Discuss the major drivers of the business case and the benefits to the
customer
Customer Requested, Customer Service Quality & Reliability, Mandatory &
Compliance, Performance & Capacity, Asset Condition, and Failed Plant &
Operations are all the major drivers in the Security Compliance business case.
Each driver has its own security elements necessary to mitigate the risk to
customers and the services they expect.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Compliance standards for physical and cyber security measures are an absolute
necessity and will be for the foreseeable future. Avista must remain compliant
to ensure service reliability and avoid fines.
Business Case Justification Narrative Page 2 of 6
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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 conducts internal audits to evaluate its ability to meeting compliance
standards. These audits, along with utility industry forums, counsels, and
organizations provide Avista with a strong baseline from which to measure its
compliance and thus channel the appropriate level of investment to meet a new
standard.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
- N/A
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
The Security Compliance business case provides funding for cyber and physical
security related projects and supports Avista's safe and reliable infrastructure
strategy. The projects funded by this business case are driven by security
compliance standards.
Option Capital Cost Start Complete
Address compliance standards as they are $250,000 01 2023 122023
applicable (Recommended)
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The capital dollar request was derived from the historical annual spend
implementing physical and cyber security measures across the Avista service
territory to reasonably mitigate risks based on input from the programs
governing body. It also takes into account estimates of in-flight projects and a
1% per year increase for inflation for future projects.
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.
Meeting industry compliance requirements is important to Avista. Improving the
patching of operating systems and applications residing on the transient cyber
assets (laptops) that directly connect to highly sensitive operational technology
at generation and substation sites will significantly improve the cyber security
posture of Avista and its networks. Additionally, FERC Critical Infrastructure
Protection requirements continue to be updated to address emerging threats
Business Case Justification Narrative Page 3 of 6
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from around the globe. This business case expects to continue to deliver
physical and cyber tools contributing to compliance standards. Each project
within the business case evaluates the potential impact to O&M costs and
staffing.
[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.
Both physical and cyber security systems, processes, and procedures can have
an impact on business functions. As a business case with multiple projects,
Avista's project management office (PMO) tools and processes will be
leveraged to coordinate and collaborate through standardized change
management any changes to business functions.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
No alternative funding strategy is proposed. Compliance requirements will be
identified, and corresponding projects will be sequenced to mitigate those risks
based on the approved funding level.
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.
Since this business case is comprised of projects running concurrently over
multiple years, each one designates its own completion date and transfer-to-
plant.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This business case is a compilation of discrete projects. The projects funded
by this business case protect Avista's people, assets and information and will
ensure compliance with the required standards.
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
Security measures to protect critical infrastructure is not only prudent but
required. Reasonable and appropriate security measures are an expectation
Business Case Justification Narrative Page 4 of 6
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from Avista's customers. The prudency of the program's investments will be
evaluated by its governing body every month and adjusted as necessary.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
The Security Compliance business case significantly impacts all of Avista's staff
and its customers. Each project within the business case must carefully consider
stakeholders and effected customers during the chartering process.
2.8.2 Identify any related Business Cases
The Compliance business case may interact with other security business cases
as it invests in new compliance requirements. Other corresponding business
cases may include investments in refresh or upgrades of these assets as part
of their asset lifecycle through resulting from the Asset Condition driver.
3.1 Steering Committee or Advisory Group Information
The Reliability Compliance Advisory Committee will provide quarterly
recommendations and guidance based on the required compliance standards.
3.2 Provide and discuss the governance processes and people that will
provide oversight
The Reliability Compliance Advisory Committee acts as the guiding body for
compliance related work. This group meets quarterly and is composed of senior
leaders and directors from most of the lines of business. In addition, each project
funded by the Security Compliance business case has project level steering
committees.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Project Steering Committees act as the governing body over each individual
project within the program and will consist of key members in management
positions that are identified as responsible for the successful completion of the
scope of work identified in the Charter document for the Project. The Project
Steering Committee is responsible to provide guidance and make decisions on
key issues that affect the following topics: scope, schedule, budget, project
issues, and project risks.
Business Case Justification Narrative Page 5 of 6
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The Project Steering Committee will meet at the defined intervals documented
in the Charter of the project and will be facilitated by an assigned Project
Manager from within the PMO Department.
The undersigned acknowledge they have reviewed the Security 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.
DocuSigned by:
—E—
Signature: -� Date: Sep-02-2022 9:47 AM PDT
6456CKEF402467_.
Print Name: Andy Leija
Title: Manager, Security Delivery
Role: Business Case Owner
DocuSigned by:
Signature: `� 1 Sf6" Date: Sep-02-2022 9:12 AM PDT
670F95F7961D4B6...
Print Name: Clay Storey
Title: Director of Security, IT & Security
Management
Role: Business Case Sponsor
Business Case Justification Narrative Page 6 of 6
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Clearwater Wind Generation Interconnection
EXECUTIVE SUMMARY
Avista is a joint owner in the 500kV Colstrip Transmission System and parry 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 Wmd
Project'), all required study processes were completed, and Avista executed a Large Generator
Interconnection Agreement with the developer on Nhy 22,2019(LGIN).
Avista and the joint owners ofthe Colstrip Transmission System are obligated to fund their respective shares
of all Transmission Provider Interconnection Facilities and Netvwrk 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 LGlA and wuuld 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 ofthe Colstrip Project.
Avista's allocation of costs for the construction of required facilities for the Clearwater Wnd 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 systemwide,electric
direct.
VERSION HISTORY
Version Author Description Date Notes
1.0 Jeff Schlect Initial narrative drafted from pre-existing 7/30/2020 Existing Approved Case
approvedcase
Business Case Justification Narrative Page 1 of 6
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Clearwater Wind Generation Interconnection
GENERAL INFORMATION
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 I Heather Rosentrater/Mike Magruder
Sponsor Organization/Department Energy Delivery/Transmission Services
Phase Execution
Category Mandatory
Driver Mandatory& Compliance
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 betvwen the Colstrip Transmission System and the Bonneville Power
Administration's Eastern Interne 500kWacilities 1. Under FERC rules and the Agreement,Avista must
comply,A th all rules and procedures governing the interconnection ofnewgeneration facilities with the
Colstrip Transmission System. Pursuant to the Agreement, Clearwater Energy Resources, LI.0
requested interconnection of its 750NIWClearwater 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 Nl y 22,2019(WIN).
ACOLSTR
I
P TRANSMISSION SYSTEM
Colstrip-Townsend—250 miles
ARRISO BRO.DVIEW COLSTRIP
TOWNSEND
Avista owns a 10.2%share in the Colstrip-Broadview segment and a 12.1%share in the Broadview-
Townsend segment.
Business Case Justification Narrative Page 2 of 6
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Clearwater Wind Generation Interconnection
Avista and the joint owners ofthe Colstrip Transmission System are obligated to fund their respective
shares of all Transmission Provider Interconnection Facilities and Network Upgrades applicable to the
interconnection ofa Large Generator Interconnection project. NorthWestem Energy(N1 W)performs
all Transmission Operator functions under the Agreement, including construction budgeting and
forecasting for Colstrip Transmission System facilities. Avista's allocation ofcosts 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 NorthWe stem Energy on June 1,
2020,outlined an overallproject decrease(from$692,000 to$570,000)along with a timing adjustment
betwwen 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
Business Case Justification Narrative Page 3 of 6
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Clearwater Wind Generation Interconnection
The Company must fund its allocated share of capital improvements under the Colstrip Transmission
Agreement,the LG1Aand FERC rules.
Option Capital Cost Start Complete
Fund Network Upgrades under LGIA $570,000 012020 122021
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). (ie. 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.
Business Case Justification Narrative Page 4 of 6
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Clearwater Wind Generation Interconnection
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
Business Case Justification Narrative Page 5 of 6
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Clearwater Wind Generation Interconnection
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
Business Case Justification Narrative Page 6 of 6
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Clearwater Wind Generation Interconnection
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.
Digitly signed by Jeff Schect
Signature: Jeff Schlect Datea12020.07.3017:30:45107'00' Date: 7/30/2020
Print Name: Jeff Schlect
Title: Senior Manager, FERC Policy and
Transmission Services
Role: Business Case Owner
Digitally signed by Michael A.
Si nature: Michael A. Magruder Magruder 7/31 /2020
g Date:2020.07.31 12:22:28-07'00' 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
Business Case Justification Narrative Page 7 of 7
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Enterprise and Control Network Infrastructure
EXECUTIVE SUMMARY
Technology that enables Avista's safety, control, customer-facing, and backoffice
systems is critical to the operations that serve our gas and electric customers. It is found
in many different environments from office locations to mountaintop sites to generation
plants across our service territory. Managing our network technologies to optimize
communications and operations of the enterprise and control systems in these locations
is extremely important. Technology investments under the Enterprise and Control
Network Infrastructure business case are needed to expand and maintain these network
assets in support of system reliability and business productivity throughout our service
territory, ensuring our ability to appropriately respond to the needs of our customers.
The technology solutions under the Enterprise and Control Network Infrastructure
business case will vary by site location and the systems supported in each facility or
environment. They will included, but are not limited to, emergency and safety systems,
control systems, customer systems, and enterprise back office productivity systems. This
infrastructure is core to utility operations, thus demanding reliable networks utilizing
commercial carrier services and private network solutions. The cost of each solution will
vary with the type of solution identified for the appropriate level of network access at each
site. Avista and its customers will experience the benefits through ongoing system
reliability.
The main driver behind this program is asset performance and capacity in alignment with
asset management strategies driven by technology Iifecycles that are based on
manufacturer product roadmaps and planned obsolesces. The technology solutions
within this program undergo regular review to balance the asset management strategy
within the predetermined budget allocations. The risks of not approving this business case
at the level to which it can maintain the balance of meeting its asset management strategy
can result in unplanned failures, which result in unplanned labor and non-labor costs, risk
of delay to procure and replace the failed asset, increased safety risks in sending field
staff in extreme weather conditions to remote locations, as well as downtime to the critical
operations and safety systems supported. New investments will be required when existing
assets do not provide adequate capacity, performance, and functionality.
VERSION HISTORY
Version Author Description Date Notes
1.0 Jim Ogle Initial BCJN Draft 612017
2.0 Shawna Kiesbuy Revision of BCJN to new template 712020
Business Case Justification Narrative Page 1 of 9
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Enterprise and Control Network Infrastructure
GENERAL INFORMATION
Requested Spend Amount $35,365,826
Requested Spend Time Period 5 years
Requesting Organization/Department Enterprise Technology
Business Case Owner I Sponsor Shawna Kiesbuy Jim Corder
Sponsor Organization/Department Enterprise Technology
Phase Execution
Category Program
Driver Performance & Capacity
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Technology that enables Avista's safety, control, customer-facing, and
backoffice systems is critical to the operations that serve our gas and electric
customers. It is found in many different environments from office locations to
mountaintop sites to generation plants across our service territory. Managing
our network technologies to optimize communications and operations of the
enterprise and control systems in these locations is extremely important.
Technology investments under the Enterprise and Control Network
Infrastructure business case are needed to expand and maintain these network
assets in support of system reliability and business productivity throughout our
service territory, ensuring our ability to appropriately respond to the needs of 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 main driver behind this program is asset performance and capacity in
alignment with asset management strategies driven by technology lifecycles
that are based on manufacturer product roadmaps and planned obsolescence.
The technology solutions within this program undergo regular review to balance
the asset management strategy within the predetermined budget allocations.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The risks of not approving this business case at the level to which it can maintain
the balance of meeting its asset management strategy can result in unplanned
failures, which result in unplanned labor and non-labor costs, risk of delay to
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procure and replace the failed asset, increased safety risks in sending field staff
in extreme weather conditions to remote locations, as well as downtime to the
critical operations and safety systems supported. New investments will be
required when existing assets do not provide adequate capacity, performance,
and functionality.
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.
Executing planned projects will refresh assets prior to the
asset's obsolescence and in this way, the business case should be able to
support the asset lifecycles and reduce the risk of failing assets affecting critical
business systems, processes and infrastructure reliability.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
Reference materials that support the needed changes in Network
technology are maintained by Technology Domain Architects within each
respective technology area.
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.
This business case is aligned with Performance & Capacity; not Asset
Management.
Option Capital Cost Start Complete
Asset replacement for optimized performance and $35,365,826 01 2021 122025
capacity
Do not fund the program $0 01 2021 122025
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The main driver behind this program is performance and capacity aligned with
asset management strategies driven by technology lifecycles that are based on
manufacturer product roadmaps, which can compound planned obsolescence.
The asset management strategy is critical to optimize the overall lifecycle value
of the product and reduce potential for failure or unplanned outages. Tracking
of the assets' installation and lifecycle durations are maintained to plan the
program projects over the course of future years driving the annual budget
request to maintain the refresh roadmap.
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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 business case includes network solutions for both expansion requirements
and systematic refresh of existing devices that provide access to our enterprise
and control networks. Life cycle schedules allow for a known number of assets,
by type, to be refreshed based on impact and likelihood of realized risk to the
environment. Historical costs and timelines provide indicators in support of the
requested allocations above.
Through roadmapping activities and known pressures on existing network
capacity, expansion work has been identified for each year. Again, using
historical data along with current product cost estimates, the team developed a
cost plan for work by year. Combined with the refresh work cost estimates, the
overall business case request amount is determined.
[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 projects in this program are standalone projects within the Enterprise and
Control Network Infrastructure business case but are dependent on length of
construction season and other geographically similar but unrelated work being
performed at impacted substations. Through those projects, business functions
and processes might be impacted but the technology upgrades being made at
the varied locations throughout Avista's service territory should strive to
increase performance and capacity for employees in their daily work life.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Alternative 1: FUND PROGRAM BASED ON OPTIMIZED PERFORMANCE
AND ASSET MANAGEMENT
Funding the Enterprise and Control Network Infrastructure business case
minimally each year based on a reduced capital plan and request incremental
increases as projects are completed. This would result in ad-hoc funding
requests to the Capital Planning Group for work approved outside of the 5-year
capital planning process.
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Alternative 2: DO NOT FUND THE PROGRAM
Enterprise and Control Network Infrastructure projects would not be funded.
Enterprise network access, optimization and/or unfunded capacity management
could result in minimized network capacity reducing the ability to perform
ordinary and necessary daily business operations. Control network access,
optimization and/or unfunded capacity management could result in minimized
control network capacity reducing the ability to manage and control our
generation and control system assets.
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 Enterprise and Control Network Infrastructure business case is managed
as a program of projects planned yearly. All individual projects are managed
through the PMO, which follows the Project Management Institute (PMI)
standards. Throughout the year, the business case's projects are Initiated,
Planned, Executed, and then Completed with a Transfer to Plant for the scope
requests which over the course of a calendar year equates to the funded budget
allocation.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This is a program with discrete projects that align with Avista's vision, mission
and strategic objectives:
• The Enterprise and Control Network Infrastructure business case
investments align with Avista's commitment to invest in its infrastructure to
achieve optimal Iifecycle performance — safety, reliability, and at a fair price.
Network communications that monitor and control Avista enterprise
networks and control networks are critical in support of the bulk electric
system. The implementation of these network technologies will continue to
enable and support these critical communications in a manner that is much
safer to all workers and at all locations across Avista.
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
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Throughout the course of a year, all project requests are vetted before the
Steering Committee to validate the request against the business case purpose
and making sure the request can be delivered within the approved funding
allocation.
2.8 Supplemental Information
Identify customers and stakeholders that interface with the business case
Within the Enterprise and Control Network Infrastructure business case, the
discrete projects interface with various internal Avista groups such as ET
engineering, Substation engineering, GPSS and Generation Plants, the
Telecommunications Shop, along with our internal business partners at various
office and remote facilities.
Steering Committee members include Business Case Sponsors, Directors and
Managers within the Enterprise Technology group along with the Business Case
Owner.
The ET Business Case Owner works in conjunction with the Project
Management Office (PMO), the assigned Program Manager, and subsequent
Project Managers.
The ET Business Case Owner is accountable and responsible for all Business
Case related activities and assignments.
2.8.1 Identify any related Business Cases
There are no related business cases.
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3.1 Steering Committee or Advisory Group Information
Steering Committee members are invaluable to the project and will provide
approval on scope, schedule, and budget related changes. Additionally, they will
provide approval on issues and risks pertaining to project deliverables outlined
in this document, which also typically have an impact on the scope, schedule,
or budget of a project. Steering Committee members will also provide approval
on Change Requests, Go-Live, and the Approval to Close document. For the
High Voltage Protection business case, the Steering Committee will consist of
the Directors and Managers within ET, Energy Delivery, GPSS and the Business
Case Owner.
3.2 Provide and discuss the governance processes and people that will
provide oversight
The Enterprise and Control Network Infrastructure Business Case has two
levels of governance; The Program Steering Committee and the Project
Steering Committee.
Program Steering Committee
This business case is a program of related projects. The Program Steering
Committee consists of members in management positions that are identified
and responsible for prioritizing the projects within this program. The Steering
Committee is also held accountable for the financial performance of this
program. The Program Steering Committee will have regular meetings to review
the progress of the program and to make decisions on the following topics:
• Project prioritization and risk
• Approving business case funding requests
• New project initiation and sequencing
The Program will be facilitated and administrated by an assigned Program
Manager within the Enterprise Technology (ET) Project Management Office
(PMO) Department. The project queue will be reviewed periodically in order to
plan and sequence work to the levels of funding allocation received.
Project Steering Committee
Project Steering Committees act as the governing body over each individual
project within the program and will consist of key members in management
positions that are identified as responsible for the successful completion of the
scope of work identified in the Charter document for the Project. The Project
Steering Committee is responsible to provide guidance and make decisions on
key issues that affect the following topics:
• Scope
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• Schedule
• Budget
• Project Issues
• Project Risks
The Project Steering Committee will meet at the defined intervals documented
in the Charter of the project and will be facilitated by an assigned Project
Manager from within the ET PMO Department.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Project prioritization is evaluated by the management team on a monthly basis.
Each program and project steering committee meet regularly and oversees
scope, schedule and budget within their respective programs and projects and
inform the Business Case owner of any changes needing escalation to the TPG
or CPG for decision-making around resource or funding constraints.
Any changes in funding or scope are documented at the Business Case level,
via Change Request document that is presented to the CPG on a monthly basis
and evaluated by the CPG for approval.
Changes in scope, schedule, or budget are also documented through a `Change
Request' at the project level and reviewed and approved through a formal
workflow process. All Enterprise technology projects in this business case are
managed through the PMO, which follows the Project Management Institute
(PMI) standards. Projects initiate with a `Charter' to begin the planning process.
When planning is complete, a `Project Management Plan (PMP)' is created and
approved as the projects baseline for scope, schedule and budget. At the end
of execution, an `Approval to Go Live' is submitted and approved prior to
implementation (Transfer to Plant). After the technology is in service and out of
the warranty period, the Project Manager will hold a Lessons Learned, and
subsequently submit an `Approval to Close' prior to finishing the project. All
Monitor and Control documentation and Change Requests are documented and
stored to ensure a comprehensive audit trail.
The undersigned acknowledge they have reviewed the Facilities Driven Technology
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.
❑ Signedby:
Signature: Es",
LLIA/" 6,Sl Date: Jul-31-2020 1 8:58 AM PDT
3CD905A61 B984C6...
Print Name: Shawna Kiesbuy
Title: Sr. Manager, Network Engineering
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Role: Business Case Owner
❑cuSignedby
Signature: ry At s 6 ('whr Date: Aug-03-2020 5:52 PM PDT
Print Name: Jim Corder
Title: IT Director
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
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Enterprise Business Continuity (EBC)
EXECUTIVE SUMMARY
Recovery is a critical business capability for Avista, as we have witnessed after a major weather
event when time is of the essence to recover from the storm. Avista's Enterprise Business
Continuity program business case is similar,whereby readiness is critical before, during, and after
an incident. Although many of Avista's technology systems have built-in redundancy or high
availability requirements, there are some gaps that necessitate further investment. To identify
these gaps,Avista conducts an annual disaster recovery exercise that evaluates the effectiveness
of its program, which includes people, process, and systems.The results of these exercises, along
with peer collaboration with utility industry partners, provides Avista with a strong baseline from
which to measure its recovery capabilities and channel the appropriate level of investment to
address any identified issues or risks.
Investments may include secondary systems required to respond when primary systems are not
available, additional compute and storage in offsite backup data centers to increase capacity, and
network and security enhancements to increase security and network reliability. The cost
associated with identified solutions can average between $100-$200k per year, depending on
the identified solution. Alternatives considered vary by the recovery need and interoperability of
systems in place.
The Colonial Pipeline ransomware event of 2021 highlighted the dependency between the
company's corporate technology systems, such as accounting and billing systems, and
operational technology system that control the flow of gas in their pipeline. These
interdependencies between systems are creating a complex technology architecture, whereby
one set of systems require the other set to fully operate. Additionally, regulators are focusing
more on recovery requirements for critical infrastructure organizations.' Using a cost estimate
for a PH (Personal Identity Information) and/or a PCI (Payment Card Industry) data breach, based
on the number of records under our stewardship, the indirect offset ranges from $5.21VI to
$20.7M, or average $12.9M, per incident. In this data breach example, the risk avoidance cost
far outweighs the per annual investment under this business case to maintain resiliency and
recovery capabilities. This is a tremendous benefit to Avista and our customers. If we do not
invest in our enterprise business continuity program, it can lead to our inability to recover from
an incident affecting technology systems required to deliver safe and reliable energy. So, while
the date and time of an incident cannot be predicted, prudency lies in the company's ability to
timely recover from an incident.
Our business continuity and disaster recovery capabilities must be ready to ensure critical
business processes and systems continue to operate under crisis conditions. Avista customers
benefit from investments in this program, as the solutions provide redundancy and availability of
critical systems that allow the delivery of electricity and gas securely, safely, and reliably to our
customers.
'Colonial Pipeline May Face$1 Million Penalty for"Operational"Lapses in 2021 Ransomware Attack-CPO
Magazine
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VERSION HISTORY
Version Author Description Date
Draft Andru Miller Initial draft of original business case 613012020
1.0 Andru Miller Updated 5-year funding request 8/9/2022
2.0 Andy Leija Updated 5-year funding request 5/15/2023
BCRT Jeff Smith Has been reviewed by BCRT and meets necessary requirements 5/30/2023
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2024 $100,000 $100,000
2025 $100,000 $100,000
2026 $100,000 $100,000
2027 $100,000 $100,000
2028 $100,000 $100,000
Project Life Span 5 years
Requesting Organization/Department Security
Business Case Owner Sponsor Andy Leija I Clay Storey
Sponsor Organization/Department Enterprise Security
Phase Execution
Category Program
Driver Performance & Capacity
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
Severe storms, natural disasters, major technology failures, and significant security events
are risks that Avista operates under. They are usually unpredictable and can have a high
consequence. These high consequence events can impact the technology systems Avista
relies on to operate the delivery of gas and electricity to our customers. For example, a data
breach incident can average $12.9M. Many of Avista's critical business processes are now
more than ever dependent on data, communication networks, and computer systems.
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Prolonged failure or disruption of any of these systems could have a significant impact on
Avista's ability to deliver gas and electric service to its customers.
1.2 Discuss the major drivers of the business case.
Performance & Capacity is the primary driver for the Enterprise Business Continuity
business case as the investments enhance or address performance or technology capacity
constraints. The availability of each application and network system is assessed annually
during an annual disaster recovery exercise to determine their reliability and recovery
capabilities. This in turn, determines the level of performance or capacity requirements
needed for systems that underperform.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The ability to maintain uninterrupted services and/or quickly recover from a major event or
disaster is critical to serving our customers. Technology investments are needed annually
to continue to enhance the resiliency of our systems that support critical business
processes. Not approving or deferring investments in this business case could limit Avista's
disaster recovery capabilities.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives, and mission statement of the
organization. See link. Avista Strategic Goals
This business case best aligns with Avista's focus area of Perform "...to serve our customers
well and unlocking pathways to growth." Avista conducts an annual disaster recovery
exercise to evaluate the effectiveness of its program, which includes people, process, and
systems. The results of these exercises, along with peer collaboration with utility industry
partners, provides Avista with a strong baseline from which to measure its recovery
capabilities and channel the appropriate level of investment to address any identified issues
or risks.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.
As mentioned in the security business case narratives, the number and level of complexity
in cyber security attacks is significantly growing, as well as attacks by Domestic Violent
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Extremists (DVEs) on physical infrastructure.Z A recently released report by the North
American Electric Reliability Corporation (NERC) tilted Cyber-Informed Transmission
Planning, calls for the integration of cyber and physical protections into transmission
planning to increase reliability and security.' The report emphasizes both prevention and
the ability to recover from an event as a goal for system resiliency. Avista's EBC program
works with all business units to maintain their business impact assessments that document
procedures for when systems are not available. Also, the technology department conducts
an annual disaster recovery exercise to review areas of excellence and improvement. An
after-action report is often produced from the annual exercises,which highlight gaps.These
gaps can vary between people, processes, and systems. This business case focuses on the
investment needed in systems to close those gaps. Examples of previously funded
investments include additional data storage and compute to support growing backup
demand. Also, a new security system was purchased to improve production system
redundancy during the annual exercise.
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Investments under this business case support technology gaps identified during Avista's
annual disaster recovery exercises. The solutions have included additional compute and
storage for backup data center capacity, additional network devices to increase system
failover reliability, and secondary security systems to support redundant protection
schemes. There is no one solution that addresses this complex problem. Instead, the
solutions will vary by the identified gaps. Further assessment and investment are required
in operational technology areas where different operational requirements exist.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).4
2 Electric grid is'attractive target'for domestic violent extremists in US,intel brief says CNN Politics
s Cyber-Informed Transmission Planning Report.NERC. May
4 Please do not attach any requested items to the business case, be sure to have ready access to
such information upon request.
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Much like investing in strong cybersecurity protection, investments in system redundancy,
availability, and recovery are risk-based and just as critical to continue to operate during a
crisis. Based on the consistent annual allocation over the past five years to strategically
deliver disaster recovery solutions, there is a high level of confidence the requested
amount will be fully utilized. According to a recently published article, the average
ransomware attack results in 19 days of downtime.' The average cost for downtime for
companies of all sizes is$4,500 per minute or$1,410 per minute for small businesses.'This
is an average of $2,955 per minute. Assuming the event was like the Colonial Pipeline
incident, the downtime was 6 days or approximately $25.5M. The risk avoided, is the
downtime associated with a potential incident.
2.3 Summarize in the table and describe below the DIRECT offsets7 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital Not Applicable $0 $0 $0 $0 $0
00 Not Applicable $0 $0 $0 $0 $0
There are no direct offsets associated with risk-based investment in disaster recovery
solutions. While an incident cannot be fully prevented, the prudent decision to invest in
recovery solutions brings confidence that when an incident occurs, Avista can recover from
it. With the number of cybersecurity incidents growing in number and complexity, there is
no utility business that would not invest in disaster recovery solutions as part of ongoing
investment and accept it as the cost of doing business.
2.4 Summarize in the table and describe below the INDIRECT offsets8
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital Security Solutions $104,000 $104,000 $104,000 $104,000 $104,000
00 Data Breach Cost Estimates $936,000 $936,000 $936,000 $936,000 $936,000
Using a data breach cost estimates for a PH (Personal Identity Information) and/or a PCI
(Payment Card Industry) data breach, the indirect offsets range from $5.2M to $20.7M per
incident or on average $12.9M. Additionally, the costs associated with incident response,
customer notification, crisis management, regulatory fines and penalties, and class action
lawsuits are mostly operational expense costs. There is an assumption that the
s After a Decline in 2020,Data Breaches Soar in 2021 1 Nasdaq
6 20+Business Data Loss Statistics&Recovery r2022 New Data](businessdit.com)
7 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work under this business case.
Such savings could include reductions in labor, reduced maintenance due to new equipment,or other.
8 Indirect offsets are those items that do not directly reduce the current costs of the Company,but may serve to reduce future
hirings,improve efficiencies, reduces risk(cost or outage),or allows current employees to focus on higher priority work.
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vulnerabilities or gaps identified during the incident will require immediate investment in
recovery solutions to mitigate the existing and/or future events.
The potential indirect offsets are 90% operation and maintenance and 10% capital using
the lowest cost of a data breach with only PII data and no class action lawsuit. However,
they can be significantly higher, such as $18.63M in operation and maintenance and $2.1M
in capital, respectively, should the incident be on the high end. Also, not knowing when or
how often a data breach would occur, the conservative estimate with the assumption that
the incident only happened once, amortized over 5 years, the cost would be $936k in
operation and maintenance and $104k in capital, respectively. The indirect benefit or
reduction of risk is mostly in operation and maintenance costs associated with recovering
from a data breach incident.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, which were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
The requested funding level will address the highest risks that are identified in the after-
action reports first following each annual disaster recovery exercise or those that cannot
wait until the next technology refresh cycle. It is recommended that this level of funding
continue rather than potentially deferring the work 3-5 years since this program is meant
to address high-risk deficiencies in a shorter cycle than a typical refresh cycle.
Option Capital Cost Start Complete
Address disaster recovery gaps identified in $500,000 012024 122028
after-action reports outside of technology
refresh or expansion projects
Alternatives under this business case vary by identified need and solution, based on after
action reports from annual disaster recovery exercises. Historically, solutions have included
additional hardware to increase performance and capacity of existing systems or network
and security systems to develop alternative paths to provide network redundancy and
failover capabilities. Only in the case of a significant need or an incident, will this business
case require additional funding. Therefore, no alternatives are being presented. And doing
nothing is not an option, as we continue to find gaps in each year's disaster recovery
exercises to make our systems more resilient.
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
Success under this business case can be measured by the number of after-action report
findings that can be completed annually based on current funding levels. Additionally, the
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annual disaster recovery exercise should have less and less findings each year assuming the
investments are creating a strong, secure, and resilient environment.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
The Enterprise Business Continuity business case is a program that consists of multiple
projects per year that run concurrently, and at times over multiple years. They follow all
phases of the project lifecycle, facilitated by a project manager, and governed by a steering
committee to determine scope, schedule, and budget forecasts, including transfers-to-
plant.
2.8 Please identify and describe the Steering Committee/governance team that
are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
There are two levels of governance to the Enterprise Business Continuity business case and
the investments within it. They consist of a business case governance team and project
specific steering committees for in-flight projects.
Business Case Governance Team: The Enterprise Security Governance Team provides
monthly oversight of this program business case and makes recommendations based on
forecasted inactive planned investments, the pace of in-flight investments, and any new
unplanned activity that surfaces from an emerging security threat. The team also tracks
business case risks and issues that can affect the portfolio of planned investments.
Monthly governance meetings consist of a full review of each in-flight investment, reasons
for any delays or deviation to proposed completion and transfers to plant schedules and
recommends necessary steps to bring the investments back into schedule or defer inactive
work, when possible, to offset delays. However, should a security risk be increased by
deferring a planned or unplanned investment into future years, the Enterprise Security
Governance Team will recommend a Capital Planning Group (CPG) In-Year Change Request
to surface the impending need. The Change Requests are presented at a monthly
Technology Planning Group meeting to inform the Director members who are also
members of the CPG where the request will be considered and weighed against other
pending requests.
The Enterprise Security Governance Team consists of Avista's Enterprise Security Director,
Cybersecurity Manager, Physical Security Manager, Security Delivery Manager, and the
Project Management Office Manager. The sessions are facilitated by the Security Program
Manager who manages the standing agenda.
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DocuSign Envelope ID:4B9820CF-A33A-4044-B4E3-3C5BCC5031F7
Enterprise Business Continuity (EBC)
Project Steering Committees: Additionally, each security investment is governed by a
project steering committee that consists of the Enterprise Security Director, Cybersecurity
Manager, and Security Delivery Manager, as well as ancillary management team members
required for the successful implementation of the security solution. Steering committee
meetings are facilitated by a Project Manager and held monthly to review scope, schedule,
budget, and risks and issues surfaced from each in-flight project.
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Enterprise Business Continuity
business case and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.
DocuSigned by:
Signature: _ Date: ]un-12-2023 1 10:59 AM PDT
6456C8EEF402467_.
Print Name: Andy Lela
Title: Security Delivery Manager
Role: Business Case Owner
DocuSigned by:
Signature: _E Sf6" Date: 3un-12-2023 11:27 AM PDT
B70F95F7961D4B6...
Print Name: Clay storey
Title: Director of Security
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
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DocuSign Envelope ID:40413711 F-24D9-46D3-BOE2-5F7465E2386A
Gas ERT Replacement Program, ER 3054
EXECUTIVE SUMMARY
An Encoder Receiver Transmitter (ERT) is an electro-mechanical device that allows gas
meters to be read remotely. These ERTs are powered by lithium batteries, which
discharge over time and must eventually be replaced.
Most of the gas meters in Washington, Idaho, and Oregon have ERT modules. The large
quantity of ERT installations will result in an unmanageable quantity of battery failures in
the future if the ERT is not replaced at an optimized frequency and in a planned manner.
When batteries fail, the customer's usage must be estimated and entered into the billing
system manually. This manual process causes a high chance of customer dissatisfaction
because of potential billing errors associated with bill estimations. Customers often
express their dissatisfaction through commission complaints.
The work of replacing the ERT modules will take place in both Idaho and Oregon.
In Idaho, the ERTs will be changed out in mass when the AMI project starts. The AMI
Idaho project is currently in the process of vendor evaluation with a target start in 2026.
Preliminary proposals and pricing are currently being evaluated and more work is being
done with the vendors to better understand the proposed solutions, technical details, and
the associated costs. Additionally, work is being done to match these technologies to the
customer density and specific geographic challenges in the project area. Previous
estimates indicated that 7,400 40G ERT modules may have a battery failure before 2026
due to their age. Over the course of 2023 and 2024, all 7,400 40G ERTs were replaced
due to the uncertainty around the timing of AMI and the failure rates being experienced.
There is currently no designated target for other ERT replacements in Idaho. Work is
being done to determine this number in conjunction with the developing schedule for the
AMI project. Additional funding for this program may be necessary in future years to
support this work. ERT replacement to support the AMI Idaho project will be performed
under the AMI Business Case.
In Oregon, the ERTs will not be changed out in mass because the AMI project will not be
implemented there; therefore, the recommended solution is (and has been for several
years) to replace the oldest 7,000 ERTs each year on a 15-year cycle. This replacement
strategy was optimized by an Avista Asset Management study. The annual cost of this
replacement strategy is approximately $261,000 and it is expected to increase
approximately 5% per year to adjust for increased wages and materials.
If this program is not funded, the amount of ERT battery failures will increase to an
unsustainable level. If not replaced at the proposed rate, a peak of more than 20,000
ERTs are predicted to fail annually, each requiring an unscheduled maintenance visit to
replace, causing an undue burden on Operations personnel and equipment. This large
number of failed ERTs will also cause an unreasonable number of meters that would
need to be read manually, and the customer's usage estimated, resulting in estimated
billing and a negative customer experience.
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DocuSign Envelope ID:40413711 F-24D9-46D3-BOE2-5F7465E2386A
Gas ERT Replacement Program, ER 3054
VERSION HISTORY
Version Author Description Date
1.0 Dave Smith Initial Business Case 3/9/2017
1.1 Dave Smith Revised per Initial Review 3/24/2017
1.2 Jeff Webb 3/31/2017
2.0 Dave Smith Revised for 2020 Oregon GRC Filing 21712020
2.1 Dave Smith Updated to the Refreshed 2020 Business Case Template 6/23/2020
2.2 Dave Smith Updated to the Refreshed 2022 Business Case Template. Edited to 51512022
include WA and ID.
2.4 Dave Smith Updated the Idaho ERT Replacement Work and the Cost Tables in Sect. 2. 10/16/2023
2.5 Douglas Brummett Updated the Run-to-Failure Model in Section 1.3. 411612024
BCRT BCRT Team Has been reviewed by BCRT and meets necessary requirements 51212024
Memember
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2025 $261,000 $261,000
2026 $273,000 $273,000
2027 $286,000 $286,000
2028 $299,000 $299,000
2029 $313,000 $313,000
Project Life Span Ongoing
Requesting Organization/Department Gas Engineering
Business Case Owner I Sponsor Douglas Brummett/Jeff Webb I Alicia Gibbs
Sponsor Organization/Department B51 —Gas Engineering
Phase Execution
Category Program
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
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DocuSign Envelope ID:40413711 F-24D9-46D3-BOE2-5F7465E2386A
Gas ERT Replacement Program, ER 3054
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?
An Encoder Receiver Transmitter (ERT) is an electro-mechanical device that allows gas
meters to be read remotely to support the AMR/AMI systems. These ERTs are powered
by lithium batteries, which discharge over time and must eventually be replaced. The
average battery life for ERT modules is 15 years. Most of the gas meters in
Washington, Idaho, and Oregon have ERT modules. The large quantity of ERT
installations will result in an unmanageable quantity of battery failures in the future if not
replaced at an optimized frequency. When batteries fail, the customer's usage is
estimated and entered into the billing system manually. This manual process causes a
high chance of customer dissatisfaction because of potential billing errors associated
with bill estimation. Customers often express their dissatisfaction through commission
complaints.
Battery replacement was determined to not be the best approach because in order to
replace just the battery, all the potting gel surrounding the battery and circuity inside the
module needs to be removed in order to access the battery, and once the gel is
removed all of the electronic components inside the ERT are now subject to moisture
damage in the field, resulting in additional failures. Itron, the ERT manufacturer, does
not recommend replacing the battery in ERT modules for this reason.
1.2 Discuss the major drivers of the business case.
The major driver for this business case is Asset Condition. This program uses
a proactive and strategic method for addressing asset condition by replacing
ERT modules before their battery fails. Replacing these assets before they fail
will avoid a manual process of estimating a customer's gas usage and bill
resulting in higher customer satisfaction. It is also more efficient and cost
effective to replace the old ERTs in a systematic manner rather than waiting
until their battery fails and having to send out a serviceman to replace a failed
ERT.
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DocuSign Envelope ID:40413711 F-24D9-46D3-BOE2-5F7465E2386A
Gas ERT Replacement Program, ER 3054
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The work is needed now because many of the ERTs have reached their end-
of-life and will begin failing or are already not communicating with the AMI
network as intended resulting in billing issues.
In Idaho, the ERTs will be changed out in mass when the AMI Idaho project
starts. There is some uncertainty around the timing of the AMI project. Due to
the uncertainty around AMI, there is currently no designated target for the
remaining ERT replacements in Idaho. Work is being done to evaluate this in
conjunction with the developing schedule for the AMI project. Additional funds
may be necessary to support this work.
The graph below shows how many ERT modules are expected to fail annually
in Oregon if they are not proactively replaced.
Failures in a Run-to-Failure Model, Oregon
25,000
20,000
L 15,000 - - - - - - - - - - - - - -
3
L.L
H
w 10,000
5,000 - - - - - - - -
0
- - - _ . . 111 11111111
-110 _O -110 -110 _O _O _O _O �O �O 10 -110 10 -110 _O �O �O
If this program is not funded, the amount of ERT battery failures will increase
to an unsustainable level. If not replaced at the proposed rate of 7,000
annually, a peak of more than 20,000 ERTs are predicted to fail annually, each
requiring a maintenance visit to replace, causing an undue burden on
Operations personnel and equipment. This large number of failed ERTs will
also cause an unreasonable number of meters that would need to be read
manually and the customer's usage estimated resulting in estimated billing and
a negative customer experience.
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DocuSign Envelope ID:40413711 F-24D9-46D3-BOE2-5F7465E2386A
Gas ERT Replacement Program, ER 3054
In most areas of Washington, the ERT modules were replaced in 2019 as part
of the Advanced Metering Infrastructure (AMI) project. These ERTs will not
need a planned replacement for approximately 15 years unless they
experience a premature battery failure. This business case also covers
instances where the ERT module is not communicating with the AMI network
as intended, causing a replacement. This will ensure reliable meter reading
and billing.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
This program directly aligns with Avista's focus on our customers and our value of
being trustworthy. Proactively replacing ERT modules is a more cost-effective
approach than reactive replacement, which reduces the overall project costs. In
addition, proactive replacement ensures ERT modules continue operating
effectively, which prioritizes accurate metering and billing for our customers.
Supplemental Information — please describe and summarize the key findings from
any relevant studies, analyses, documentation, photographic evidence, or other
materials that explain the problem this business case will resolve.'
In Idaho, the main concern has been 2005-2007 vintage 40G ERTs failing before
the AMI project commences in 2026. Now that these 7,400 modules have been
replaced, work is being done to determine what additional modules may need to
be replaced given the uncertainty around the start date of AMI.
The graph below shows the quantity of ERTs installed per year in Oregon-
' Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
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DocuSign Envelope ID:40413711 F-24D9-46D3-BOE2-5F7465E2386A
Gas ERT Replacement Program, ER 3054
Approximate Quantity of ERTs Installed Per Year in Oregon*
'Data shown is the quantity of ERTs received each year and is a close approximation to the quanity installed per year
31,1100
31,300
30,000
25,000
21,956
20,000
15,000
10,000
5,236 5,516 5,509
4,732 4,935
5.000
3,586 4,109 4,123 4,104 4,161
70 1■ 9 I I 9® 10
1992 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
If these ERTs are run to battery failure, there will be an unmanageable quantity of
ERT failures each year.
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The recommended solution for Idaho has been to replace the remaining 7,400 +/-
40G ERTs that are at end of life. This work has been completed as of April 2024.
Due to the uncertainty around AMI, there is currently no designated target for the
remaining ERT replacements in Idaho. Work is being done to evaluate this in
conjunction with the developing schedule for the AMI project.
The recommended solution for Oregon is to replace the oldest 7,000 ERTs each
year on a 15-year cycle. This approach targets the oldest ERTs resulting in less
battery failures and as a result fewer estimated customer bills.
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DocuSign Envelope ID:404B711 F-24D9-46D3-BOE2-5F7465E2386A
Gas ERT Replacement Program, ER 3054
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
Some factors that were considered when preparing this request are the
number of ERTs in service, the average battery life of the ERT module, the
effects on the customer's bill if the ERT fails, the cost to reactively replace the
failed module, and the cost to proactively replace the asset before failure.
The Asset Management department was consulted by Gas Engineering for
assistance in developing a strategic program to replace ERT modules in
Oregon since the AMI program would not replace the modules there. The
result of the study suggested the most efficient method for replacing these
assets resulted in the highest customer satisfaction and the lowest cost. The
graph below summarizes the cost savings associated with a proactive and
strategic ERT replacement program over a 15-year cycle:
Run to Failure 15 Year Replacement Cyce Based on ERT 15 Year Replacemert Cycle Based on ERT Location
Age
$50
"e
$4S
0
S40
$35 $12.5MM
•
o' S30
IL`
"0 525
u
$20
E $15
u
$10
S5
S
0 1 2 3 4 S 6 7 8 9 10 11 12 13 14 15 16 17 18 19
Year
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
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DocuSign Envelope ID:40413711 F-24D9-46D3-BOE2-5F7465E2386A
Gas ERT Replacement Program, ER 3054
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and OW) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $0 $0 $0 $0 $0
00 Hourly Maintenance $1,269,380 $1,294,767 $1,276,380 $1,301,907 $1,327,945
If an ERT battery fails, the Mobile Collector will not download the monthly meter
read. As a result, a serviceman is dispatched to investigate the issue which
results in a much higher cost than if the ERT was proactively replaced before the
battery dies. This additional cost is primarily composed of personnel labor and
travel wages, vehicle costs, and the cost to produce an estimated customer bill.
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and OW) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $0 $0 $0 $0 $0
00 $0 $0 $0 $0 $0
There are no quantifiable indirect offsets associated with this program.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
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DocuSign Envelope ID:40413711 F-24D9-46D3-BOE2-5F7465E2386A
Gas ERT Replacement Program, ER 3054
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternative 1:
An alternative solution for Oregon that was considered was to replace 7,000
ERTs based on geographic location each year on a 15-year cycle
(represented by the yellow line in the graph in Section 2.2). This option
involves replacing a geographic cluster of ERTs. The benefit to this approach
is that the ERTs are located close to one another, which equates to less travel
time in-between ERT locations. The disadvantage to this approach is that the
oldest ERTs may not be replaced if they are outside of the geographic zone,
so there would be a higher quantity of ERT battery failures and customer
billing estimates. A third-party contractor provided a cost estimate for both
replacement strategies and the cost to replace the oldest ERTs was not
significantly more than replacing the geographically located ERT clusters,
therefore this alternative solution would cost approximately $5,000,000 over
the life of the 15-year program, mostly due to the number of reactive truck rolls
necessary to replace failed ERTs that were not included in the geographic
locations.
Alternative 2:
The run-to-failure cost to reactively replace the failed ERT modules was also
considered for Idaho and Oregon. When an ERT is run to failure, the
customer's bill is estimated and then corrected the next month after the ERT is
replaced. If this proactive replacement program is not funded, there will be an
unmanageable quantity of ERTs failing each year and it is likely that the failed
ERT will not be replaced in one month's billing cycle resulting in billing
estimates for multiple months. This will create customer dissatisfaction and
loss of trust. See below for breakdown of these risks.
Assumptions:
1. Except for regulatory fines, cost estimates based on SME input.
2. Costs associated with each risk can vary significantly depending on site
conditions.
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DocuSign Envelope ID:40413711 F-24D9-46D3-BOE2-5F7465E2386A
Gas ERT Replacement Program, ER 3054
Risk Probability Definitions:
Risk event expected to occur
High(H) Risk event more likely to occur than not
Probable(P) Risk event may or may not occur
Low(L) Risk event less likely to occur than not
Very Low(VL) I Risk event not expected to occur
Risk Avoidance Over Time and the Cost of Doing Nothing:
Risk Over Time
1 2 5 10 15+
# Risk Year Years Years Years Years Cost Estimate
1 Regulatory Fines L L L L L $257,664 per day per violation(Max)*
$2,576,627 Total(Max)*
2 Pipeline Leak L L L L LE $5,000 to$150,000 per site(site dependent)
3 Pipeline Failure&Outage L L L L $150,000 to$3,000,000 per site(site dependent)
4 Negative Reputation H VH EL
VH Erosion of PUC and Public trust
5 Employee&Public Safety L L L L Lost time,lawsuits,healthcare,etc.(varies)
*State fines are not prescribed and it is up to each state to determine the fine amount. Federal
regulatory fines present a daily and overall maximum value per violation in accordance with 49
CFR Part 190.223. However, these values are not necessarily an accurate representation of
how much Avista would be fined for any specific violation. The actual amount is likely to be
much lower since Avista has an ongoing reputation and history of investing in programs
related to safety and non-compliance issues. However, it is a bookend reminder from which to
characterize the regulatory risk associated with chronic and/or egregious non-compliance,
especially in the event of a pipeline safety incident (i.e. failure). Therefore, Avista must
continue to demonstrate an ongoing commitment to compliance and pipeline safety to ensure
favorable future outcomes with respect to regulatory penalties. (actual penalty amount is at the
discretion of the state or federal agency).
Over the life of the 15-year program in Oregon the asset management study
estimates that the cost of this run-to-failure approach would be approximately
$12,500,000 more than if a proactive and strategic replacement program was
executed. Refer to the cost analysis graph in Section 2.2 showing a
comparison between the preferred and alternative solutions.
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
The ERT Replacement Program is documented in a business plan and
prioritized in a spreadsheet. Each ERT replacement is documented in Maximo
with a work order. Completed work orders can be tracked to show program
progress. In addition, the program yearly spend can be compared to the run-
to-failure model which shows annual cost comparisons and savings that the
program provides.
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DocuSign Envelope ID:40413711 F-24D9-46D3-BOE2-5F7465E2386A
Gas ERT Replacement Program, ER 3054
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
The Oregon program will be completed between January and December each
year on a 15-year cycle. The ERT modules are purchased as a pre-capital
material item under ER 1053 (Gas ERT Minor Blanket).
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
The Asset Management department was consulted by Gas Engineering for
assistance developing a strategic program to replace ERT modules before
their battery expires. The result of the study suggested the optimized method
for replacing these assets that resulted in the highest customer satisfaction
and lowest cost.
Using the replacement strategy recommend by Asset Management, the ERT
Replacement Program Manager works with GIS Technical Services to
determine the location of the oldest 7,000 ERT modules in Oregon. Each year
prior to starting work, the oldest ERT locations are re-analyzed to ensure the
ERT priority list for the year is accurate and up to date. The third-party
contractor performing the replacement work also provides field verification to
ensure only old ERTs are replaced.
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.
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DocuSign Envelope ID:40413711 F-24D9-46D3-BOE2-5F7465E2386A
Gas ERT Replacement Program, ER 3054
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the ER3054—Gas ERT Replacement
Program and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.
D S'g d by:
Signature: ww Date:May-07-2024 1 3:25 PM PDT
15831 FFAC45834CF..
Print Name: 3eff webb
Title: Mgr Gas Engineering
Role: Business Case Owner
D S'g d by:
Signature: a(aaa G� k Date:May-08-2024 1 5:33 AM PDT
C49C42855345E483...
Print Name: Al i ci a Gibbs
Title: Alicia Gibbs
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 12 of 12
Staff PR_037 Attachment C 81 of 237

DocuSign Envelope ID: 1B164927-C717-494C-8CF7-157DEBE2C33E
Gas Overbuilt Pipe Replacement Program, ER 3006
EXECUTIVE SUMMARY
Overbuilt pipe refers to gas pipes that are located directly under or very close to building
structures. Except in rare case, Avista does not intentionally install gas pipes under structures.
In most cases, overbuilt pipe occurs in mobile home parks where home locations tend to vary
over time. The close proximity of these structures makes gas system maintenance and
inspection difficult and can be a serious safety hazard in the event of a leak. In situations where
the gas line is located directly under building structures, this is in violation of the Code of
Federal Regulations (CFR) Title 49 Part 192.361.
Avista's Distribution Integrity Management Program (DIMP) was used to initially identify,
analyze, and risk rank all known large overbuild conditions at the beginning of this program.
These large projects were all found to be located in Avista's Oregon districts, but the program
was created for all service territories (including Idaho and Washington) so that there was
funding to remediate all overbuilt facilities as they were discovered.
This program was previously scheduled to be completed at the end of 2024, but Gas
Engineering is requesting an extension through the year 2027 so that all four remaining large
overbuild projects in Medford can be completed. All of these projects have large sections of gas
main piping located directly underneath mobile homes, which is a violation of federal code and
represents an elevated safety risk for the residents of these homes. These projects consist of
approximately 10,000 ft of main piping, 3,000 ft of service piping, and 103 service points.
Extending the program to 2027 and providing sufficient funding each year will ensure that the
projects can be fully completed within the budget year. Completing projects in one budget year
is more efficient and less disruptive to these communities than breaking projects up into smaller
phases over multiple years. See below for requested funding.
YEAR PLANNED SPEND PLANNED TRANSFER TO
AMOUNT ($) PLANT ($)
2025 $850,000 $850,000
2026 $425,000 $425,000
2027 $450,000 $450,000
All other new overbuild projects discovered on the system starting in 2024 will be funded by ER
3005 Gas Non-Revenue.
Business Case Justification Narrative Template Version: February 2023 Page 1 of 7
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DocuSign Envelope ID: 1B164927-C717-494C-8CF7-157DEBE2C33E
Gas Overbuilt Pipe Replacement Program, ER 3006
VERSION HISTORY
Version Author Description Date
1.0 Seth Samsell Initial version 4/17/2017
2.0 Seth Samsell Revision for 2020 Oregon GRC filing 2/12/2020
2.1 Tim Harding Updated to the refreshed 2022 Business Case Template 9/1/2022
2.2 Mike yang 2024 Business Case Refresh 4/22/2024
BCRT Team
BCRT Member Has been reviewed by BCRT and meets necessary requirements 4/26/2024
GENERAL INFORMATION
YEAR PLANNED SPEND PLANNED TRANSFER TO
AMOUNT ($) PLANT ($)
2025 $850,000 $850,000
2026 $425,000 $425,000
2027 $450,000 $450,000
Project Life Span 2017 -2027
Requesting Organization/Department B51 —Gas Engineering
Business Case Owner I Sponsor Mike Yang/Jeff Webb I Alicia Gibbs
Sponsor Organization/Department B51 —Gas Engineering
Phase Execution
Category Program
Driver Mandatory&Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
Business Case Justification Narrative Template Version: February 2023 Page 2 of 7
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DocuSign Envelope ID: 1B164927-C717-494C-8CF7-157DEBE2C33E
Gas Overbuilt Pipe Replacement Program, ER 3006
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?
Overbuild conditions usually occur when a structure is placed or constructed over an
existing gas pipe. The close proximity of these structures makes gas system maintenance
and inspection difficult, is a violation of federal code, and can be a potential safety hazard
for the occupants.
The funding of this program will allow for the completion of four remaining large overbuild
projects in Medford, OR. All of these projects currently have large sections of gas main
piping located directly underneath mobile homes, which is a violation of federal code and
represents an elevated safety risk for the residents of these homes. These projects
consist of approximately 10,000 ft of main piping, 3,000 ft of service piping, and 103
service points.
1.2 Discuss the major drivers of the business case.
The main drivers for this program are pipeline safety and compliance. Resolving overbuilt
gas pipes keeps Avista compliant with federal codes, increases the safety of customers in
the immediate project areas, and mitigates company risk associated with a serious
pipeline safety incident.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The four overbuilt projects identified are a short-term safety and compliance risk that can
only be resolved through pipeline replacement.
Leaving known overbuilds in place would be a violation of code and Avista's standards.
This could lead to regulatory fines and other enforcement actions. Regulatory fines can be
up to $257,664 per day per violation, up to a $2,576,627 total.
1.4 Discuss how the proposed investment, whether project or program,
aligns with the strategic vision, goals, objectives and mission statement
of the organization. See link.
Avista Strategic Goals
This program focuses on the safety of our customers and compliance with Federal code
requirements. By mitigating the risks associated with Overbuilt pipe, this program aligns
with Avista's organizational focus to maintain safe, compliant, and reliable infrastructure to
achieve optimum life-cycle performance, safely, reliably, and at a fair price for our
customers.
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Gas Overbuilt Pipe Replacement Program, ER 3006
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
The list of four known large overbuilt project locations in Medford to be remediated under
this program can be provided upon request. Future overbuilt facilities that are discovered
in the system as of 2024 will be remediated using ER 3005 (Non-Revenue).
Overbuilt conditions are typically discovered unintentionally during periodic leak survey
activities or by Avista Operations personnel when on site for other activities. These
overbuilt sites can only be identified and confirmed by physically locating the facilities in
the field, so there are no studies or analyses that can be performed to proactively identify
the problem.
The Code of Federal Regulations (CFR) Title 49 Part 192.361 requires all piping located
under buildings to be encased, sealed, and vented so that a leak will not create a hazard.
None of the remaining four overbuilt projects were originally installed with vented and
sealed casings, so they are not in compliance with this requirement and represent a
significant safety hazard in the event of a leak.
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative(e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Extending and sufficiently funding the program will provide the resources to plan,
coordinate, and construct replacement main and service piping in locations that are much
less susceptible to encroachment. Existing mains at these overbuilt locations are in very
small backyards, which is what led to the current overbuild conditions. New main and
service piping will be installed along access roads and near driveways that cannot be
encroached upon as easily. Once the new mains and service are installed and
commissioned, the overbuilt piping will be retired and sealed in place which eliminates the
non-compliance and safety risk.
The alternative of encasing, venting, and sealing the existing pipelines in place is not a
cost effective or practical solution to solving the problem. See section 2.5 for more details
The other alternative of installing the new pipe back into the soft surface backyard area is
also not an advisable long-term solution. See section 2.5 for more details.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
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Gas Overbuilt Pipe Replacement Program, ER 3006
2.2 Describe and provide reference to CIRRARR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
The Code of Federal Regulations (CFR) Title 49 Part 192.361 requires all piping located
under buildings to be encased, sealed, and vented so that a leak will not create a hazard.
Uncased piping under homes is not compliant with federal code. There are no metrics to
quantify the risk associated with overbuilds.
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
There are no capital or O&M direct offsets associated with this investment.
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
There are no indirect offsets (Capital and O&M) that result by undertaking this investment.
Leaving known overbuilds in place would be a violation of code and Avista's standards.
This could lead to regulatory fines up to $257,664 per day per violation, up to a $2,576,627
total.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
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Gas Overbuilt Pipe Replacement Program, ER 3006
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those
additional risks to Avista that may occur if an alternative is selected.
2025 2026 2027
Recommended $850,000 $425,000 $450,000
Alternative 1 $525,000 $425,000 $450,000
Alternative 2 $775,000 $350,000 $400,000
Alternative 1:
Instead of replacing the pipelines, Avista will install casings, vents, and seals so that
the overbuilt pipelines comply with CFR Title 49 Part 192.361. It's possible this option
could save time and money on restoration costs, but the construction and operational
probability of achieving this are low. The effort and cost to do the pipeline portion of
the work could easily be more expensive, which would significantly erode some or all
of the cost savings associated with soft surface restoration. Also, keeping gas
pipelines under buildings in casings still represents an elevated safety risk and would
require more frequent inspections from Avista personnel. Current Avista standard
GSM Spec 3.15 Page 2 does not allow mains within a 5 ft horizontal clearance of
buildings and services within a 2 ft horizontal clearance, so performing this alternative
would require Engineering approved variances to leave them in place. For these
reasons, this alternative is not a reasonable or advisable solution.
Alternative 2:
Another option would be to install new pipelines outside of the access roads and
driveways to save time and money. This option would place the new pipelines back
into the soft surface area similar to where the existing overbuilds are located, but
away from existing buildings. There would be less hard surface to restore and less
service piping work to perform (i.e. tie-overs vs running new services). This option is
not advisable due to the long-term risk that this pipeline will once again have a
structure placed/built over the top of it. All remaining projects under this program are
located at mobile home parks, so the probability of overbuilds occurring again in the
future are high unless the new piping is installed further away from the homes in
areas that unlikely to be encroached upon.
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
Project costs and eliminated overbuilt footage will be tracked and monitored regularly
to ensure that the program is delivering as expected with respect to cost and timeline.
Overall program success will be known once all four remaining large overbuild
facilities in the Medford area have been retired. This will be documented through
redline as-built documents which will then be updated in the GIS and DIMP systems.
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DocuSign Envelope ID: 1B164927-C717-494C-8CF7-157DEBE2C33E
Gas Overbuilt Pipe Replacement Program, ER 3006
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Work covered under this business case proposal will start on approximately January
1st 2025 and conclude by December 31It 2027.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of
the business case, and how such oversight will occur.
This program budget is overseen by Gas Engineering. Construction activities are
overseen by Medford Gas Operations. Projects can be prioritized with input from
the DIMP Program Manager, Medford Gas Operations, and/or Gas Engineering.
DIMP risk scores are assigned to each proposed project. The highest-ranking
projects are generally completed first, but some flexibility is required to ensure that
specific operations groups are not overloaded during any given year. Gas
Engineering reviews the program budget with Medford Gas Operations on a
monthly basis. Monthly updates are documented via a spreadsheet and fund
requests are made using the appropriate forms from the CPG.
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Gas Overbuild Pipe Replacement
Program, ER 3006 and agree with the approach it presents. Significant changes to this will
be coordinated with and approved by the undersigned or their designated representatives.
S'g d by:
Signature: Wa Date: May-03-2024 1 11:47 AM PDT
Ei
5831EEAC45834CE
Print Name: Jeff Webb
Title: Mgr Gas Engineering
Role: Business Case Owner
D11"Signed by:
Signature: Cuua ai s Date: May-04-2024 111:29 AM PDT
4gC42855345E483...
Print Name: Alicia Gibbs
Title: Director of Natural Gas
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
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Generation DC Supplied System Update
EXECUTIVE SUMMARY
The Generation DC Supplied System program covers all the generation and control facilities. It is
the backbone for supplying power to the protective relays, breakers, controls and communication
systems. Experience shows that we must continually monitor, review and maintain our DC
system. To maintain reliability, we follow NERC requirements and design enhancements for the
DC system to be monitored and tested. The equipment manufactures provide estimated life span
for batteries and auxiliary equipment. Some of these estimates have not been accurate and
change outs early due to failing tests or issues with the equipment have been necessary. Proven
manufactures are used to improve reliability and life. The cost of this program overtime is
approximately$420,000 a year.
The overall benefit to customers would be the reliability of our generation and control facilities.
This risk of not approving this business case would result in maintenance work ballooning into
large projects as there would be no prepared design to address issues when problems arise.
Waiting for issues to arise can extend outages and leave the plant exposed for extended time
frames for repairs and/or replacement parts. Upon failure we would temporarily restore the system
back to working condition with the knowledge that we have to address it later. It places plant
equipment at risk if a key element of the DC system were to fail, particularly the battery system.
It also does not provide a means to perform required NERC testing and does not provide a means
to plan for cost efficient replacements. Also, critical AC loads served from the Uninterruptible
Power Supply, UPS have increased to the point where we can no longer get a UPS that is of
necessary size. We would have to install more UPS systems, creating more maintenance work
and increasing the NERC testing requirements. It also does not address any other issues that
our design standard is intending to address. While it is a much higher life cycle cost and
operationally impactful option. The recommended solution was reviewed by GPSS Engineering
and approved by GPSS Management.
VERSION HISTORY
Version Author Description Date Notes
1.0 Glen Farmer Initial Version 411012017
2.0 Glen Farmer Updated timeline from 5-year plan 81112020
3.0 Kristina Newhouse Updated to 2022 Template 8/15/2022
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Generation DC Supplied System Update
GENERAL INFORMATION
Requested Spend Amount $420,000
Requested Spend Time Period 10 years
Requesting Organization/Department GPSS
Business Case Owner I Sponsor Kristina Newhouse Alexis Alexander
Sponsor Organization/Department GPSS
Phase Execution
Category Program
Driver Asset Condition
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
Traditionally, the Direct Current (DC) system, (aka Battery System) at each
generation plant is used for protection and monitoring of the plant. All the protection
relays, breaker control circuits and monitoring circuits are fed from this source. The
source is assumed to always be on-line and able to supply the critical load for a
predetermined length of time.
As technology has evolved, other standalone DC systems that were installed at
different times. Typical plants now have standalone DC Systems for: general station,
Uninterruptible Power Supplies (UPS), governors (electronic turbine speed
controllers), communications and control systems. Each of these systems have a
battery bank, battery charger, converters to supply different voltages, and distribution
panels and circuits. As things have changed on the generating units or in the balance
of plant systems, the DC load requirement has significantly increased and the time
duration for the systems to supply this critical load has increased. Our current practice
is to replace the battery banks per manufactures life cycle recommendations. This
practice is not addressing the additional load added to the systems.
Some of the other issues we have had on the DC systems are the failing of battery
cells due to inconsistent temperature and environmental control needed to maintain
these present battery systems. The system life cycle is 20 years at its normal
operating temperature of 77 degrees F. For temperatures fifteen degrees F over the
normal operating temperature the life cycle is decreased by 50 percent. Component
failure, utilization from multiple extended outages and manufactures quality are other
problems we have experienced on these systems.
Finally, there are compliance requirements from the North American Electric
Reliability Corporation (NERC)for inspections, maintenance and testing of the battery
banks to make sure they are in good working order and will perform when called upon.
To perform these inspections and maintenance, and testing needs, it requires either
unit or plant outages to comply with the requirements for multiple DC systems that
are now present in our stations.
To address these multiple issues, a new Generation Plant DC Standard was
developed by the engineering group. The new Generation Plant DC Standard System
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Generation DC Supplied System Update
provides for layers of back up and redundancy to address current and future capacity
needs as well as addressing maintenance and testing requirements. This Program
will replace existing DC systems at Avista's owned and operated generation plants
with a system that meets this new design standard.The Generation Plant DC Standard
will be used as a guide for defining the base scope of the 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 activity objectives are to order the plant replacements in a timeline that will allow
for stages of a project to happen and use our engineering and construction staffing. At
each plant the DC System will be updated to meet the current Generation Plant DC
System Standard and the following:
• Comply with NERC requirements for inspection and testing.
• Address battery room environmental conditions to optimize battery life.
• Replace any legacy UPS systems with an invertor system.
• Address auxiliary equipment based on life cycle.
• Hydrogen sensing and fire alarm, eyewash station and lighting.
• Wall separation of batteries and auxiliary equipment.
• Install Programmable logic controller monitoring and new operating
screens to provide visibility for operations and maintenance purposes.
• Provide new distribution panels, disconnect switches, voltage conversion
devices for communications equipment that operate at different voltages.
• Establish current drawings, construction documents, 1/0 list, plans,
schedules, manuals and as-builts.
1.3 Identify why this work is needed now and what risks there are if not approved or
is deferred
The biggest risk is a battery bank not being able to provide load to the plant. The
batteries are supposed to have a 20-year life based on the manufacture, but we have
only seen one manufacture perform to this level. We are using this manufacture going
forward and expect to have them last the full life.
If not approved and we have a failure of a battery then budgets, schedules and
resources on other projects would be diverted to handle fixing the 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.
With the DC design standard, we are creating the best possible environment for the
battery banks and have enhanced monitoring of the system. This gives Operations
better insight to how the DC system is functioning.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
The preparation of our DC Standard incorporates IEEE design parameters and
standards. It has redundancy built in for testing and suppling load.
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Generation DC Supplied System 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.
2. PROPOSAL AND RECOMMENDED SOLUTION
The recommended solution is to construct new systems as part of a programmatic effort.
This would allow for prioritized and planned series of projects to upgrade the existing station
DC systems to the Generation Plant DC Standard. This will save time and expense over the
life cycle of the station with the flexibility it provides to address future capacity and
maintenance needs, and the ability to perform NERC required testing. It also has the benefit
allowing a schedule to be established for both the engineering and the installation. Both of
these resources are constrained and it would allow options of contracting or in-house
consideration. A typical schedule to execute is given below. Each planned project would take
approximately 16 to 18 months. Added complexity, cost, and time may be needed if extensive
work is required to address the temperature and other environmental issues with the location
of the new battery system. This program aligns with Avista's Safe and Reliable Infrastructure
goal through investment to achieve optimum life-cycle performance and operational safety.
In addition, it helps Avista meet its corporate compliance goals.
Alternative 1 is to address the DC system as part of another capital project. In this case the
scope of the DC system upgrade project is often a lower-level effort and is subordinated to
the primary project. The table below shows the current upgrade plans. While planning and
scoping management can manage the concerns about making sure the DC Supplied
Systems can be fully addressed, we do not have plans to work through all the plants. This
would leave the program incomplete.
Alternative 2 to replace parts as they fail doesn't address any of the requirements for
Standards, NERC inspection and testing, or the room itself. The parts fail at different time
and we are subject to more outages. This also requires reaction to a critical system failure.
Clearly replacing failed parts and components is a more costly item than performing planned
work and without a planned effort, deployment of that new Generation Plant DC Standard
would likely take decades. Replacing as components fail and gradually build out to our
standard has the benefit of minimizing the costs of this program. However, it would be
unpredictable would make labor planning impossible. This would also place the plant at a
higher likelihood of forced outages and equipment damages if we wait for failure.
Option Capital Cost Start Complete
[Recommended Solution]Establish independent DC $1.315M 012017 082026
system replacement program to bring plants to
standard as quickly as possible
[Alternative #1]Address the DC system standards $1.315M 0152017 082030
as we are doing other system or unit upgrades.
[Alternative#2]Address the DC systems as they fail $1.315M 012017 122037
testing or battery issues arise with the goal of
making it like our standard over time.
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The capital request was developed from budgetary quotes from manufacture and
compared to previous projects of similar type.
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Generation DC Supplied System Update
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.]
There are normally three different projects happing each year. One project would be in
the initiation phase, the next would be in the execution phase and the next would be in
the close out phase. Maintenance is reduced after the execution phase and we have
not seen it pick back up for the first five years of the life span.
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 engineer business process would be used. This allows for the stakeholders to be
involved from the beginning to the end of the project.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The risk of addressing the DC system when there is an issue is usually that is too late.
We have had one instance where the DC system failed and some equipment was
damaged due to this not functioning correctly.
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.
We normally have one project per year become used and useful.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
A new DC System contributes to the Safe and responsible design, construction,
operation and maintenance of Avista's generation fleet.
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
We ranked this project based on a ranking matrix to ensure prudent consideration of
costs, scheduling and personnel resources.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
• Electric shop • Thermal Operations
• PCM shop • Protection Engineering
• Electrical Engineering • Environmental
• Controls Engineering • Project Management
• Hydro Operations • Power Supply
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Generation DC Supplied System Update
2.8.2 Identify any related Business Cases
None.
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The Steering Committee consists of the following members: Manager of Project
Delivery, Manager of Maintenance and Construction, Manager of Hydro Operations
& Maintenance, and Manager of Thermal Operations & Maintenance.
3.2 Provide and discuss the governance processes and people that will provide
oversight
More detailed project governance protocols will be established during the project
chartering process. The Steering Committee will allocate appropriate resources to
all project activities once the scope is better defined.
Persons providing oversight include: Generation Electrical Engineering Manager,
Forman PCM shop, Manager C&M - Electric Shop and the Plant Managers.
3.3 How will decision-making, prioritization, and change requests be documented
and monitored
Project decisions will be coordinated by the project manager. The Steering
Committee will be advised when necessary. Regular updates will be provided to
the Steering Committee by the project manager as project scope, schedule and
budget are defined, and through the course of the project execution.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the DC Supplied System Upgrades
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: 8/15/2022
Print Name: Kristina Newhouse
Title: Controls/Electrical Eng Manager
Role: Business Case Owner
Digitally signed by Alexis
Signature: Alexis Alexander Alexander Date:
Date:2022.09.02 16:43:00-07'00'
Print Name: Alexis Alexander
Title: Director, GPSS
Role: Business Case Sponsor
Signature: Date:
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Generation DC Supplied System Update
Print Name:
Title:
Role: Steering/Advisory Committee Review
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DocuSign Envelope ID:7FC40954-5082-4E8B-9679-C1C6FE162129
High Voltage Protection
EXECUTIVE SUMMARY
Under Lumen (formerly known as Century Link), Avista is required to provide high voltage
protection for leased communication circuits in high voltage areas newer than September
12, 1994. If Avista does not meet the tariff requirements, telecommunication companies
can turn off communication circuits to substations until Avista electrically isolates the
copper wire coming into a substation, thereby affecting phone, modem, SCADA
(Substation Control and Data Acquisition), and other metering and monitoring systems at
substations. This infrastructure is core to utility operations, thus demanding safe and
reliable networks. This business case will meet the needs of this tariff and ensure
investments are made to minimize risk regarding personal safety for all workers in and
around these high voltage areas.
This business case is requesting $200,000 in 2024 to finish the removal of copper wire
and install fiber optic cable to the last three identified substations across Avista's service
territory currently without an HVP solution. Once the last sites are complete with a high
voltage protection package, the business case will be closed at the end of 2024. The cost
of each solution has historically proven symmetrical across substations and we have been
able to leverage that data to estimate costs based on the number of sites outstanding.
The risk of not approving this business case and its funding request will result in an
inability to support the safety of personnel near high voltage equipment where
unprotected communication circuits exist. Additionally, termination of services by the
telecommunications circuit provider could occur if their HVP requirements are not met.
This would impact Avista's ability to control and monitor our substation and transmission
facilities safely and reliably.
Avista customers benefit from this work by having a reliable network connection to the
sites without interruption of services thus reducing the likelihood of an outage due to lack
of communication.
There are no direct or indirect cost offsets due to this work.
VERSION HISTORY
Version Author Description Date
5.0 Shawna Kiesbuy Revision of BCJN to new template 412023
BCRT BCRT Team Has been reviewed by BCRT and meets necessary requirements 4/20/2023
Member
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DocuSign Envelope ID:7FC40954-5082-4E8B-9679-C1C6FE162129
High Voltage Protection
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2024 $200,000 $200,000
2025 $0 $0
2026 $0 $0
2027 $0 $0
2028 $0 $0
Project Life Span 1 year
Requesting Organization/Department Enterprise Technology
Business Case Owner I Sponsor Shawna Kiesbuy I Jim Corder
Sponsor Organization/Department Enterprise Technology
Phase Execution
Category Program
Driver Mandatory& Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. B U S I N E S S P RO B L E M - 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?
Under Lumen (formerly known as Century Link), Tariff FCC (Federal
Communications Commission) Number 1, Section 13.7, Avista is required to
provide high voltage protection for leased communication circuits in high voltage
areas newer than September 12, 1994. If Avista does not meet the tariff
requirements, telecommunication companies can turn off communication
circuits to substations until Avista electrically isolates the copper wire coming
into a substation, thereby affecting phone, modem, SCADA (Substation Control
and Data Acquisition), and other metering and monitoring systems at
substations. This infrastructure is core to utility operations, thus demanding safe
and reliable networks. This business case will meet the needs of this tariff and
ensure investments are made to minimize risk regarding personal safety for all
workers in and around these high voltage areas. The cost of each solution has
historically proven symmetrical across substations, and we have been able to
leverage that data to estimate costs based on the number of sites outstanding.
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High Voltage Protection
As of early 2023, this business case is focused on adding high voltage protection
to the last 5 substations within Avista's territories to meet the Tariff
requirements. All 5 projects will be completed by the end of 2024.
1.2 Discuss the major drivers of the business case.
The main driver for this business case is Mandatory and Compliance. The
technology improvements invested under this business case will provide
protection for communication circuits in high voltage areas in support of
employee and public safety, system reliability, and business productivity
throughout our service territory. Avista and its customers will experience the
benefits through ongoing attention to safety and system reliability.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
Avista facilities providing service to electric power generating, switching, or
distribution stations might require the use of special High Voltage Protection
(HVP) apparatuses such as isolation or neutralization devices. These devices
are to protect against the effects of Ground Potential Rise (GPR) and induction
caused by faults in a customer's electric power system. The special protection
precautions are intended to minimize electrical hazards to personnel and
prevent electrical damage to telecommunications equipment and facilities. This
work is ongoing until all sites have been neutralized for this hazard.
The risk of not approving this business case and its funding request will result
in an inability to support the safety of personnel near high voltage equipment
where unprotected communication circuits exist. Additionally, termination of
services by the telecommunications circuit provider could occur if their HVP
requirements are not met. This would impact Avista's ability to control and
monitor our substation and transmission facilities safely and reliably.
1.4 Discuss how the proposed investment,whether project or program, aligns
with the strategic vision, goals, objectives, and mission statement of the
organization. See link.
Avista Strategic Goals
The High Voltage Protection initiative aligns with Avista's commitment to invest
in its infrastructure to achieve optimal lifecycle performance — safety, reliability,
and at a fair price.
Our Customers — Our customers could see a negative impact to the reliable
delivery of energy if services provided by the telecommunications circuit
provider are terminated because their HVP requirements were not met. This
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action would result in our inability to receive delivery of telemetry data which
gives us situational awareness and control of the systems and devices that
serves energy to customers.
Our People — Our employees could see a negative impact in their ability to
operate and control the system on a real-time basis, adding safety risks and in-
efficiencies to normal operating procedures.
Perform -We have built these real time data efficiencies into our daily operations
and budgets. Sending crews to man locations without telemetry or control
circuits would be cost prohibitive, inefficient, and extremely disruptive to existing
operations. We would be moving in the wrong direction of progress.
Invent — We are on the back end of the product lifecycle curve with the copper
technologies in substations. We must increase our cadence of deployments with
current/newer network technologies to keep pace with markets, carriers,
suppliers, vendors, and other energy companies with whom we have
interconnections and service relationships. Otherwise, we risk misalignments,
obsolescence, and an inability to move data, communicate and control.
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1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
http://www.centurylink.com/techpub/77321/77321.pdf
2. PROPOSAL AND RECOMMENDED SOLUTION - Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
These projects will set a course of action for implementing a fiber optic cable at
sites that do not have a currently compliant HVP solution. This cable which has
no electrical conductivity will be attached to a converter to convert electrical
signals into an Optical Fiber based signal, to connect substations to telephone
company services in accordance with IEEE standards.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
Under Lumen (formerly known as CenturyLink), Tariff FCC Number 1, Section
13.7, Avista is required to provide high voltage protection for leased
communication circuits in high voltage areas newer than September 12, 1994.
At this time, 5 locations do not have the current HVP standard package installed.
2.3 Summarize in the table and describe below the DIRECT offsets3 or
savings (Capital and OW) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $0 $0 $0 $0 $0
00 $0 $0 $0 $0 $0
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
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No Direct-This business case has NO identifiable direct or indirect cost savings
for customers. Under Lumen (formerly known as CenturyLink), Tariff FCC
Number 1, Section 13.7, Avista is required to provide high voltage protection for
leased communication circuits in high voltage areas newer than September 12,
1994. If Avista does not meet tariff requirements, telecommunication companies
can turn off communication circuits to substations until Avista electrically
isolates the copper wire coming into a substation, thereby affecting phone,
modem, SCADA, and other metering & monitoring systems at substations. If we
lose communications to substations, SCADA has zero visibility to the devices at
this location and cannot perform system monitoring and performance analysis
on the devices at the said location.
Additionally, any personnel working at a substation that does not have high
voltage protection runs the risk of being in harm's way during a high voltage
event that produces an electrical surge or an arc flash.
2.4 Summarize in the table and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $0 $0 $0 $0 $0
0&M $0 $0 $0 $0 $0
No Indirect - This business case has NO identifiable direct or indirect cost
savings for customers. Under Lumen (formerly known as CenturyLink), Tariff
FCC Number 1, Section 13.7, Avista is required to provide high voltage
protection for leased communication circuits in high voltage areas newer than
September 12, 1994. If Avista does not meet tariff requirements,
telecommunication companies can turn off communication circuits to
substations until Avista electrically isolates the copper wire coming into a
substation, thereby affecting phone, modem, SCADA, and other metering &
monitoring systems at substations. If we lose communications to substations,
SCADA has zero visibility to the devices at this location and cannot perform
system monitoring and performance analysis on the devices at the said location.
Additionally, any personnel working at a substation that does not have high
voltage protection runs the risk of being in harm's way during a high voltage
event that produces an electrical surge or an arc flash.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
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2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
The requested funding levels have been established based on the number of
sites currently identified as needed or upgrades to existing High Voltage
Protection (HVP) packages. At this time, 5 locations do not have the current
HVP standard package installed. This business case intends to complete the
last 5 sites by the end of 2024.
Alternative 1: Do not fund the business case
High Voltage Protection projects would not be funded. Personnel and equipment
safety risks would remain at unprotected substation locations and
telecommunication carriers would be able to deny service at the same
unprotected locations. Additionally, any Avista personnel working at a
substation that does not have high voltage protection runs the risk of being in
harm's way during a high voltage event that produces an electrical surge or an
arc flash.
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
The investment and work involved in implementing the projects contained in this
business case have been produced and proved successful in previous projects.
As the design standards are such that repeatable success can be achieved,
there is minimal risk of not meeting the desired protection objectives with
appropriate funding allocations and a professionally trained and skilled
workforce.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
The High Voltage Protection business case is managed as a program of projects
planned yearly. All individual projects are managed through the Project
Management Office (PMO), which follows the Project Management Institute
(PMI) standards. Throughout the year, the business case's projects are Initiated,
Planned, Executed, and then Completed with a Transfer to Plant for the scope
requests which over the course of a calendar year equates to the funded budget
allocation.
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2.5 2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
The High Voltage Protection Business Case has two levels of governance: The
Program Steering Committee and the Project Steering Committee.
Program Steering Committee
This business case is a program of related projects. The Program Steering
Committee consists of members in management positions that are identified
and responsible for prioritizing the projects within this program. The Steering
Committee is also held accountable for the financial performance of this
program. The Program Steering Committee will have regular meetings to review
the progress of the program and to make decisions on the following topics:
• Project prioritization and risk
• Approving business case funding requests
• New project initiation and sequencing
The Program will be facilitated and administrated by an assigned Program
Manager within the PMO. The project queue will be reviewed periodically to plan
and sequence work to the levels of funding allocation received.
Project Steering Committee
Project Steering Committees function as the governing body over each
individual project within the program and will consist of key members in
management positions that are identified as responsible for the successful
completion of the scope of work identified in the Charter document for the
Project. The Project Steering Committee is responsible for providing guidance
and making decisions on key issues that affect the following topics:
• Scope
• Schedule
• Budget
• Project Issues
• Project Risks
The Project Steering Committee will meet at the defined intervals documented
in the Charter of the project and will be facilitated by an assigned Project
Manager from within the PMO.
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3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the High Voltage Protection and agree
with the approach it presents. Significant changes to this will be coordinated with and
approved by the undersigned or their designated representatives.
Signature: D sg tlby:[�,aunn.a �icsbwj Date: May-11-2023 6:41 AM PDT S
3Gg05A81B984G3—
Print Name: Shawna Kiesbuy
Title: Sr. Manager, Network Engineering
Role: Business Case Owner
DSg tlby:
Signature: (16r� Date: May-11-2023 9:so AM PDT
E-.'114 911114141
Print Name: Jim Corder
Title: Director, Infrastructure Technology
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
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KF Fuel Yard Equipment Replacement
EXECUTIVE SUMMARY
The existing system does not allow the plant to operate consistently with safe best
practices, environmental stewartship and production. The fuel handling equipment
operates at or beyond its absolute limit. In the early 1980's Washington State increased
the legal hauling weight and the trucking industry transitioned from 48' trailers to 53' to
increase their payload. This change created a number of production and safety
challenges for the plant operations and contractor support. The system does not meet
current environmental regulations for visibility and particulate matter (PM) emissions for
intermittent periods. Although the primary drivers for the project are safety,
environmental, and reliability, we do expect a decrease in O&M. With all benefits
included, Financial Planning and Analysis has concluded that this is a prudent project.
The project will proceed over a two year period with $12 million in 2019 and $10 million
in 2020. (7/8/2021 Update: Project timeline has been extended and adjusted and the
current plan will continue into 2021 with the underground utilities installed, major
equipment purchased and truck dumpers commissioned. 2022 will be construction of
conveyance, processing and control buildings and installation of the hog and disc screen.)
Replacing the major fuel handling equipment will create a safer system for employees
and contractors as the new dumpers will be designed to lift current truck lengths and
weights. The major equipment will be designed with covers and passive dust control
utilizing new dumper technology and conveyance covers. (71812021 Update: Scope has
been reduced to reduce project costs by changing the truck route, eliminating a pass
through travel route, reduction of an enclosed processing building, eliminating a conveyor
through a more compact layout, eliminating a new power supply from the distribution line
near the plant site and delay of replacing the existing #3 fuel conveyor)
This project will impact customers in service code Electric Direct jurisdiction Allocated
North serving our electric customers in Washington and Idaho.
VERSION HISTORY
Version Author Description Date Notes
Draft Greg Wiggins Initial draft of original business case 0510112018
1.0 Thomas Dempsey Edit Draft/Executive Summary 07/03/2018 Added content
Edit Approved Business Case to new New Template/Update major
1.1 Greg Wiggins Template 0710812021 project changes Scope,
Schedule and Budget
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KF Fuel Yard Equipment Replacement
GENERAL INFORMATION
Requested Spend Amount $22,000,000
Requested Spend Time Period 2 year(71812021 Update project will be 5 year)
Requesting Organization/Department GPSS
Business Case Owner I Sponsor Greg Wiggins Andy Vickers
Sponsor Organization/Department GPSS
Phase Execution (71812021 Update project is in execution phase)
Category Project
Driver Asset Condition
1. BUSINESS PROBLEM
The major fuel yard equipment being
considered for replacement includes
the truck dumpers, fuel hog, truck
scale, and conveyance systems.
Truck Scale - The truck scale is -
used to account for the quantity of
fuel received from each truck
delivery. The truck drivers scale in
upon arrival to the site and the scale
out after completing the unloading
process.
Truck Dumpers - The truck dumper
receives the delivered fuel by '
elevating the trailers. Fuel exits the
rear of the trailer into a receiving }' _
housing.
Fuel Conveyors - Fuel conveyers move the fuel from the truck dumpers to a metal
detection system, then to the fuel hog system and finally out to the fuel yard.
Hog and Disc Screen - The fuel hog is a device that clarifies and conditions the fuel
so that it is the proper size required for optimum combustion.
1.1 What is the current or potential problem that is being addressed?
There are three key components that comprise the business problem presented
by the current fuel yard.
1. Safety
2. Environmental
3. Reliability
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These three components are summarized as follows:
The Kettle Falls Generating Station is a biomass fueled power plant that processes on
average 500,000 green tons of waste wood from area sawmills. The wood delivered to
the facility is trucked in by contractors utilizing semi-trucks and chip trailer. On average
the plant received 65-80 loads of fuel each day with surges to 100 deliveries in a 24 hour
period.
The plant's original design was just prior to Washington State increasing the legal haul
lengths and weights. All the equipment was designed for 48' trailers and the new law
change in 1985 allowed drivers to haul with 53' trailers. When the drivers enter the facility
the load is weighed on a State certified scale to determine amount of fuel being delivered.
The longer trailers do not completely fit on the scale without the drivers lifting the tag axle
on the trailer. The plant's delivery tracking system captures the gross weight of the truck
and trailer into the Rog financial interface application. Through this system vendors and
suppliers are paid for their services. Due to the longer trailers and short scale drives can
"cheat" the system by not positioning the load correctly on the scale. Each load is
reviewed through the Rog (TWA) Truck Weight Analyzer. When an infraction is found
the surveillance video is reviewed and sent to the hauling company for reconciliation.
Manual adjustments are made in the system to ensure proper payment to the supplier.
Truck was intentionally positioned short on the scale. TWA show drivers manipulating the scale due to being overloaded.
The fuel is offloaded truck trailers into the receiving hoppers via a truck dumpers. The
wood is then conveyed, screened and sized prior to being transferred out to the fuel
inventory pile. The Fuel Equipment Operators then manage the fuel inventory utilizing
D10 Cat dozers to stack out incoming fuel and stage inventory to be processed in the
plant.
Due to the higher legal hauling limits in Washington the longer truck/trailer configurations
require the truck drivers to unhitch the trailer from their trucks. This unhitching process
not only increases truck turnaround time and increases hauling costs to plant, it adds a
difficult step. Although not the primary factor, a contractor fatality in 2013 occurred while
going through this step in the process. One driver was attempting to unhitch his trailer
from the truck and was working with another driver to get the hitch pin released when the
accident occurred.
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After the load is raised into the air and the fuel is discharged out of the back of the haul
trailer into the truck receiving hopper a large plume of dust often launched into the air and
then carried in the wind off the plant
site. After the wood discharges out
of the truck receiving hopper it is
transferred via conveyor belt to a
disc screen and hammer hog to be
properly sized and then discharged
onto the hog storage area.
Both Safety and Environmental
regulations require that PM be
reasonably controlled for worker �..
safety, air quality and visibility. All �-
emissions should be managed on-
site. -
The fuel yard is subject to a very corrosive environment due to the wet wood being in
contact with the equipment. The years of rusting has caused failure to metal conduit and
structural steel. The metal support structure of the truck receiving hoppers has rusted
through to the point of being completely cracked through. Welded plates have been
installed to affected areas on the truck receiving dumpers. Many of the electrical conduits
are rusted through and need replacement.
The system is currently running at maximum capacity with fuel spilling over the edges of
the conveyance system, the disc screen is not operating at the proper throughput as a
significant amount of proper sized fuel is carried over the disc screen into the hammer
hog. The over feeding of material into the hog creates excessive wear on the hammer
hog grates and hammers.
With an average of 80 semi loads delivered each day and over 25 sawmills depending on
the fuel yard at Kettle Falls to be in full operation there is tremendous pressure in keeping
the system running. Area mills store the fuel purchased by Avista in storage bins and can
only hold the waste wood for a few days and sometimes only hours before the backup of
wood begins to cause production issues at the mill. When product flow out of the mill is
not managed well suppliers may begin to look for other options to move their waste to
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KF Fuel Yard Equipment Replacement
more reliable markets. Another important detriment to not keeping fuel moving efficiently
is that as more fuel inventory builds at the supplying mill, the resulting Moisture Content
increases as well as the opportunity for contamination from rock and other "non-spec"
materials. It is important to keep the KFGS fuel yard operating with minimal downtime
to provide good service and quality control to the supplier's milling operations. It is critical
to the reliability of both the KFGS plant and its supply chain.
In 2017 a team was assembled including the Thermal Operations and Maintenance
Manager, Fuel Manager, Plant Manager, Thermal Engineering and plant staff. The team
worked with outside engineering firm WSP to evaluate the fuel yard equipment and
explore options. The team also traveled to two new biomass plants to gain knowledge of
new equipment and process. This information along with the support of WSP allowed the
team to evaluate a number of options.
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
Major drivers for this project were Asset Condition and Mandatory & Compliance.
Installing the new fuel yard equipment with a higher capacity design and
environmental dust control measures will be a benefit to the plant and neighbors.
Moving truck through the yard quickly reduces trucking costs. This project will
decrease truck turn time.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The plant experienced a fatality of a contract driver that would have been completely
avoided if the truck dumpers were able to lift the current truck weights and lengths.
A few years later another driver was injured on plant site attempting to manually
offload his overloaded trailer when a bunch of fuel slid out of the trailer and buried
the driver crushing his hip and knee. This project will make for a safer facility for our
contractors.
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.
Truck weight analyzer and the weighwiz system will be able to accurately capture
the delivery with the new longer scales. Truck turntime will decrease as drivers will
no longer need to lift tag axels, disconnect the truck and trailer or use one scale for
inbound and outbound scaling.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
In 2017 a team was assembled including the Thermal Operations and Maintenance Manager, Fuel
Manager, Plant Manager, Thermal Engineering and plant staff. The team worked with outside
engineering firm WSP to evaluate the fuel yard equipment and explore options. WSP presented
the Team a feasibility study with options to consider. That document is located in the project file.
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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 team selected option #3 and in replacing the major equipment in a new layout.
Below shows the four options, matrix score, CAPX and OPEX.
This feasibility study includes estimated CAPEX,OPEX and MTC,and discusses the pros and cons of the scenarios analyzed.
The possibility of an increase in generation of 15 MW was considered when sizing the equipment.Some equipment drives
may require upgrading,as such the equipment was sized for the increase.
Based on extensive in-person meetings with the Avista project team,four scenarios were examined to meet the
requirements of the plant results of the analysis for the scenarios are shown in the table below.
System#1: System#2: System#3: New System#4:
Existing and Existing Layout Layout c/w new New System c/w
Rebuilds c/w new equip equip Covered Building
Avista's Ranking
Calculator by System 370.00 296.00 123.00 143.00
CAPEX(2017$) $4.2 M S9.5 M S21.6 M S30.1 M
OPEX(average over 20 S1,095,000 $1,121,000 $665,000 $998,000
years,2017$)
MTC(average over 20 S829,000 $782,000 S405,000 S432,000
years,2017$)
2. PROPOSAL AND RECOMMENDED SOLUTION
The four options were discussed and doing nothing has been the approach for a
number of years. Maintenance costs have increased with equipment failure to the
live bottom gear boxes, dumper cylinders and lifting deck. Modifications are being
made to equipment due to obsolete equipment is no longer available. This
approach will see continued breakdown maintenance, reduction in fuel yard
reliability and continued risks around safety and environmental litigation.
Option 1 includes major rebuild of the existing equipment. The truck dumpers
would have mechanical and support rebuilt, some conveyors would be sped up to
the maximum allowed throughput, hog and disc screen would be rebuilt, the power
distribution, motor control centers and PLC's replaced, all the electrical hardware in
the yard would be replaced. This option would not change the operations of the fuel
handling system. Safety and environmental concerns would remain unchanged.
The truck scaling issue would still remain. The work would create major disruptions
to our suppliers as the work and repairs could not be done without interrupting
delivery schedules for days and weeks at a time. Fuel would have to be diverted to
other consumers with the risk of losing the contracts in the future.
Option 2 included replacing key equipment with one new scale, two dumpers, two
conveyors, hog and screen in the existing location. This option would not address
the congested truck route that currently exists with one scale. The fuel conveyor
angle would remain the same and would not solve the sliding winter fuel issues
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experienced by the plant operations staff all winter long. This option would disrupt
dilveries and cause major fuel disruptions to the sawmills and carriers under
contract. Temporary truck dumpers would have to be installed and significant fuel
curtailment and deverting would be required.
Recommendation is to pursue Option 3 that includes relocating new equipment to a
different location in the fuel yard. This approach would allow the current system to
operate while the new system is constructed and commissioned. The layout would
reduce crossing traffic issues with the semi trucks. A new longer inbound and
separate outbound scales would eliminate the scaling issue as sensors would not
allow a driver to scale in unless the truck was positioned correctly on the scale. The
two new truck dumpers would be larger in size which would allow the lifting of both
the truck and the trailer. This would reduce truck turnaround time and eliminate the
hazard identified in the driver fatality. The new dumpers would incorporate a dust
containments systems to reduce fugitive dust during the offload. New conveyors
would be larger to accommodate higher throughput. The higher capacity belt
system would reduce laborious shoveling of spilled fuel. The incline of the new
belts would reduce winter frozen fuel from sliding on the conveyor belts. The disc
screen would be larger in size for better screening efficiency and reduce hog
operation to only oversized material. The upgraded stack out fuel conveyor system
would strategically move the fuel to three locations reducing Caterpillar dozer fuel
consumption and yearly time base maintenance. A new control tower and power
supply would eliminate the electrical deficiencies with the current system.
Option 4 is the same as option 3 with the addition of a covered fuel storage area.
Covering the fuel could reduce moisture content during the winter months. Power
Supply and Asset Management explored the additional cost benefit and this option
did not make financial sense.
Option Capital Cost Start Complete
Existing Rebuild and Minor Upgrades $4,200,000 10/2020 6/2023
Existing Layout with New Equipment $9,500,000 10/2020 6/2023
New Layout with New Equipment $22,000,000 10/2020 6/2023
New Layout with New Equipment and Covered Yard $30,100,000 10/2020 6/2023
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KF Fuel Yard Equipment Replacement
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The Team worked with WSP and evaluated ever component of the fuel
handling system. All of the current equipment was ranked using the GPSS
project ranking matrix and the scores were used to determine what system
would meet the criteria set for the project. Below is an example of the analysis
that was done for every part of the fuel handing system.
Avista KFGS Woodyard Study Equipment Alternatives and Ranking Table
WSP Ref#:171-11373-00/18S233A Date:10/19/2017
Scope of Work Description&Avista Rating
system#2:Existing Layout System#3:New Layout c/w system#4:New System c/w
Rem#Equipment Name I Wt System#1:Existing c/w new equip new equip lCovered Building
1 Truck Scale(s) -maintenance -new single scale and data -new dual scales and data -new dual scales and data
recorder recorder recorder
Personal or public 3 2 0 0
safety
Potential
environmental issua 0 0 0
Regulatory mandate
0 0
On-going
maintenance issue _ 0 0
wt3
Decrease future
operating costs _ : 0 0
Increase efficiency
(revenues-power _ 1
usa e)
Obsolete parts and _
equipment _
Risk of equipment - _
failure
Customer Value -
Sub-total -- --
Reference key points from external documentation, list any addendums, attachments etc.
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 project will be a two year project with engineering, design and major
equipment procurement in the first year followed by construction and
commissioning the following year. The beakdown is a two year period with $12
million in 2019 and $10 million in 2020. (7/8/2021 The project will run into 2022
with a possibility of 2023. The project originally requested 22 million over two
years, CPG has only funded 20 million. When presenting the request 1 failed to
load the project during the estimating process so AFUDC and Loadings were
not added at the time of the request. These two issues have a 4 million shortfall
in project funding. During construction the underground excavation process
discovered unforeseen challenges with foundations and underground piping
that resulted in re-engineering and changes. Cost and overruns form the phase
one resulted in the Team drastically cutting scope to manage budget. Changes
included re-routing the truck area, removing the enclosed processing building,
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KF Fuel Yard Equipment Replacement
repurposing some existing equipment, redesigning the layout to eliminate an
entire conveyor and postponing replacing the final stackout conveyor.)
[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.
This project will require some short outages that will be managed within the
normal Spring outage for accommodate some conveyor transitions to the
current process and power supply connections. There may be some curtailment
needs with our contract mill to stop wood deliveries. This project will not cause
any plant reliability issues with Power Supply.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The project will run into 2022 with a possibility of 2023. The project originally
requested 22 million over two years, CPG has only funded 20 million. When
presenting the request I failed to load the project during the estimating process
so AFUDC and Loadings were not added at the time of the request. These two
issues have a 4 million shortfall in project funding. During construction the
underground excavation process discovered unforeseen challenges with
foundations and underground piping that resulted in re-engineering and
changes. Cost and overruns form the phase one resulted in the Team
drastically cutting scope to manage budget. Changes included re-routing the
truck area, removing the enclosed processing building, repurposing some
existing equipment, redesigning the layout to eliminate an entire conveyor and
postponing replacing the final stackout conveyor. The Team intentionally
stopped work with the contractor Greenberry to reevaluate the costs. The
installation was rebid to a number of contractors and a change was made with
awarding the work to Knight Construction as a lower cost.
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.
(7/8/2021 Update All of the underground work is complete minus two conveyor
foundations that will be installed after the current truck dumpers are demolished.
All major equipment is purchased and onsite minus the hammer hog and
transition chute and the #3 stack out conveyor. The fueling building is procured
and will be installed in September. The truck dumpers will be commissioned
mid July. All the critical electrical equipment has been purchased. The project
has two options for 2022 one being a complete project to the #3 conveyor and
the other a hot feed option which could see some of the equipment in Q3 of
2022 either way. If the hot feed option is selected then the remaining equipment
would become operational in 2023.)
Business Case Justification Narrative Template Version: 08/04/2020 Page 9 of 12
Staff PR_037 Attachment C 113 of 237

KF Fuel Yard Equipment Replacement
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Ketlle Falls is a renewable generating site and this project aligns with providing
reliable renewable energy to our customers. This project will increase Safety
and be good for the environment and neighbors.
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 was subjected to a rigorous evaluation of each major piece of
equipment and is documented in the WSP Feasibility Study. The project has
worked closely with the Steering Committee that is represented by GPSS,
Environmental and Power Supply. The project is being lead by GPSS Project
Manager and the Team meets regularly to discuss scope, schedule and budget.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
GPSS Thermal Operations and Maintenance Manager
Environmental
Power Supply
Contracts and Supply Chain
Plant Staff
2.8.2 Identify any related Business Cases
KF 4160 V Station Service replacement (new request in 2022)
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Thomas Dempsey - GPSS Thermal Operations and Maint Mgr
Darrell Soyars — Environmental
Scott Reid — Power Supply
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KF Fuel Yard Equipment Replacement
3.2 Provide and discuss the governance processes and people that will
provide oversight
GPSS Core team will follow the Department Project Management protocol.
There will be monthly Steering Committee meetings to discuess issues or
concerns. Updates will be shared on an as needed basis between monthly
status meetings.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Chage orders will follow Supply Chain contracting protocol based on financial
signing authority.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Kettle Falls Fuel Yard Equipment
Replacement 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: 4V POO Date: 7/8/2021
Print Name: Gre iggin
Title: Plant Manager
Role: Business Case Owner
Signature: Date: 7/9/2021
Olt
Print Name: Andy Vickers
Title: Director GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Business Case Justification Narrative Template Version: 08/04/2020 Page 11 of 12
Staff PR_037 Attachment C 115 of 237

KF Fuel Yard Equipment Replacement
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: 08/04/2020 Page 12 of 12
Staff PR_037 Attachment C 116 of 237

LED Street Lights
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 $300,000 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
1.0 Katie Snyder 5 Year Planning Draft 06/10/2022 Draft
1.1 Katie Snyder Business Narrative Update 07/25/2022 Draft
Business Case Justification Narrative Page 1 of 9
Staff PR_037 Attachment C 117 of 237

LED Street Lights
GENERAL INFORMATION
Requested Spend Amount $300,000
Requested Spend Time Period 1 Year
Requesting Organization/Department Electric Operations
Business Case Owner I Sponsor Katie Snyder I David Howell
Sponsor Organization/Department Operations
Phase Execution
Category Program
Driver Asset Condition
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.
Business Case Justification Narrative Page 2 of 9
Staff PR_037 Attachment C 118 of 237

LED Street Lights
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
Quantities Ratio
I641 1% ' 84
Business Case Justification Narrative Page 3 of 9
Staff PR_037 Attachment C 119 of 237

LED Street Lights
Lamp 7,930 15% 7
photocell 711111 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 I Complete
RECOMMENDED: Base Case (current practice of $300,000 Ongoing program
replacing burned-out HPS bulbs or replacing a
fixture if broken)
ALT#1: Optimized Case (planned replacement of $1.67M 1/1/2015 Ongoing -
HPS bulbs and photocells) 15-year
cycle
replacement
ALT#2: LED Case (change-out all fixtures to $2.32M 1/1/2022 5- or 10-
LED) 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 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.
Business Case Justification Narrative Page 4 of 9
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LED Street Lights
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
Initial Population Initial Population Mean Time to Failure
.. , ,
Year— Year— population will have
failed by_Years)
00 , 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
ComponentInitial Population Initial Population Mean Time to Failure
,
populationYear— Year—
Photocellfailed by_Years)
New Style 10.2
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 replaces LED lights upon failure (burn-out). Funding
calculations are based on historical spend (2020 spend was approx. $411,000). We
anticipate as more bulbs are replaced due to failure, there will be less spend each year.
Business Case Justification Narrative Page 5 of 9
Staff PR_037 Attachment C 121 of 237

LED Street Lights
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.
Business Case Justification Narrative Page 6 of 9
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LED Street Lights
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
projects are 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 Operations Roundtable(ORT)acts as the advisory group for the LED Change Out Program.
Business Case Justification Narrative Page 7 of 9
Staff PR_037 Attachment C 123 of 237

LED Street Lights
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.
Business Case Justification Narrative Page 8 of 9
Staff PR_037 Attachment C 124 of 237

LED Street Lights
Signature: &�-� 77��- Date: 07/25/2022
Print Name: Katie Snyder
Title: Asset Maintenance Business Analyst
Role: Business Case Owner
Signature: Z�)a4lr Date: 7/28/2022
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
Business Case Justification Narrative Page 9 of 9
Staff PR_037 Attachment C 125 of 237

DocuSign Envelope ID:025A8842-7B30-40A7-9407-ACB882B2C969
Long Lake Stability Enhancement
EXECUTIVE SUMMARY
PROJECT NEED: The major driver for this business case is regulatory. FERC (Federal
Energy Regulatory Commission) requested analysis revealed that Long Lake dam does
not meet the internal plane stability minimum safety factor during a PMF (probably
maximum flood) event. Avista submitted a preliminary study to the FERC and is waiting
for final design before sending the FERC the full scope of the project and timeline to
address mitigation. Avista is also revising the Spokane River PMF and performing a site-
specific seismic hazard assessment to fully understand the loadings at the facility. The
PMF has been recently approved and approval of the seismic loads are anticipated by
mid-2023. The results of the detailed 3D modeling of the facility are anticipated to reduce
the necessary mitigation efforts to satisfy FERC stability criteria. The FERC expects
Avista to develop a mitigation plan to address the stability issues once modeling is
complete and therefore this project is mandatory. If this project does not move forward,
Avista's relationship with the FERC will be heavily damaged and costly operational
changes or even fines will result.
RECOMMENDED SOLUTION: The recommended solution will be heavily informed by
the Engineering efforts dating back to 2016, however, recent discoveries have narrowed
the remediation efforts to the following Alternatives listed below.
ALTERNATIVES CONSIDERED (as of 2023):
Up to 5 different construction items may be needed for Long Lake Dam based on the
ongoing engineering efforts. The path forward includes additional engineering (PCA &
FEA of the dam and left abutment), design, FERC approvals, and construction. The
expected possible alternatives include:
• Waterstop installation for Long Lake Dam
• Spillway pier repair (strengthening/ the concrete added in 1918 and 1930)
• Spillway pier stabilization (anchoring and/or new deck)
• Left abutment rock wedge stabilization
• Intake dam stabilization (anchors)
ALTERNATIVES CONSIDERED:
A high-level construction feasibility study was conducted prior to embarking on the 3D
Finite Element Modeling stage and was refined by a third-party industry expert in dam
stability and anchoring, and heavy civil construction Engineering Solutions. It was
estimated that the construction could be done in one year but more realistically should
be done over two years
• Alternative 1: Initial Anchor Design, Two Season Construction schedule (initial
estimate of $18.52M)
• Alternative 2: Initial Anchor Design, One Season Construction schedule (initial
estimate of $18.65M)
• Alternative 3: New Design, Anchors, Drains and Grouting (initial estimate of
$17.35M)
Business Case Justification Narrative Template Version: January 2023 Page 1 of 10
Staff PR_037 Attachment C 126 of 237

DocuSign Envelope ID:025A8842-7B30-40A7-9407-ACB882B2C969
Long Lake Stability Enhancement
COST OF RECOMMENDED SOLUTION: Total project costs have an overall estimate at
complete cost of $41.6M (2023 estimate).
ADDITIONAL INFO: Not completing the Stability Enhancement Project will place Avista
out of compliance with our FERC License Requirements. FERC can require operational
changes or additional, costly risk reduction measures, up to and including the loss of
power generation at Long Lake. If work is not performed this has cost and operational
repercussions which could affect our customers in terms of cost, reliability of energy, and
reputational damage. performed this has cost and operational repercussions which could
affect our customers in terms of cost, reliability of energy, and reputational damage.
Business Case Justification Narrative Template Version: January 2023 Page 2 of 10
Staff PR_037 Attachment C 127 of 237

DocuSign Envelope ID:025A8842-7B30-40A7-9407-ACB882B2C969
Long Lake Stability Enhancement
VERSION HISTORY
Version Author Description Date Notes
1.0 PJ Henscheid Format existing BC into exec 7.6.20
summary
2.0 Michael Truex/ Completion of full BCJN 7.31.20
PJ Henscheid document
Updated to 2022 template and
3.0 PJ Henscheid modified budget to align with 8.24.22
im roved estimates
No substantive
4.0 Jessica Bean Transfer to new BCJN Template 01/06/2023 changes/edits have been
made to the business
case through this transfer
Wendy Updated to reflect current state
5.0 Iris/Brandon of project and engineering 5/10/2023
Little/PJ efforts— revealing some new
Henscheid remediation needs
BCRT Team Has been reviewed by BCRT
BCRT Member and meets necessary
requirements
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2024 $ 1,600,000 0
2025 $ 1,400,000 0
2026 $ 1,000,000 0
2027 $ 12,500,000 $20,000,000
2028 $ 16,100,000 $21,000,000
Project Life Span 13 years (2016-2028)
Requesting Organization/Department GPSS
Business Case Owner I Sponsor PJ Henscheid Alexis Alexander
Sponsor Organization/Department GPSS
Phase Execution
Category Mandatory
Driver Mandatory& Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's
site see link.
Investment Drivers
Business Case Justification Narrative Template Version:January 2023 Page 3 of 10
Staff_PR_037 Attachment C 128 of 237

DocuSign Envelope ID:025A8842-7B30-40A7-9407-ACB882B2C969
Long Lake Stability Enhancement
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?
Long Lake dam does not meet the internal plane stability minimum safety factor
during a PMF event. Also, Avista believes a large portion of water seepage in
the concrete is related to deteriorated water stops installed along the vertical
construction joints during the original construction.
1.2 Discuss the major drivers of the business case
The major driver for this business case is Regulatory/ Mandatory & Compliance.
Avista is subject to multiple Federal, State and Local environmental regulatory
programs. Avista is required by FERC to maintain facilities for generation and
public safety. The FERC license for Long Lake HED includes several
operational requirements that depend on reliable operation of the generation
units as well as the intakes and spill gates.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
Not completing the Stability Enhancement Project will place Avista out of
compliance with our FERC License Requirements. FERC can require
operational changes or additional, costly risk reduction measures, up to and
including the loss of power generation at Long Lake.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link. Avista Strategic Goals
This project touches upon the value that Avista is trustworthy. Executing this
project allows Avista to take care or our assets—assets that are vital to providing
our cusomters with reliable energy, safely.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
See Section 2.2
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: January 2023 Page 4 of 10
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DocuSign Envelope ID:025A8842-7B30-40A7-9407-ACB882B2C969
Long Lake Stability Enhancement
2. PROPOSAL AND RECOMMENDED SOLUTION- Describe the proposed
solution to the business problem identified above and why this is the best and/or least cost
alternative (e.g., cost benefit analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Recommended Solution: A final recommendation is pending final
engineering design. The recommended solution will be heavily informed by the
Engineering efforts dating back to 2016, however, recent discoveries have
narrowed the remediation efforts to the following Alternatives listed below.
ALTERNATIVES CONSIDERED (2023): Up to 5 different construction items
may be needed for Long Lake Dam based on the ongoing engineering efforts.
The path forward includes additional engineering (Pier Condition Assessment
& Finite Element Analysis of the dam and left abutment), design, FERC
approvals, and construction. The expected possible alternatives include:
Waterstop installation for Long Lake Dam Spillway pier repair (strengthening/
the concrete added in 1918 and 1930) Spillway pier stabilization (anchoring
and/or new deck) Left abutment rock wedge stabilization Intake dam
stabilization (anchors)
In Scope: A final recommendation is pending final engineering design.
Out of Scope: A final recommendation is pending final engineering design.
Assumptions: A final recommendation is pending final engineering design.
The above alternatives have recently been presented to the project team;
however, there is still active engineering work going on to determine the 3D
effects of the facility and the seismic requirements at the location. Dam Safety
is monitoring movement, uplift pressures, and deflection of the intake and
spillway dam. The project team recently completed (February 2023) boring and
drilling and is completing laboratory testing to aid the assessment of the
structural integrity of the concrete piers. Once those variables are determined,
these alternatives will be re-evaluated, and the capital investment costs will be
re-analyzed.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
• Alden Report
• Avista's Dam Safety Surveillance Plans and Reports
• Finite Element Analysis
Business Case Justification Narrative Template Version: January 2023 Page 5 of 10
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DocuSign Envelope ID:025A8842-7B30-40A7-9407-ACB882B2C969
Long Lake Stability Enhancement
• The initial design work, value engineering, and constructability reviews, as
well as industry studies, reports, and information gleaned from Avista's peer
dam owners have all contributed to the development of the business case.
• Risk Cost calculation from GPSS Asset Management Group: Risk cost is the
product of the Failure Rate, Potential Consequence of failure, and the
Probability of experiencing the potential consequence in the event of a
failure. This risk cost is associated with the probable dollar value associated
with Avista's exposure risk of each component. This exposure risk includes
the cost of anything that threatens the company, including costs associated
with a probable failure of the components (potentially including replacement,
refurbishment, or lost generation costs), safety risks associated with normal
operation or replacement actions, and probable environmental risks
associated with the asset, and at times other costs such as public perception
risk mitigation activities. While the company may not be able to shelter itself
from risk completely, there are ways it can help protect itself from the effects
of business risk, primarily by adopting a risk management strategy as a part
of the asset management program. Risk costs not only take account for the
exposure risk for an asset but also the criticality (or importance of an asset)
and its' current condition. Risk costs are somewhat analogous to insurance
premiums. They represent an annual cost, but the year-to-year costs vary
with the condition of the assets. If we total the risk costs for all of our assets
for the next year, the company would need to have monies set aside for that
year to cover the costs associated with the assets that fail that year.
Annual Risk Cost
= [Probability of Failure (that year)] x [Consequence $]
x [Likelhood of actually experiencing that consequence]
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital N/A $0 $0 $0 $0 $0
O&M N/A $0 $0 $0 $0 $0
Since this project is driven by regulatory efforts there are no known offsets.
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
s Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: January 2023 Page 6 of 10
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DocuSign Envelope ID:025A8842-7B30-40A7-9407-ACB882B2C969
Long Lake Stability Enhancement
Offsets Offset Description 2024 2025 2026 2027 2028
Capital N/A $0 $0 $0 $0 $0
O&M N/A $0 $0 $0 $0 $0
Since this project is driven by regulatory efforts there are no known offsets.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
RECOMMENDED ALTERNATIVE: A final recommendation is pending final
engineering design. However, the initial design work considers some high level
mitigation solutions, including adding post-tension anchors into bedrock, adding
pressure relief drains, and adding mass concrete to the dam structure itself.
These options, or a combination thereof, can bring the dams into FERC stability
compliance.
The recommended solution will be heavily informed by the Engineering efforts
dating back to 2016, however, recent discoveries have narrowed the
remediation efforts to the following Alternatives listed below. ALTERNATIVES
CONSIDERED (2023): Up to 5 different construction items may be needed for
Long Lake Dam based on the ongoing engineering efforts. The path forward
includes additional engineering (Pier Condition Assessment & Finite Element
Analysis of the dam and left abutment), design, FERC approvals, and
construction. The expected possible alternatives include: Waterstop installation
for Long Lake Dam Spillway pier repair (strengthening/ the concrete added in
1918 and 1930) Spillway pier stabilization (anchoring and/or new deck) Left
abutment rock wedge stabilization Intake dam stabilization (anchors)
The above alternatives have recently been presented to the project team;
however, there is still active engineering work going on to determine the 3D
effects of the facility and the seismic requirements at the location. Dam Safety
is monitoring movement, uplift pressures, and deflection of the intake and
spillway dam.
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DocuSign Envelope ID:025A8842-7B30-40A7-9407-ACB882B2C969
Long Lake Stability Enhancement
The project team recently completed (February 2023) boring and drilling and is
completing laboratory testing to aid the assessment of the structural integrity of
the concrete piers. Once those variables are determined, these alternatives will
be re-evaluated, and the capital investment costs will be re-analyzed.
Alternative 1: Initial Anchor Design, Two Season Construction schedule;
$18.52M
This alternative was based upon an initial engineering analysis and therefore
required many anchors. It was not selected, with thoughts that a more detailed
engineering model would require a reduced number of anchors.
Alternative 2: Initial Anchor Design, One Season Construction schedule;
$18.65M
nis alternative was based upon an initial engineering analysis and therefore
required many anchors. The construction schedule was revised to be one
season to attempt to provide savings. It was not selected, with thoughts that a
more detailed engineering model would require a reduced number of anchors.
Alternative 3: New Design, Anchors, Drains and Grouting; $17.35M
The engineering efforts are still in process. But those efforts are revealing other
stability issues that will need to be addressed. The number of anchors may
decrease but there is a possibility that additional work is needed to stabilize the
Piers, Spillway, Intake and left abutment. This alternative is not a complete
solution therefore not selected.
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
Initial stability studies revealed that Long Lake dam does not meet FERC
stability criteria during PMF and Post-Earthquake loading conditions. Success
of the project requires design and delivery of stability measures to bring the
spillway and intake dams into compliance with FERC stability requirements.
Stability measures justified through a value engineering analysis, satisfying
FERC factors of safety for stability, and properly constructed per plans and
specification would be considered a success.
The initial design work considers some high-level mitigation solutions, including
adding post-tension anchors into bedrock, adding pressure relief drains, and
adding mass concrete to the dam structure itself. These options, or a
combination thereof, can bring the dams into FERC stability compliance. No
other solutions are known to exist for stabilizing the dam.
Finalizing the design parameters and establishing a more defined budget will be
essential in the success of project delivery and capital budget forecasting. To
assist in delivering the project on time and within our budget parameters, we will
be looking for an alternative progressive project delivery method.
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DocuSign Envelope ID:025A8842-7B30-40A7-9407-ACB882B2C969
Long Lake Stability Enhancement
2.7 Include a timeline of when this work is scheduled to commence and
complete, if known.
❑x Timeline is Known
• Start Date: 2016
• End Date: 2028
❑Timeline is Unknown
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of
the business case, and how such oversight will occur.
Steering Committee/Governance Team
• Jacob Reidt — Sr Manager Project Delivery
• Greg Wiggins — Sr Manager of Hydro Ops & Maintenance
• Meghan Lunney — Spokane River License Manager
Oversight Process
Management of this project will include the creation of a Steering Committee
which will include managers representing the key stakeholders involved in this
project. The steering committee will make impactful financial, schedule, or risk
decisions related to project activities.
The project will also be executed by a formal Project Team lead by the Project
Manager. Regularly cadenced steering committee meetings as well as monthly
project reports with cost metrics assist in transparency and oversight.
Decisions, periodization efforts, and change requests will be tracked by the
Project Manager for the project for the duration of project activities. These
efforts will be entered into in conjunction with the project team and the steering
committee members.
Business Case Justification Narrative Template Version: January 2023 Page 9 of 10
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DocuSign Envelope ID:025A8842-7B30-40A7-9407-ACB882B2C969
Long Lake Stability Enhancement
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Long Lake Stability
Enhancement business case and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.
DocuSigned by:
Signature: E
li(,�tat,�, 1-ha)" Date: AUg-08-2023 1 11:06 AM PDT
— 30401E01AC 1543C...
Print Name: Michael Truex
Title: GPSS Manager of Project
Management
Role: Business Case Owner
DocuSigned by:
Signature: 5FA27BABA767F467
a(t-�-AU .W Date: Aug-26-2023 1 1:34 AM PDT
...
Print Name: Alexis Alexander
Title: Director, GPSS
Role: Business Case Sponsor
Signature: NA Date:
Print Name: NA; Alexis Alexander is on the
steering committee for this project.
Title: NA
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: January 2023 Page 10 of 10
Staff PR_037 Attachment C 135 of 237

Monroe St Abandoned Penstock Stabilization
EXECUTIVE SUMMARY
The Monroe Street Powerhouse was initially constructed in 1890 and has undergone
several modernizations over the last 129 years. During the 1972 modernization, three of
the original penstock intakes were plugged with concrete and sealed with a layer of shot-
crete. The three 10 ft. diameter steel penstocks were only partially removed, leaving an
approximate 250 ft. length of each buried under what is now Huntington Park. It is
unknown if the penstocks were also backfilled with material, posing a risk of implosion.
These penstocks run underneath parts of the access road, crane staging area, and
walking path through the park. The park is open to the public, and the access road and
crane areas are critical to maintaining the safe and efficient operation of the Monroe Street
Hydroelectric Development. During the 2018 Maintenance Assessment, these penstocks
were identified as a high risk due to their location, unknown condition, and observed
groundwater.
The recommended solution includes further investigation of the intake dam and penstocks
to better quantify the risk, and implementation a plan to mitigate those risks. The scope
of this work would likely include an initial engineering evaluation, including investigatory
drilling, with stabilization efforts likely to include grouting of the intake and penstock.
The estimated cost of the project is $760,000. The service code for this program is
Electric Direct and the jurisdiction for the project is Allocated North serving our electric
customers in Washington and Idaho. Operating Monroe Street safely and reliably
provides our customers with low cost, reliable power while ensuring the region has the
resources it needs for the Bulk Electric System (BES).
VERSION HISTORY
Version Author Description Date Notes
Draft Ryan Bean Initial draft of original business case 6/21/2019
1.0 Ran Bean Updated Approval Status 7/2/2019 Full amount approved
2.0 Ryan Bean 5 Year Planning 2020 & New Form 7/8/2020
3.0 Ryan Bean 2022 Annual Refresh 8/18/2022 Reclassified Drilling
costs to 00
Business Case Justification Narrative Page 1 of 8
Staff PR_037 Attachment C 136 of 237

Monroe St Abandoned Penstock Stabilization
GENERAL INFORMATION
Requested Spend Amount $760 000
Requested Spend Time Period 2 years
Requesting Organization/Department C07/GPSS
Business Case Owner I Sponsor Ryan Bean I Alexis Alexander
Sponsor Organization/Department C07/GPSS
Phase Initiation
Category Project
Driver Failed Plant& Operations
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The Monroe Street Powerhouse was initially constructed in 1890 and has
undergone several modernizations over the last 129 years. During the 1972
modernization, a new turbine intake and penstock arrangement was installed,
just prior to Expo '74. During this upgrade, three of the original penstock intakes
were plugged with concrete and sealed with a layer of shot-crete. The three 10
ft. diameter steel penstocks were only partially removed, leaving an approximate
250 ft. length of each buried on site. It is unknown if the penstocks were
backfilled with material, posing a risk of implosion. The penstocks are located
under what is now Huntington Park and run underneath parts of the access road,
crane staging area, and walking path through the park.
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 this business case is Failed Plant. The original penstocks are no
longer functional and pose a risk to the continued operation of the park and the
power plant. Monroe Street supplies year-round base load hydroelectric power
to Avista's portfolio. Continuing to operate Monroe Street safely and reliably
provides our customers with low cost, reliable power while ensuring the region
has the resources it needs for the Bulk Electric System (BES).
Business Case Justification Narrative Page 2 of 8
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Monroe St Abandoned Penstock Stabilization
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The penstocks are located under what is now Huntington Park and run
underneath parts of the access road, crane staging area, and walking path
through the park. The park is open to the public, and the access road and crane
areas are critical to maintaining the safe and efficient operation of the Monroe
Street Hydroelectric Development. During the 2018 Maintenance Assessment,
these penstocks were identified as a high risk due to their location, unknown
condition, and observed groundwater. Due to the unknown condition of these
penstocks, there is a risk of implosion of the abandoned penstocks due to
deterioration, potentially resulting in an uncontrolled release of water thereby
jeopardizing the plant and the park.
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 investment would field effort in two phases. The first phase would consist
of an investigation of the penstocks and original intake dam to determine the
condition. The second phase would implement corrective actions to eliminate
the risk from implosion and ensure the intake structure is watertight and fit for
continued service. The measure of success would be the stabilization of the
above components resulting in the mitigation of risk to the public and continued
production at the plant.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the
problem.
See project documentation from 2016 storm water controls and
investigation.
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 metric supporting the stabilization of the current system is that it is no
longer useful and poses a risk to continued operation of the park and plant.
During the 2018 Maintenance Assessment, these penstocks were
Business Case Justification Narrative Page 3 of 8
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Monroe St Abandoned Penstock Stabilization
identified as a high risk due to their location, unknown condition, and
observed groundwater.
GroupAsset 'MM
3
59 Abancloned Penstocks 0.00
i Dam Concrete - Original Intake 1.2
64 Penstock Plugs
Dam Concrete - Seawall/ Retaining Wall 1.21
Option Capital Cost Start Complete
Investigate to ascertain condition; and $760,000 01 2022 122023
mitigate leakage or instability if needed.
Continue to operate at risk. $0 01 2021
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The failure of the system and risk to the plant is the primary metric for justification
of the project. A significant increase in ground water was observed in
Huntington Park in 2007 when groundwater was observed to be traveling
through the 13.8 kV underground electric vault and into the powerhouse,
requiring remediation at the electric vault. Since 2007, excessive groundwater
persisted to leak into the powerhouse through cracks in the concrete, and
underground conduit penetrations, requiring constant monitoring and controls to
be installed to manage the water. In 2015 excessive groundwater was observed
to be flooding portions of Huntington Park, requiring areas of the park to be
restricted for use. The flooding in Huntington Park increased by a magnitude
again in 2016, requiring additional storm water controls and investigation into
the source which was determined to be strongly associated with the buried
penstocks, validating the drawings indicating the presence of the buried
penstocks and associated infrastructure.
Business Case Justification Narrative Page 4 of 8
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Monroe St Abandoned Penstock Stabilization
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 capital cost will be spread out over two years. The first year will be primarily
engineering, investigatory drilling, and determination of needed remediation.
This is estimated to be $150,000 and primarily O&M. The second year will
include contractor mobilization and execution of the remediation plan. This is
estimated to be $750,000. This will not offset significant O&M charges because
the equipment is no longer in service, so it is no longer maintained.
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 execution of this project will temporarily inhibit access to the park and power
plant due to investigatory and remediation efforts. The outcome of this project
will also answer questions about loading of the access road that would impact
future rehabs of the plant.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Continue to Operate at risk.: The level of risk is unknown due to the condition
of the penstocks being unknown. However, the risk is likely to increase over
time due to deterioration of the penstocks and the presence of groundwater in
the park. Given the risk to the public, plant operations, and the company's
reputation; doing nothing is not advisable.
Investigate and Remediate: This alternative includes further investigation of the
intake dam and penstocks to better quantify the risk, and implementation a plan
to mitigate those risks. The approach to fix is likely to involve grouting for
penstock and intake stabilization, as well as measures for additional water
management and monitoring. This alternative would provide a lasting solution
to the above concerns and prevent future issues with access and safety.
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 project is expected to take two years. The effort in the first year will be
devoted investigation and design. The effort in the second year will consist of
Business Case Justification Narrative Page 5 of 8
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Monroe St Abandoned Penstock Stabilization
execution of a remediation plan. The transfer to plant will be at the end of the
second year with the completion of the work.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Operating Monroe Street safely and reliably provides our customers with low
cost, reliable power while ensuring the region has the resources it needs for the
Bulk Electric System (BES). By taking care of this plant we support our mission
of improving our customer's lives through innovative energy solutions which
includes hydroelectric generation. By executing this project, we ensure that
Monroe Street will continue to provide reliable service and mitigate risk to the
park and Avista's reputation.
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 impacts due to an implosion could harm Avista employees, the public,
continued generation from the powerhouse, and Avista's reputation.
A formal Project Manager will be assigned to a project of this size. The project
will be managed within project management practices adopted by the
Generation Production and Substation Support (GPSS) department. This
includes the creation of a Steering Committee and a formal Project Team. Once
the project is initiated, reporting on scope, schedule and cost will occur monthly.
Changes in scope, schedule, or cost will be surfaced by the Project Manager to
the Steering Committee for governance. The Project Manager will manage the
project through its conclusion.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
The primary stakeholders for this project are, the Hydro Regional Manager
on the Upper Spokane, the Upper Spokane plant personnel, GPSS
Engineering, Environmental Resources, the City of Spokane and Parks.
Other stakeholders may be identified during project initiation.
2.8.2 Identify any related Business Cases
This project will need to be completed prior to any substantial rehab at the
Monroe Street power plant, however this is not anticipated to be needed
for some time.
Business Case Justification Narrative Page 6 of 8
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Monroe St Abandoned Penstock Stabilization
3.1 Steering Committee or Advisory Group Information
A formal Project Manager will be assigned to a project of this size. The project
will be managed within project management practices adopted by the
Generation Production and Substation Support (GPSS) department. A Steering
Committee will be formed for this project. The Project Manager will manage the
project through its conclusion.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Management of this project will include the creation of a Steering Committee
which will include managers representing the key stakeholders involved in this
project. The project will also be executed by a formal Project Team lead by the
Project Manager.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Once the project is initiated, reporting on scope, schedule and cost will occur
monthly. Changes in scope, schedule, or cost will be surfaced by the Project
Manager to the Steering Committee for governance.
Business Case Justification Narrative Page 7 of 8
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Monroe St Abandoned Penstock Stabilization
The undersigned acknowledge they have reviewed the Monroe Street
Abandoned Penstock Stabilization 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.
g Ryan Bean Digitally signed by Ryan Bean Date:
Signature: Date:2022.08.3111:03:31
-07'00'
Print Name: Ryan Bean
Title: Plant Manager, Upper Spokane
Role: Business Case Owner
Digitally signed by Alexis
Signature: Alexis Alexander nder
pate 2022.09.02 16:16:26-07'00' Date:
Print Name:
Title:
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Template Version: 05/28/2020
Business Case Justification Narrative Page 8 of 8
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Nine Mile Battery Building
EXECUTIVE SUMMARY
The purpose of this project is to build a battery storage building for the batteries supplying
the Nine Mile Falls HED's critical power system to improve reliability and safety. The
battery room will be located near the switchyard and underground conduit will be installed
to the powerhouse containing power and control cables. During emergency situations,
the critical power system is required to continually monitor and control the turbine
generators and spillway for safe operations of the river and its flow. The 125 VDC battery
banks are the most essential component of the critical power system and the health of
the batteries needs to be closely monitored. The existing location batteries on the
switchgear floor is susceptible to extreme temperatures that greatly reduce the reliability
and performance of the system. The location of the batteries is a safety issue, because
they contain hazardous material and expel potentially explosive hydrogen gases during
discharge. In addition to the reliability and safety concerns, the structural integrity of the
existing floor needs to be reinforced as equipment is added or replaced. A new building
with climate control and hydrogen monitoring dedicated to battery storage will greatly
enhance the critical power system reliability and eliminate unnecessary safety hazards.
The initial design of the powerhouse has begun as part of the Generation DC Supplied
Upgrade program, but the estimated costs are too high to be funded through the program.
Therefore, a separate business case is required to complete the design and construction
by the end of 2022 before major overhauls to the Units 3 and 4 begin.
VERSION HISTORY
Version Author Description Date Notes
1.0 Terri Echegoyen Original submission June 2021
Jeremy Winkle
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Nine Mile Battery Building
GENERAL INFORMATION
Requested Spend Amount $800,000
Requested Spend Time Period 1 year-2022
Requesting Organization/Department GPSS
Business Case Owner I Sponsor Jeremy Winkle I Andy Vickers
Sponsor Organization/Department GPSS
Phase Planning
Category Project
Driver Asset Condition
1 . BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
There are a number of issues with the existing location of the batteries in the Nine Mile
HED powerhouse including:
• Excessive battery temperature — The batteries are open to the
switchgear floor and not enclosed in a climate controlled room.
Temperatures above 78 degrees Fahrenheit significantly reduces the
usable life and performance of the batteries.
• Hydrogen danger - Batteries emit hydrogen gassing which is extremely
explosive in a concentrated area. The existing location of the batteries
does not meet current safety standards to monitor and expel potentially
explosive hydrogen gases.
• Switchgear floor loading concerns - The existing location of the batteries
on the switchgear floor may not be strong enough to safely store new
batteries and equipment. During the Units 1 and 2 upgrade, the portions
of the switchgear floor had to be strengthened prior to installing new
equipment. A thorough structural analysis would need to be completed
before installing new critical power equipment in the existing location.
• Battery transportation safety - Batteries contain corrosive acid and great
care must be taken when installing and maintaining lead acid batteries.
The existing location requires transporting battery up and down multiple
levels of the powerhouse and creates safety hazard for electricians and
plant personnel.
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Nine Mile Battery Building
1.2 Discuss the major drivers of the business case and the benefits to the
customer.
During a utility power failure, the Nine Mile Falls HED facility's critical power
system supplies emergency DC power to protect plant equipment and
personnel and AC power to control and monitor the generators and auxiliary
systems
These systems allow plant operations, during emergency situations, to
continue to monitor and control the turbine generators and spillway for safe
operations of the river and its flow. Failure of this system during an emergency
situation could result in compromised safe operations, cause equipment failure
and extended outages. A reliable and safely maintained critical power system
benefits the customer by ensuring reliable operations and public safety during
an emergency situation.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The battery banks are currently located in areas not designed for the storage or
operation of batteries, both because of the climate and the floor system. Battery
operation and life are hindered by being stored in a location whose temperatures
are outside of the recommended range. As isolated systems, when one system
experiences a component failure, the remaining battery banks do not have the
ability to support the plant. The batteries have an expected life span of 20 years.
Excessive temperature above 78 degrees greatly reduces the expected life
span of the batteries and hinders performance. Construction of a dedicated
battery building similar to that constructed at Cabinet Gorge HED will provide an
enclosed space thereby allowing for necessary climate control, monitoring and
safe operations.
If this program is not funded or deferred, there will be increasingly negative
impacts to the critical power system and continued safety concerns. As the
batteries are exposed to high temperatures, their expected lifetime decreases
and requires replacement before failure. Emergent replacement of the batteries
may cause unplanned outages and strain resources to procure and install new
batteries. Since the integrity of the floor is questionable, a detailed analysis and
possible improvement would need to be complete before installing new batteries
delaying the installation. It would be very likely, the plant would need to operate
on a temporary battery system with limited capacity for an extended period of
time before replacement negatively impacting operational reliability. The safety
concerns associated with hazardous materials, hydrogen gassing, and
structural integrity would continue to exist and expose plant personnel to
dangers. Funding this business case will eliminate the operational and safety
concerns associated with location of the batteries.
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Nine Mile Battery Building
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.
Success will be measured through consistent monitoring of the batteries and
their environment. In the event of an emergency, the batteries would perform as
expected. Load tests would indicate that the expected life span of the batteries
is consistent with manufactures specifications.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
• Battery Temperature Data - Temperature monitoring in 2012 confirmed
prolong temperature near or above 85 degrees Fahrenheit.
Nine Mile HED
90
PM It -
85
a gp —
E
]5
)0
65
7/10/20120 0 7/30/20120:00 8/19/2012 R00 9f8/2.2- 9/2.-20:00
R.rar
Figure 1-2012 Battery Temperature Monitoring
• Switchgear temperatures are monitored on the PI Historian system.
During the late June 2021 heat wave, temperature in the powerhouse
reached over 100 degrees Fahrenheit on multiple days. Daily
operational logs taken in the morning matched PI Historian temperature
of greater than 85 degrees Fahrenheit.
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
2. PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Cost Start Complete
Business Case Justification Narrative Template Version: 08/04/2020 Page 4 of 9
Staff PR_037 Attachment C 147 of 237

Nine Mile Battery Building
[Recommended Solution] Dedicated Battery $800,000 01/2022 12/2022
Building
[Alternative #1] Enclose batteries in existing $950,000 01/2022 12/2022
location
[Alternative #2] Relocate batteries to plant $800,000 01/2022 12/2022
basement
The recommend solution is to construct a dedicated battery building near the
switchyard. This is the safest solution, because the hazards associated with
batteries will no longer be locates in the plant powerhouse.
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
Analysis of the various options took into consideration overall cost, performance
projections, ergonomic conditions, heat dissipation, hydrogen dissipation and
safety considerations. See attached document for details regarding alternative
methods analysis.
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.
Project engineering will continue through 2021. A project within the Generation
DC Supplied System Update program already exists (20505079) and will
support this work in 2021 with the goal being to solidify designs to be
implemented in 2022.
The outcome of this investment is not expected to increase O&M costs. The
investment will reduce O&M costs for battery maintenance costs. The new
building will greatly reduce the risk of replacing one or multiple batteries.
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 negative safety impacts associated with the current locations of the
batteries on plant operations will be eliminated after the successful
implementation of this business case. The major safety hazards will be isolated
to the dedicated battery room which will be closely monitored and only
accessible to necessary personnel. The impact to the operation team will be
very positive.
The project will significantly benefit the crew performing battery maintenance.
The new battery room will be in a very accessible location to reduce
maintenance time. The room will be designed ergonomically to reduce the
impact on personnel maintaining and replacing batteries.
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Staff PR_037 Attachment C 148 of 237

Nine Mile Battery Building
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Alternatives #1 and #2 were eliminated as acceptable solution, because the
batteries would still be located in the powerhouse and require disruptive
construction in the powerhouse. These solutions would require extended time
on temporary critical power. Most importantly, these solutions do not solve the
safety risk specifically maintaining the batteries in the powerhouse.
Please see the attached document for additional alternatives analysis
information.
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.
• •
•
Continued
• • Construction • •
awardEngineering contract •• days to 120
days)
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
At Avista, our Mission is to improve our customers' lives through innovative
energy solutions — safely, responsibly and affordably. This project will improve
battery safety and provide continuous operation in the event of an emergency
at Nine Mile Falls HED.
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 health of the critical power system is vital to plant operations and safety.
Proper battery storage in a temperature controlled environment greatly reduces
the risk of battery failure. Additionally, moving the batteries outside the
powerhouse reduces the safety risk to plant personnel and potential damage to
batteries due to other plant operations.
During project design, construction, and commissioning, the project will be
continually evaluated to ensure the goals of the project are being met. Remote
room temperature, battery condition and hydrogen monitoring will be utilized to
verify the temperature control of the environment. Access to the building will be
limited to essential personnel to limit and minimize any safety risks to personnel
and equipment. Battery discharge testing and subsequent recharging will also
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Staff PR_037 Attachment C 149 of 237

Nine Mile Battery Building
evaluate the performance of the system prior to project completion and
periodically throughout the life the system.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
• GPSS Project Delivery (engineering and project management)
• Spokane River Plant Operations
• Battery Maintenance and Testing
• Spokane River Permitting and Environmental
• Supply Chain (contracts management)
• Power Supply
• Hydro Compliance
2.8.2 Identify any related Business Cases
N/A
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Steering committee members consist of the Manager of Hydro Operations &
Maintenance, the Manager of Spokane River Hydro Operations and the
Manager of Controls & Electrical Engineering. The Battery Maintenance &
Testing team will serve as an Advisory Group for this project.
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Nine Mile Battery Building
3.2 Provide and discuss the governance processes and people that will
provide oversight
This project will be governed by the methods described in the GPSS PM
Process Flow document. Governance tasks will include monthly project reports,
quarterly project updates, business case updates, the monthly monitoring of
project costs and schedule, tracking changes, monitoring risks and issues,
communications including project meetings and stakeholder communication.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The creation and utilization of a Risk Registry will provide for the identification
of risks and their analysis. In the event changes are needed, documentation will
be presented to the steering committee who is solely authorized to approve said
changes.
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Nine Mile Battery Building
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Nine Mile Falls HED Battery Room
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: 7/7/2021
Print Name: Jeremy Winkle
Title: Controls/Electrical
Engineering Manager
Role: Business Case Owner
Signature: Date: 7/12/2021
Print Name: Andy Vickers
Title: Director of GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
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Nine Mile Powerhouse Crane Rehab
EXECUTIVE SUMMARY
The Nine Mile Falls Generator Bay and Access Bay bridge cranes were replaced in 1993
prior to the Units 3 and 4 replacement project. Both cranes are Kone brand 35ton cranes
with service class for both cranes being H1 — light duty. The Nine Mile powerhouse
cranes are now beyond their useful life. Their duty cycle is too low to support continuous
work during future unit overhauls with both replacement controls and mechanical parts
no longer supported by the manufacturer and must be custom fabricated. The Generator
floor crane trolley is now out of service, limiting Avista's capability to respond to a turbine
generator failure. During the 2018 Maintenance Assessment, the cranes were identified
as high risk due to their current condition.
The recommended solution includes replacement of each crane's hoist and trolley system
and installing a modern hoist and trolley. This approach is a modern in-kind replacement
of the current powerhouse cranes and would provide a lasting solution to meet current
and future crane demands.
The estimated cost of the project is $1,500,000 in order to rehabilitate both bridge cranes.
The service code for this program is Electric Direct and the jurisdiction for the project is
Allocated North serving our electric customers in Washington and Idaho. Operating Nine
Mile safely and reliably provides our customers with low cost, reliable power while
ensuring the region has the resources it needs for the Bulk Electric System (BES).
VERSION HISTORY
Version Author Description Date Notes
Draft Ryan Bean Initial draft ofo ' inalbusiness case 7/1/2019
1.0 Ryan Bean Updated Approval Status 7/2/2019 Full amount approved
2.0 Ryan Bean BCFCR Submitted 5/6/2020 Accelerate Funding
3.0 Ryan Bean 5 Year Planning 2020&New Form 7/8/2020
GENERAL INFORMATION
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Nine Mile Powerhouse Crane Rehab
Requested Spend Amount $1 500 000
Requested Spend Time Period 2 years
Requesting Organization/Department C07/GPSS
Business Case Owner I Sponsor Ryan Bean I Bob Weisbeck
Sponsor Organization/Department C07/GPSS
Phase Initiation
Category Project
Driver Failed Plant & Operations
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The Nine Mile Falls bridge cranes were replaced in 1993 prior to the Units 3 and
4 replacement project. Both cranes are Kone brand 35ton cranes. Service class
for both cranes is H1 — light duty. The light duty means infrequent use in a
powerhouse or seldom used warehouse setting.
These cranes are now beyond their useful life. Recent maintenance and deeper
investigation have resulted in one crane being removed from service and the
other having a finite amount of life left.
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 this business case is Failed Plant. The generator floor crane is
no longer available, and the access bay crane has a finite amount of life left
placing future repair and refurbishment activities at risk. Nine Mile supplies
year-round base load hydroelectric power to Avista's portfolio. Continuing to
operate Nine Mile safely and reliably provides our customers with low cost,
reliable power while ensuring the region has the resources it needs for the Bulk
Electric System (BES).
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
These cranes are critical to repair and refurbishment work necessary to maintain
and overhaul generating equipment. Many of the electrical control components
of the crane are now obsolete, and retrofitting the with other parts is not possible.
Many mechanical parts are no longer produced such that replacement parts
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Nine Mile Powerhouse Crane Rehab
must be custom fabricated. If the work is not addressed, this will lead to
extended down time due for repairs, increased O&M costs, and impacting
schedules of future repair and overhaul work.
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 measure of success would be in restoring the capabilities of the
powerhouse cranes. This could be captured in reduced crane downtime,
reduced O&M for crane repairs, and decreased risk to future project schedules
due to crane failures. With the current generator bay crane trolley out of service,
overhauls of any major turbine generator equipment may not be possible at this
time.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the
problem.
See Nine Mile Falls HED Bridge Crane Replacement Basis of Design
Report
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 metric supporting the replacement of the current cranes is that one is
no longer functional and other has a finite number of start/stops left. Major
repairs to turbine generator equipment may not be feasible and future
projects will be impacted without cranes readily available.
During the 2018 Maintenance Assessment, the cranes were identified as
high risk due to their current condition.
1 Net Condition Index&Rating Summary
2 Units
Nine Mile Falls HED Asset Group Condition 1 Rating
69 1.666
70 - - Access Bay 3STon Kone 1.666
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Nine Mile Powerhouse Crane Rehab
Option Capital Cost Start Complete
Alternative 2: Replace Hoists, Trolleys, $1 ,500,000 01 2023 122024
Bridge crane drives and controls
Alternative 1: Replace Crane control $500,000 01 2023 122024
system
Continue to repair current system (O&M) 01 2021
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The failure of the system is the primary metric for justification of the project.
During the higher usage periods, we have seen issues with various aspects of
the cranes, mostly having to do with the controls and electrical systems. During
the most recent unit replacement project for Units 1 and 2, the general
construction contractor used the crane on an almost constant basis during
concrete demolition activities to remove rubbleized concrete from the
powerhouse. Numerous instances of thermal overload occurred on the crane
due to the high usage, causing work stopped and project delays.
Many of the electrical control components of the crane are now obsolete and
retrofitting the with other parts is not possible. Many mechanical parts are no
longer produced such that replacement parts must be custom fabricated.
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 capital cost will be spread out over two years. The first year will be primarily
design, sourcing, and installation of equipment for the first crane. This is
estimated to be $750,000. The second year will include design, sourcing, and
installation of equipment for the first crane. This is estimated to be $750,000.
This will not offset significant O&M charges because the one crane has failed
so it is no longer maintained, while the other has minimal inspection and
maintenance performed.
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 execution of this project will enable the needed overhaul of Nine Mile Units
3 & 4. The unit controls and many mechanical components are at the end of
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Nine Mile Powerhouse Crane Rehab
their useful life. Plant production and reliability will be impacted without the
availability of cranes.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Do Nothing: This alternative includes doing nothing with the existing cranes.
Maintaining them as is without replacing any electrical or mechanical
components. This would include the continual maintenance and/or replacement
of parts, where possible. This will lead to continued periods of crane down-time
for necessary repairs or part replacements. It will also maintain the thermal
overload issue that we have been experiencing during high levels of use.
The approximate capital cost to this alternative is $0 initially. However, future
costs could be substantial if crane down time causes delays during maintenance
or Unit overhaul projects. These future costs are anticipated to be all O&M costs
related to maintaining the crane as necessary.
Alternative 1: Replace crane control system. This alternative would include
removing the existing control system on the two bridge cranes and replacing
them with a modern Magnatek VFD control system. This alternative would
ensure that the control system is robust and reliable, however would not address
the thermal overload issues with extended use, nor the custom mechanical parts
needed for each repair.
Alternative 2: Preferred Alternative: Replace Hoists, Trolley's, Bridge crane
drives and controls. This alternative would include replacing each crane's hoist
and trolley system and installing a modern hoist and trolley. This alternative
also includes replacement of the controls system with the Magnatek system
discussed in Alternative 1. This would include Hoist VFD controls, VFD controls
on the hoist trolley and a new bridge panel with VFD controls that will hook to
the current end truck motors. This option is a modern in-kind replacement of
the current powerhouse cranes and would provide a lasting solution to meet
current and future crane demands.
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 project is expected to take two years. The effort in the first year will be
devoted design, equipment sourcing, and replacement of the first crane. The
effort in the second year will consist of equipment sourcing and replacement of
the second crane. The transfer to plant will be at the end of each year with the
completion of commissioning of each crane.
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Nine Mile Powerhouse Crane Rehab
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Operating Nine Mile safely and reliably provides our customers with low cost,
reliable power while ensuring the region has the resources it needs for the Bulk
Electric System (BES). By taking care of this plant we support our mission of
improving our customer's lives through innovative energy solutions which
includes hydroelectric generation. By executing this project, we ensure that
Nine Mile will continue to provide reliable service and mitigate risk to future
projects and fielding unplanned failures.
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
Industrial cranes of this size and complexity fall into this range of cost. We are
currently operating at risk with our units in not being able to respond to failed
turbine generator equipment in a timely manner thereby, incurring substantial
lost generation and O&M.
A formal Project Manager will be assigned to a project of this size. The project
will be managed within project management practices adopted by the
Generation Production and Substation Support (GPSS) department. This
includes the creation of a Steering Committee and a formal Project Team. Once
the project is initiated, reporting on scope, schedule and cost will occur monthly.
Changes in scope, schedule, or cost will be surfaced by the Project Manager to
the Steering Committee for governance. The Project Manager will manage the
project through its conclusion.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with
the business case
The primary stakeholders for this project are, the Hydro Regional Manager
on the Upper Spokane, the Upper Spokane plant personnel, GPSS
Engineering, GPSS Construction and Maintenance, and Power Supply.
Other stakeholders may be identified during project initiation.
2.8.2 Identify any related Business Cases
This project will need to be completed prior to overhaul of Units 3 & 4, or
any repairs to any major equipment on the generator floor.
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Nine Mile Powerhouse Crane Rehab
3.1 Steering Committee or Advisory Group Information
A formal Project Manager will be assigned to a project of this size. The project
will be managed within project management practices adopted by the
Generation Production and Substation Support (GPSS) department. A Steering
Committee will be formed for this project. The Project Manager will manage the
project through its conclusion.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Management of this project will include the creation of a Steering Committee
which will include managers representing the key stakeholders involved in this
project. The project will also be executed by a formal Project Team lead by the
Project Manager.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Once the project is initiated, reporting on scope, schedule and cost will occur
monthly. Changes in scope, schedule, or cost will be surfaced by the Project
Manager to the Steering Committee for governance.
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Nine Mile Powerhouse Crane Rehab
The undersigned acknowledge they have reviewed the Cabinet Gorge HVAC
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: &IRyan Bean
Title: Plant Manager, Upper Spokane
Role: Business Case Owner
Signature: ,A4)15B� Date: 7/31/2020
Print Name: Andy Vickers
Title: Director, GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Template Version: 05/28/2020
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Nine Mile Powerhouse Roof Replacement
EXECUTIVE SUMMARY
The Nine Mile Falls generation plant is over 100 years old. The roof trusses and concrete
slab is original construction, and the roofing membrane was possibly updated in 1984 -
38 years ago or more with temporary patches and repairs since. Many inspections
conducted over the years have determined that the roof is leaking and deteriorating, and
the most recent June 2021 inspection by Garland Roofing stated that "overall the roof
system has come to the end of its serviceable life" and is badly in need of complete
replacement. As the engineering team has investigated the roof's condition, more
information has come to light revealing that the roof's steel truss members in their current
state are overstressed supporting the roof system weight (concrete roof slab and roofing
membrane material) alone with no extra capacity for live loads, such as snow. Additional
concerns include the condition of the 100-year-old steel trusses, which have experienced
some damage and corrosion over the years and still has the same 100-year-old coating
system.
The recommended solution is to address the overstressed condition of the steel trusses
and to replace the failed roof membrane system. The supporting steel truss members
will either be upgraded to increase their structural capacity or the concrete roof slab
panels be replaced with lighter weight roofing material to reduce load on the steel trusses.
The estimated cost for the roof is $1,000,000 to address both the structural and roofing
needs. The service code for this program is Electric Direct and the jurisdiction for the
project is Allocated North serving our electric customers in Washington and Idaho.
Operating Nine Mile safely and reliably provides our customers with low cost, reliable
power while ensuring the region has the resources it needs for the Bulk Electric System
(BES).
VERSION HISTORY
Version Author Description Date Notes
Draft Ran Bean Initial draft of original business case 8/18/2022
GENERAL INFORMATION
Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 7
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Nine Mile Powerhouse Roof Replacement
Requested Spend Amount $ 1,000,000
Requested Spend Time Period 1 Year
Requesting Organization/Department C07/GPSS
Business Case Owner I Sponsor Ryan Bean I Alexis Alexander
Sponsor Organization/Department C07/GPSS
Phase Initiation
Category Project
Driver Asset Condition
1 . BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The powerhouse roof at Nine Mile needs replacement due to age and deterioration. The
current membrane leaks and the existing roof trusses are in an overstressed condition
that requires remediation.
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 this business case is Asset Condition. The powerhouse roof is needed in
good condition to protect the inner workings of the generating plant. Nine Mile supplies
year-round base load hydroelectric power to Avista's portfolio. Continuing to operate
Nine Mile safely and reliably provides our customers with low cost, reliable power while
ensuring the region has the resources it needs for the Bulk Electric System (BES).
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The roof has reached the end of its serviceable life and is structurally deficient. If not
addressed in the near future, the condition of the roof will continue to degrade, exposing
the plant to water infiltration and potential failure due to its overstressed 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.
The measure would include restoring the structural integrity and watertight seal of the
roof to provide years of service to come. By restoring the roof, we protect our ability to
generate low-cost power for our customers.
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Nine Mile Powerhouse Roof Replacement
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
- NM Roof Structure Analysis Memo
- Roof Truss Steel Coupon Test 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.
Per roofing condition inspection, the roof has reached the end of its useful life.
2. PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Start Complete
Cost
1. Address overstress and membrane $1,000,000 012023 122023
condition
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The failure of the existing roofing membrane is the primary metric for justification of the
project. Investigative measures have been taken to determine the exact quality of the
roof and its components. These measures include steel and concrete assessments and
analysis. By addressing the problem, we mitigate the risk of water damaging critical
generating equipment and/or roof failure.
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 because of this investment.
The capital costs will be spread over 1 year. Current investigative efforts will inform
selection of an appropriate structural remedy and those costs will be transferred to this
project. Truss remediation will precede the roof membrane replacement in the fall. This
will not offset significant O&M charges because roofing and roof trusses are low
maintenance items.
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 execution of this project will enable the continued operation of Nine Mile Units
HED. Plant production and reliability will be impacted without a sound roof.
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Nine Mile Powerhouse Roof Replacement
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
OPTION 1: Upgrade the 8 steel trusses by reinforcing the overstressed members to
provide greater capacity.
Pro's:
• Regardless of what option is chosen, the roof trusses need to be maintained by sand
blasting and painting
• Reinforcing truss members improves strength/capacity of truss for dead load and live
load
Con's:
• Unloading the truss is tricky and could put a member designed for tension into
compression; applied forces/stresses need monitored
• Lead abatement required (steel truss clean up and painting)
OPTION 2: Reduce the dead load weight on steel trusses by cutting out concrete sections
of the roof and replacing with metal lightweight deck material.
Pro's:
• Regardless of what option is chosen, the roof trusses need to be maintained by sand
blasting and painting
• Cutting out concrete sections reduces dead weight on truss members
Con's:
• Uneven areas where cutouts made?? Or can these areas be built up and then a new
membrane applied and not have compromising uneven roof areas that create issues
in the future?
• Dusty & concrete fines need contained (in powerhouse) during concrete cutting
• Lead abatement required (steel truss clean up and painting)
OPTION 3: Perform complete tear off the concrete roof and concrete beams over the
trusses (unless it makes more sense to keep the concrete beams and just remove the slab)
and replace with a new roof (metal deck & membrane roofing).
Pro's:
• Regardless of what option is chosen, the roof trusses need to be maintained by sand
blasting and painting
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Nine Mile Powerhouse Roof Replacement
• Reduces dead weight on truss members; new roof material would be much lighter
than existing concrete roof
Con's:
• Extensive work and could be disruptive to plant operations
• Lead abatement required (steel truss clean up and painting)
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.
Costs will be transferred to plant as the stages of work are completed. First will be the
truss remediation followed by the new roofing membrane.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Operating Nine Mile safely and reliably provides our customers with low cost, reliable
power while ensuring the region has the resources it needs for the Bulk Electric System
(BES). By taking care of this plant, we support our mission of improving our customer's
lives through innovative energy solutions which includes hydroelectric generation. By
executing this project, we ensure that Nine Mile will continue to provide reliable
service and mitigate risk to future projects and fielding unplanned failures.
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
Nine Mile HED is Avista's fifth largest hydroelectric plant. Roof projects of his size and
complexity fall into this range of costs.
A formal Project Manager will be assigned to a project of this size. The project will be
managed within project management practices adopted by the Generation Production
and Substation Support (GPSS) department. This includes the creation of a Steering
Committee and a formal Project Team. Once the project is initiated, reporting on
scope, schedule and cost will occur monthly. Changes in scope, schedule, or cost will
be surfaced by the Project Manager to the Steering Committee for governance. The
Project Manager will manage the project through its conclusion.
2.8 Supplemental Information
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Nine Mile Powerhouse Roof Replacement
2.8.1 Identify customers and stakeholders that interface with the business case
The primary stakeholders for this project are, the Hydro Regional Manager on the
Upper Spokane, the Upper Spokane plant personnel, GPSS Engineering, GPSS
Construction and Maintenance, and Power Supply. Other stakeholders may be
identified during project initiation.
2.8.2 Identify any related Business Cases
This project will need to be sequenced with several other projects that are in process
including crane overhauls and Unit 3 & 4 overhauls.
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
A formal Project Manager will be assigned to a project of this size. The project will be
managed using project management practices adopted by the Generation Production
and Substation Support (GPSS) department. A Steering Committee will be formed for
this project. The Project Manager will manage the project through its conclusion.
3.2 Provide and discuss the governance processes and people that will
provide oversight
Management of this project will include the creation of a Steering Committee which
will include managers representing the key stakeholders involved in this project. The
project will also be executed by a formal Project Team lead by the Project Manager.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored?
Once the project is initiated, reporting on scope, schedule and cost will occur monthly.
Changes in scope, schedule, or cost will be surfaced by the Project Manager to the
Steering Committee for governance.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Nine Mile Powerhouse Roof Replacement
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.
Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 7
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Nine Mile Powerhouse Roof Replacement
DigitSignature: Ryan Bean Date al 022 08.3ly signed b1y1R Bean
04:yanB Date:
-07'00'
Print Name: Ryan Bean
Title: Plant Manager
Role: Business Case Owner
Digitally signed by Alexis
Signature: Alexis AlexanderAlexander Date:
Date:2022.09.02 16:13:32-07'00'
Print Name: Alexis Alexander
Title: Director, GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: 04.21.2022 Page 7 of 7
Staff_PR_037 Attachment C 167 of 237

Noxon Rapids Spillgate Refurbishment
EXECUTIVE SUMMARY
The eight Spillgates at Noxon Rapids HED are over 60 years old and are the
original gates. The Spillgates are critical equipment which control the flow of water
over the dam during spill conditions when the water flowing in the river exceeds
that which passes through the turbines in the plant. They are also protection for
the dam during high flow periods or in the event that the plant or units trip to
prevent overtopping or flooding of the dam. The gates require repair or
replacement due to age, future EIM usage requriements, and structural analysis
which reveals that the current gates may not be designed to meet the loading
requirements during operation and due to seismic conditions. The spillgate issues
must be resolved in the near future for the safety and reliability of the plant
personnel and equipment. Fully functioning spillgates is a FERC requirement and
part of the Dam Safety program. At the time of writing this document, the FERC
was reviewing a site specific seismic hazard assement performed at Noxon
Rapids, the results of which will inform the project on the necessary path forward,
whether the gates are refurbished or if they are required to be replaced.
The path forward and recommended alternative has taken different forms over the
life of this project. It started out as potential refurbishment or replacement of the
gates, however, has morphed into a refurbishment project to strengthen specific
identified weaker members of the gate to meet necessary FERC and design
standards to meet all operating conditions — besides seismic. The FERC is
continuing to review the seismic hazard assessment at Noxon Rapids, which will
inform the necessary seismicity requirements at the facility. However, a potential
outcome of that assessment would be more significant enhancements necessary
across the entirety of the plant, and as such, the determination to proceed with the
strengthening project at this time was prudent to ensure that the spillgates meet all
normal operating requirements. The project budget originally was estimated at
$24.9M, where the revised request is down to $3.85M with the revised scope of
work. The recommended solution was reviewed by GPSS Engineering and
approved by GPSS Management and the project steering committee.
VERSION HISTORY
Version Author Description Date Notes
1.0 PJ Henscheid Format existing BC into exec summary 7.6.20 5-year Capital Planning
Process
2.0 Jessica Bean/PJ Completion of full BCJN document 8.3.20 5-year Capital Planning
Henscheid Process
3.0 PJ Henscheid Updated to 2022 template and modified 8 24 22
budget to align with improved estimates
Business Case Justification Narrative Template Version:04.21.2022 Page 1 of 8
Staff PR_037 Attachment C 168 of 237

Noxon Rapids Spillgate Refurbishment
GENERAL INFORMATION
Requested Spend Amount $3,850,000
Requested Spend Time Period 6 years, 2019-2024
Requesting Organization/Department GPSS
Business Case Owner I Sponsor PJ Henscheid Alexis Alexander
Sponsor Organization/Department GPSS
Phase Execution
Category Project
Driver Mandatory & Compliance
1. BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
1.1 What is the current or potential problem that is being addressed?
(1) The Noxon Spillgates are nearing the end of their useful life as Avista transitions into the
EIM market. EIM will require the spillgates to be used at greater frequencies than they are today
and with finer movements. The gate mechanisms can't support these types of and quanity of
movements due to age, material, and design. (2) The gates are structurally insufficient when
compared against the FERC requrements for structural stability when an earthquake hits. If an
earthquake hits and damages the dam such that they are unoperable, that could potentially be
a danger to plant personnel, the community downstream, and Avista's ability to generalte
electricity in a prudent manner.
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
(1) MANDATORY&COMPLIANCE Working and safe tainter gates are required by FERC. Additional
scrutiny is placed on tainter gates by FERC after the Folsom Dam Failure. If Avista neglects to
address the conditons that FERC has put into place and expects from this project, in particular, we
will be out of regulatory compliance. (2) PERFORMANCE & CAPACITY fully functioning spillgates
are an integral part of a fully functioning dam. They maintain the forebay level which, in turn, helps
dictate the amount of power generated for our customers; they keep customers safe by controlling
the amount of water that flows downstream during normal operations and during flood events (3)
ASSET CONDITION The gates are original to the dam. The Noxon Spillgates are nearing the end of
their useful life as Avista transitions into the EIM market. EIM will require the spillgates to be used at
greater frequencies than they are today and with finer movements. The gate mechanisms can't
support these types of and quanity of movements due to age, material, and design. This affects our
customers because Avista may not be able to provide power at the needed rate or quantity.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
See Section 1.1. Additionally, Avista has communicated to FERC that a gate project is forthcoming.
Should we neglect to move forward with this project, Avista would be out of regulatory compliance.
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Noxon Rapids Spillgate Refurbishment
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) constructing a FERC approved design would remove Avista from any regulatory compliance lists
that we are on due to insufficiently strong spillgates; (2) The gates would operate such that the plant
operators could support the directives from the EIM market.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
• GPSS "G" Drive @ \\c01 ml 14
o G:\Generation\401 Noxon Rapids\Projects\ER-4187 Spillgate
Refurbishment\40105196 Spillgate Remediation\05 Engr\05.12-Studies
and Inspections
■ LCI Seismic Analysis: this document discusses the seismicity of
the Noxon, Montana
■ Strata Shear Wave Velocity Testing: this document provides
data showing how seismic waves move through the ground at
Noxon
■ Stantec Structural Report:this document takes the seismic data
and the seismic analysis, applies it to the dam using models,
and discusses the failure points of the facility
■ Schnable Seismic Hazard and Geophyiscal Report: This is
Avista's Part 12 Inspector review of the LCI Seismic Analysis
o G:\Generation\' Hydro Plants\Noxon Rapids HED\Projects\2020
Spillgate Rehab\09 Submittals
• Draft Structural Report: this document updates the Stantec
Structural Report noted above using LCI Sesimic Analysis data
■ Drafit Pier Analysis Technical Memo: this document
summarizes the structural analysis of the Noxon Dam spillway
piers to accommodate a cross-valley seismic event
■ Draft Electrical Systems Evaluation Report: this document
reviews the feasibility of reusing the existing electrical
infrastructure
■ Draft Gate Trunnion System Review: this document evaluates
the past use of the gates, future use of the gates, and the
existing conditions to help arrive at a recommendation for their
replacement.
■ Draft Gate Hoist System Review: this document reviews the
existing hoist condition, expected lifting capacity, and potential
for upgrade and modernization
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.
At minimum, the highlighted members require strengthening. Depending on the size of
an earthquake the FERC will require the gates to withstand, the entire gate could be
replaced as well as the associated mechanical and electrical gear. If the earthquake
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Noxon Rapids Spillgate Refurbishment
required by the FERC is large enough, it may require modifying the concrete Spillgate
piers. At this time however, the members will be only strengthened.
Top Girder
Top Strut
Diagonal
Bracing
Trunnion Location
(Trunnions Not Shown)
Middle
Strut
2. PROPOSAL AND RECOMMENDED SOLUTION
Continue on with the project. This is the best solution because we have promised the FERC
that we will mitigate structural issues on the spillgates and it will ensure the spillgates have a
long life once we have entered the EIM market.
Continuing forward with the proposed strengthening project of the identified weak members provides
confidence and our ability to meet all FERC design requirements for Tainter gates until such time as
we realize the full impacts of the seismicity at site.
Option Capital Cost Start Complete
Recommended: Strengthen the diagonal members $3,850,000 0112019 1212024
with bracing until such time as seismicity can
determine the best path forward for the gates
Alternative 1: Rehab/Replace the Noxon Spillgates $24,900,000 0112019 Unknown
following determination of seismicity needs
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
o Engineering Analysis, see Section 1.5.1
o FERC regirements
o Operational Data of the number of times the spillgates are used per year
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Noxon Rapids Spillgate Refurbishment
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.
o Avista will receive upgraded spillgates,and associated appurtenances, once the project
is complete
o Newly renovated spillgates, once complete, should require less maintenance ethat 70
year old spillgates.
o New technology integrated into the project may require up-front training and
troubleshooting
The project is anticipating the following remaining costs:
2022 - $600,000
2023 - $3,100,000
2024 - $150,000
[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.
o Upgraded Spillgates will support the EIM iniative be ensuring the gates are
functional to move as frequently as anticipated as part of Avista's participation
in EIM
o Construction processes will make operating the all 8 spillgates impossible at
once, for rthe duration of construction.
o Upgraded spillgates will support operations O&M expendaratures year-over-
year
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
o Not doing anything—this was never an option because working on the gates is
a FERC requirement
o Structural Reinforcement of select steel members—this was considered to be
an interim fix until the gates could be repair or replaced. The business unit
elected to not move forward with this because a larger gate project was on the
horizon.
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.
o Work is continuing forward to strengthen the gate members identified.
Construction activities will start in late 2022 and continue to mid to late 2024.
Likely a portion of the project will become used and useful in 2022 and 2023,
with the remainder in 2024. The means and methods and construction schedule
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Noxon Rapids Spillgate Refurbishment
have yet to be determined so exact timelines are unknown at this point in time.
It is anticvipated to perform work on Gate #5 in late 2022, Gates 6, 7, and 8 in
early 2023, and gates 1 through 4 in late 2023 and rolling into 2024.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This project emphasizes: reliability, safety, and the customer(through the end result
of being able to support the EIM iniative.
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
See Section 2.5.
Additionally We are prudently investing money to understand what type of
repair/repaclement/rehab is necessary. When we understand that, a second round
of prudency will be entered when the project and the project steering committee will
weigh the cost-benefits of each alternative.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
O Environmental
O Power Supply
o GPSS
O Supply Chain
O Exeternal Communications
O Asset Management
O Clark Fork Personnel
2.8.2 Identify any related Business Cases
No related business cases at this time
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
STEERING COMMITTEE MEMBERS
O Bruce Howard
O Scott Kinney
O Alexis Alexander
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Noxon Rapids Spillgate Refurbishment
3.2 Provide and discuss the governance processes and people that will
provide oversight
0 Dam Safety Team
0 Scott Kinney
0 Alexis Alexander
0 Bruce Howard
The project will be led by the core project team. Any changes to scope, schedule
and budget will be submitted for approval to the steering committee and with the
respective cost thresholds as defined in the project charter.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The project is utilizing the Project Change Log to track and manage all Project
Change Requests (PCR) associated with the delivery of the construction project.
The PCR describes the need for change, supplemental documentation, related
project artifacts, change order proposals, and any other pertinent information.
PCR's are then signed for approval by the project approval thresholds, and then
processed against the project risk registry, and or contract amendment with the
contractor.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Noxon Rapids Spillgate
Refurbishment BCJN 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: 8.25.22
Print Name: PJ Henscheid
Title: Mgr, Civil and Mechanical
Engineering
Role: Business Case Owner
Signature: 01 Date: 9/2/2022
Print Name: Alexis Alexander
Title: Direector, GPSS
Role: Business Case Sponsor
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Noxon Rapids Spillgate Refurbishment
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
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DocuSign Envelope ID:BCDD8BC0-6E83-4A7A-A46C-05127B7EEBA3
Oil Storage Improvements
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
segregate 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 May 2022). There will
be two rate jurisdictions for this project. For the actual oil tanks and dispensing equipment,
since they will only be used for Substation Support, the costs will be filed under Electric
Only—WA & ID. All other associated site improvements, since they could be used by any
business unit at the Mission Campus, will be filed with the rate jurisdiction of 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. The Facilities Capital Steering Committee approved submission of this
Business Case.
Business Case Justification Narrative Page 1 of 11
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DocuSign Envelope ID: BCDD8BC0-6E83-4A7A-A46C-05127B7EEBA3
Oil Storage Improvements
VERSION HISTORY
Version Author Description Date Notes
0.0 Vance Ruppert Initial draft to be approved by 7/6/2020
Sponsors
1.0 Vance Ruppert Final Draft, Sponsor edits 7/10/2020
incorporated
1.1 Vance Ruppert BUN update Capital Planning 7/9/2021
2.0 Lindsay Miller Executive Summary Update 5/24/2022
2.1 Conor Crai en BUN update 08/31/2022
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
Sponsors: Bruce Howard, Alexis Alexander, and Alicia
Gibbs
Sponsor Organization/Department Environmental/GPSS/Shared Services
Phase Initiation
Category Project
Driver Asset Condition
Business Case Justification Narrative Page 2 of 11
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DocuSign Envelope ID:BCDD8BC0-6E83-4A7A-A46C-05127B7EEBA3
Oil Storage Improvements
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 maintenance 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. On June 17, 2020
Avista received a letter from the Washington Department of Ecology's Toxic Cleanup
Program stating that "no further action" is required in the cleanup effort.
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
Business Case Justification Narrative Page 3 of 11
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Oil Storage Improvements
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 an 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 Underground 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/ Conor Craigen).
Pictures of the oil tank overflow as described in Section 1.1 (B) above are
available on request (Facilities /Conor Craigen).
Pictures of the annual water roof leaks as described in Section 1.1 (C)above are
available on request (Facilities /Conor Craigen).
Option Capital Cost Start Complete
Recommended Option: Build new above ground $1.5M 0712022 1112023
tanks, demolish underground vault and tanks (see note 1
below)
Alternate #1:Build a new GPSS Maintenance Shop $15M-$25M(?) 2022 (?) 2024 (?)
at Mission or off-site, with a new tank(s)
arrangement.
Notes:
1) See Appendix A for further cost estimate breakdowns of the Recommended Option's
$1.5M Capital Cost as shown in the table above.
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.
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DocuSign Envelope ID: BCDD8BC0-6E83-4A7A-A46C-05127B7EEBA3
Oil Storage Improvements
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
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 used for tank procurement and
construction.
The project will provide the followin_g 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 oiland 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 second 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
Business Case Justification Narrative Page 5 of 11
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Oil Storage Improvements
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 the
Mission Campus ES, and in the field /at any particular substation.
Demolish the existing underground vault. Remove only 6 feet or so top-down, with existing
slab and footings to remain. Holes will be bored in to the abandoned slab, and the
remaining area filled in with structural fill. The removed underground vault will be replaced
with a new asphalt parking lot, approximately the same footprint, for GPSS use.
Siding and slider doors will be added 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.
Business Case Justification Narrative Page 6 of 11
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Oil Storage Improvements
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 2023. The major milestones and timeline of the project is estimated to be the
following:
Complete Design Drawings: Completed
Bidding / permits complete, General Contractor (GC) selection: 2 months
GC procure tanks and long lead items: 6 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
2023, with all of its $1.5M transferring to plant in 2024, 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 strategic vision of
environmental stewardship. This Business Case clearly identifies the environmental
regulatory issues that could 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
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, with the expectation of meeting scope, schedule, and budget
targets.
2.8 Supplemental Information
Business Case Justification Narrative Page 7 of 11
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Oil Storage Improvements
2.8.1 Identify customers and stakeholders that interface with the business case
Maior customers/stakeholders:
Environmental Department
Generation Production / Substation Support Department
Facilities
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 August 2022) shall consist of the following:
Alicia Gibbs, Jody Morehouse, Alexis Alexander, David Howell, Jim Corder, Adam
Munson, Mike Magruder, 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 ( Alexis Alexander, Brad
McNamara)
Facilities (Dan Johnson, Eric Bowles, Robert Johnson, Dave Schlicht, Nick Lasko, Conor
Craigen)
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 Lifetime to Date, Lifetime
Project Estimate at Complete, and Lifetime Project Variance at Complete.
Each month, the SteerCo will make decisions on cost, scope, or budget items as required
by the Project Execution Plan. The project manager reserves the right to present items not
outlined in the Project Execution Plan if he/she determines its importance is relevant to
SteerCo input.
Business Case Justification Narrative Page 8 of 11
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Oil Storage Improvements
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.
Business Case Justification Narrative Page 9 of 11
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DocuSign Envelope ID:BCDD8BC0-6E83-4A7A-A46C-05127B7EEBA3
Oil Storage Improvements
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.
Docu Signed by:
Signature: 66WO-S Date: Aug-31-2022 1 2:55 PM PDT
Print Name: aAcc724D1a764c2...
�i w oumes
Title: Corp Facilities Manager
Role: Business Case Owner
DocuSigned by:
Signature: QUM, �tW Date: Au9-31-2022 1 6:14 PM PDT
Print Name: 4sc42s55345E453...
r�itia Grabs
Title: Director of Shared Services
Role: Business Case Sponsor
Template Version: 05/28/2020
Business Case Justification Narrative Page 10 of 11
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Oil Storage Improvements
Appendix A— Cost Estimate Breakdown
Presented and approved by Facilities Steering Committee to request additional funds
through the Capital Planning Group on June 10, 2021.
YEARLY 2022
Planned
Category Spend Scope
Group 1-12 hr/month
Avista Resources $ 104,280 Group 2-20 hr/month
Group 3-48 hr/month
Benefits 95%of Wages $ 94,895 Matches hours shown above
$1.02M+tax forgeneral contractor
$211(forspecialinspections
Contract Project Support $ 1,145,628 $13K for consultant construction administration
Avista Supplied Equipment and Materials $
Material Overheads 8%of Mo Total $
AFUDC $ 48,620 estimated
Other Expenses $ -
Capt OH-Functional and A&G 3.25%of Mo Total $ 45,286 3.25%of all charges
Contingency 6%of Planned $ 86,323 If needed foranyitems as described above
1,525,031
$ 1,500,000 Budget
$ (25,031) Variance
Business Case Justification Narrative Page 11 of 11
Staff PR_037 Attachment C 186 of 237

Primary URD Cable Replacement 2017
1 GENERAL INFORMATION
Requested Spend Amount $1,000,000
Requesting Organization/Department Asset Maintenance
Business Case Owner Cody Krogh
Business Case Sponsor Bryan Cox
Sponsor Organization/Department Asset Maintenance
Category Program
Driver Asset Condition
1.1 Steering Committee or Advisory Group Information
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 BUSINESS 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 unjacketed first generation
underground primary distribution cable referred to as URD cable. This first generation
URD cable was installed from 1971 to 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 8 faults per 10 miles of cable. The faults reached a peak of
238 annual failures in 2007. Increased capital funding to replace this URD cable from
2005 through 2009 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.
AypiWrbrb�aARA*M&tt tion Narrative PfWo19-�

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.
Tablet: URD Cable Replacement Results
Projected
.D .D Projected Actual
• . .le - Number Number
Description
• OMT Replaced Replaced
Events Events
9 143 136 178,000 213,000
2010 119 93 178,000 217,883
2011 94 95 178,000 225,823
2012 70 72 178,000 117,247
2013 45 93 0 35,874
2014 45 88 0 35,515
2015 45 64 0 24,155
Table 2: URD Cable Replacement Cost Impact
Projected Avoided Actual Avoided
Metric Outage Benefit due Outage
Description to 'D . URD
Caused Outages Outages
9 $1,038,613 $1,056,113
i $1,228,275 $1,295,225
2011 $1,368,561 $1,352,648
2012 $1,516,159 $1,481,504
r $1,744,539 $1,494,738
i $1,898,311 $1,580,378
2015 r
$1,997,052 $1,720,020
Reference:
Electric Distribution System, 2016 Asset Management Plan
,4�oipjksbSIW.1pg% !ion Narrative P o 254

Primary URD Cable Replacement 2017
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Cost Start Complete
Do nothing $0
[Recommended Solution] Continue to Replace $1 M 042017 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 pull the 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
$1 M 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 $1 M 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. It 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.
sipps§S7"fa lm�4f Wion Narrative PN 0 B74

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 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: 4-14- W l-q
Print Name: Cody Kro
Title: Mgr Asset Maintenance
Role: Business Case Owner
Signature: Date: y u 7 '1-7
Print Name: Bryan Cox
Title: Sr Dir of HR Operations
Role: Business Case Sponsor
5 VERSION HISTORY
Version Implemented Revision Approved Approval Reason
By Date By Date
1.0 Cody Krogh 4/14/2017 Bryan Cox 4/14/2017 Initial version
Template Version:03/07/2017
Narrative P o1�74

Protection System Upgrades for PRC-002
EXECUTIVE SUMMARY
This section is reserved to provide a brief description of the business case and high level summary ofthe 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 Author Description Date Notes
1.0 Randy Spacek Initial Version 7/11/2017 Initial Version
2.0 Glenn Madden Revised to remove DRAFT 5/28/2019
watermark
3.0 Karen Kusel/ Update to 2020 Template 06/2020
Glenn Madden
Business Case Justification Narrative Page 1 of 6
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Protection System Upgrades for PRC-002
GENERAL INFORMATION
Requested Spend Amount $12,000,000
Requested Spend Time Period 5 Years
Requesting Organization/Department Substation Engineering
Business Case Owner I Sponsor Glenn Madden I Josh Diluciano
Sponsor Organization/Department Electrical Engineering
Phase Execution
Category Project
Driver Mandatory & Compliance
1 BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
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 comp) ant 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.
Business Case Justification Narrative Page 2 of 6
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Protection System Upgrades for PRC-002
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 ofany supplemental information;do not attach]
NERC Reliability Standard PRC-002-2
NERC Project 200711 Disturbance Monitoring:
DL-2007-11_DM_I mp_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 offault recording.
2 PROPOSAL AND RECOMMENDED SOLUTION
[Descnbe 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 022017 102022
Do Nothing $OM
Installation of a digital recorder on each BES
bus to provide the SER and FR data.
2.1 Describe what metrics, data, analysis or information was considered when preparing
this capital request.
Examples include:
Business Case Justification Narrative Page 3 of 6
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Protection System Upgrades for PRC-002
- Samples of savings,benefits or risk avoidance estimates
- Description ofhowbenefits to customers are being measured
- Comparison ofcost($)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 08M costs, employee or staffing
reductions to O&M(offsets),etc.?
[Offsets to projects Abe more strongly scrutinized in general rate cases going forward(ref.wUl'C Docket No.U190531 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.
[Forexarnple,howwillthe outcome ofthis business case irnpactotherparts ofthe 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.
[Oescnbe 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.
Uthis is a program or compilation ofdiscrete projects,explain the importance ofthe body ofAurk.]
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.
Business Case Justification Narrative Page 4 of 6
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Protection System Upgrades for PRC-002
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 anybusiness 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 ofyour 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
Business Case Justification Narrative Page 5 of 6
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Protection System Upgrades for PRC-002
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: QS42— NDate:� 1 Z-23—2a
Print Name: Glenn Madden
Title: Manager, Substation Engineering
Role: Business Case Owner
Signature: LA Date: 1/5/2021
Print Name: Josh DiLuciano
Title: Director, Electrical Engineering
Role: Business Case Sponsor
Signature: Date: 1/5/2021
Print Name: Damon Fisher
Title: Principle Engineer
Role: Steering/Advisory Committee Review
Template Version: 05/28/2020
Business Case Justification Narrative Page 6 of 6
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DocuSign Envelope ID:516820B0-6EEF-4EC7-BE16-9AD269F2155B
Saddle Mountain 230-115kV Station (New) Integration Project
Phase 2
EXECUTIVE SUMMARY
This section is reserved to provide a brief description of the business case and high-level summary of the projects or
programs included. Please limit to no more than 2 paragraphs. Components that should be included:
1) NEEDs ASSESSMENT-a synopsis of the problem, the current state and recommended solution
2) COST-the cost of the recommended solution
3) DOCUMENT SUMMARY-benefit to the customer
4) RISK-of not approving the business case
5)APPROVALS-who reviewed and approved the recommended solution
<< Both the Executive Summary and Version History should fit into one page>>
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 two
30MVA transformers. The business case also includes substantial 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 that they can continue to have the
reliability of the electric system that they have become accustomed to receiving. This project has
been approved and prioritices by the Engineering Roundtable Committee.
Service: ED — Electric Direct
Jurisdiction: AN —Allocated North
Engineering Roundtable Request Number: ERT_2017-64
Cost of Solution: $43,800,000
VERSION HISTORY
Version Author Description Date Notes
1.0 Unknown Initial Version 2017
2.0 Karen Kusel/ Update to 202 Template 6/2020
Glenn Madden
2.1 Karen Kusel Project Cost Update, 2022 Template 6/2022
Business Case Justification Narrative Page 1 of 7
Staff PR_037 Attachment C 197 of 237

DocuSign Envelope ID:516820B0-6EEF-4EC7-BE16-9AD269F2155B
Saddle Mountain 230-115kV Station (New) Integration Project
Phase 2
GENERAL INFORMATION
Requested Spend Amount $43,800,000
Requested Spend Time Period 6 Years
Requesting Organization/Department Transmission / System Planning
Business Case Owner I Sponsor Glenn Madden Josh DiLuciano
Sponsor Organization/Department T&D
Phase Execution
Category Project
Driver Mandatory& Compliance
1 BUSINESS PROBLEM
[This section must provide the overall business case information conveying the benefit to the customer, what
the project will do and current problem statement]
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 levels 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.
Business Case Justification Narrative Page 2 of 7
Staff PR_037 Attachment C 198 of 237

DocuSign Envelope ID:516820B0-6EEF-4EC7-BE16-9AD269F2155B
Saddle Mountain 230-115kV Station (New) Integration Project
Phase 2
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.
Business Case Justification Narrative Page 3 of 7
Staff PR_037 Attachment C 199 of 237

DocuSign Envelope ID:516820B0-6EEF-4EC7-BE16-9AD269F2155B
Saddle Mountain 230-115kV Station (New) Integration Project
Phase 2
Option Capital Cost Start Complete
Recommended Solution: Build Saddle Mountain $11 M 01 2020 122021
230/115kV Substation Phase 2 Project with
associated support projects
Alternative 1: Status Quo $OM
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 0&M costs, employee or staffing
reductions to 0&M(offsets), etc.?
[Offsets to projects will be more strongly scrutinized in general rate cases going forward(ref. WUTC Docket No.U-190531 Policy
Statement),therefore it is critical that these impacts are thought through in order to support rate recovery.]
2018 $1,100,000
2019 $3,000
2020 $2,300,000
2021 $28,000,000
2022 $10,600,000 (Expected Spend)
2023 $1,950,000 (Forecast)
2023 — 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.
Business Case Justification Narrative Page 4 of 7
Staff PR_037 Attachment C 200 of 237

DocuSign Envelope ID:516820B0-6EEF-4EC7-BE16-9AD269F2155B
Saddle Mountain 230-115kV Station (New) Integration Project
Phase 2
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 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.]
Business Case Justification Narrative Page 5 of 7
Staff PR_037 Attachment C 201 of 237

DocuSign Envelope ID:516820B0-6EEF-4EC7-BE16-9AD269F2155B
Saddle Mountain 230-115kV Station (New) Integration Project
Phase 2
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.
3.2 Provide and discuss the governance processes and people that will provide
oversight
Engineering Roundtable meets several times a year to analyze current and future projects.
3.3 How will decision-making, prioritization, and change requests be documented
and monitored
Project folders are saved to Engineering shared drives and Businesss Case Funds
Requests are available on the Finance sharepoint site
Business Case Justification Narrative Page 6 of 7
Staff PR_037 Attachment C 202 of 237

DocuSign Envelope ID:516820B0-6EEF-4EC7-BE16-9AD269F2155B
Saddle Mountain 230-115kV Station (New) Integration Project
Phase 2
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.
DocuSigned by: A
t
Signature: J Nl,a4lA11, Date: Jun-28-2022 1 3:50 PM PDT
Print Name: 'D4B3°FSCBD8463...
V IGI 111 IVIQUUCI I
Title: Manager, Substation Engineering
Role: Business Case Owner
DocuSigned by:
Signature: E�A3C71874F65B.
6SrV[(,tXMhDate: Jul-05-2022 1 7:43 AM PDT
Print Name: u, 9.4D .._-,Jano
Title: Director, Electrical Engineering
Role: Business Case Sponsor
Signature: Date:
Print Name: Damon Fisher
Title: Principle Engineer
Role: Steering/Advisory Committee Review
Template Version: 05/28/2020
Business Case Justification Narrative Page 7 of 7
Staff PR_037 Attachment C 203 of 237

Clean Energy Fund 3 - Eco-District G2G
1 GENERAL INFORMATION
Requested Spend Amount $4,500,000 (Avista Contribution)
Requesting Organization/Department Research and Development/
Distribution Operations
Business Case Owner John Gibson (Project Sponsor)
Business Case Sponsor Heather Rosentrater(Executive Sponsor)
Sponsor Organization/Department Distribution Operations
Category Strategic
Driver Customer Service Quality & Reliability
1.1 Steering Committee or Advisory Group Information
• Heather Rosentrater(Executive Sponsor)
• John Gibson (Project Sponsor)
• Curt Kirkeby (Concept Engineer/Project Sponsor)
• To-be-determined (Project Manager)
• To-be-determined (Project Engineer)
• Washington State, Department of Commerce advisory group
2 BUSINESS PROBLEM
This Eco-District Grid Modernization project proposal ("EGM Proposal") will seek to
leverage Avista's participation in the Eco-District by utilizing the net-zero, carbon free
Catalyst building being constructed in the Eco-District to evaluate how these types of net-
zero,carbon free developments impact the energy production and delivery system.Avista will
deploy advanced thermal and electric storage assets integrated with load control and inverter
technology with an overall objective to develop a control strategy within the Eco-District
which balances the competing certification requirements of net-zero, carbon free
developments against grid utilization strategies to reduce unnecessary investment in grid
infrastructure. This project is branded the Grid To Green ("G2G") Project. The G2G Project
assets and analytics will be designed to measure and value how net-zero, and carbon free
developments impact the regional and local electrical system production and delivery system.
The G2G Project objectives are: (1) to deploy electric and thermal storage assets in the Eco-
District to modulate the voltage swings resulting from local intermittent generation; (2) to
deploy electric, thermal storage assets with load management control strategies to reduce
production, transmission and feeder peak demands; (3) to evaluate the transmission and
distribution deferral that may be created through the deployment of the Eco-District combined
with control and storage assets; and (4) to develop a social and economic outreach program
to incentivize local small business adjacent to the Eco-District to deploy demand response
programs.
Business Case Justification Narrative Page 1 of 6
Staff PR_037 Attachment C 204 of 237

Clean Energy Fund 3 - Eco-District G2G
Business Model Challenge
Avista's core business is centered on providing safe, reliable, efficient and low cost energy to
our customers. However, consumers are increasingly asking for value-add energy products
and services like self-generation, clean energy and socially responsible buildings.
Electric and Thermal Storage Integration Challenger
Within the last ten years, significant technology advancements have occurred in building
mechanical systems to heat and chill building environments. Many of these advancements
have evolved around various thermal dynamic processes to store, extract and recycle hot and
chilled water. However, these mechanical system advances have been driven to support just
the building conditioned environment.
Electrical Transactive Bus
Consumers want to participate in their local economy, which is evident just from the simple
concept of local farmers markets. In the energy environment, energy prosumers are wanting
to participate in local energy exchanges with renewable. So, what is the local exchange? And
how would transactions occur and be valued?
Operational Challenge: Open Source Energy Operating System
Today,the interconnection requirements to deploy controllable Distributed Energy Resources
("DERs") on the grid requires significant engineering resources in order to perform
interconnection studies, establish design specifications and deploy control and protection
settings. How could we develop a grid platform which would support a"plug and play" type
capability to allow for a seamless interconnection of DERs?
DC Bus
The delivery of electrical energy across long distances is more efficiently accomplished with
Alternating Current ("AC") power. Current estimates show approximate energy loss in the
twenty to thirty percent due to the conversion between AC to Direct Current ("DC"). Would
it be practical to centralize DC generation resources like solar and storage in order to reduce
these losses? Could a DC system or bus be leveraged by a buildings' participation in the Eco-
District in order to address building code requirements for backup generation or lighting?
Extending Benefits to Local Community
The Eco-District development is being built in the East Sprague area of Spokane that has
traditionally been economically disadvantaged, and small businesses currently struggle with
their bottom line.
Business Case Justification Narrative Page 2 of 6
Staff PR_037 Attachment C 205 of 237

Clean Energy Fund 3 - Eco-District G2G
3 PROPOSAL AND RECOMMENDED SOLUTION
Option Capital Cost Start Complete
Do nothing $0
Implementation of CEF3 Proposal $4,500,0001 6/2019 12/2022
Project Opportunities for Solution Development
This EGM Proposal contains key components of innovation around the utility business model,
grid and control assets, technology platforms and outreach learning programs. For each
innovative component, the challenge, opportunities and solution is summarized.
Changes to the Business Model
Net-zero and carbon free developments are expensive and difficult to finance using the
traditional capital funding model. The HUB building will centralize electrical, thermal and
mechanical assets in order to improve the economic viability of these net-zero, carbon
free developments
Integration of Electric and Thermal Storage
Centralizing the electrical, thermal and mechanical components in the HUB provides
adequate scale to evaluate the relative impact of these systems on the grid.
Creation of an Electrical Transactive Bus
The HUB and its 480 V bus offers potential to facilitate a local market hub (balancing area)
for local exchanges. This 480 V bus in the HUB is common point of coupling of the Eco-
District's load and renewable and storage resources.
Operation Through an Open Source Energy Operating System
Avista and a coalition of like-minded utilities are investing in an effort to develop an open
source platform that can enable an interoperable framework to interconnect resources to
the electric distribution system (branded as "openDSP")The first release of openDSP is
currently scheduled for the 3rd quarter of 2019. This platform will enable a variety of grid
services similar to that envisioned by the Eco-District G2G Project.
Centering Around a DC Bus
The HUB is being designed with a DC system to tie the Catalyst and HUB solar assets to
a common inverter in the HUB which ties to the 480 V AC bus.
Extending Benefits to Local Community
The East Sprague business area receives energy and capacity from the same distribution
station and feeders which serve the Eco-District. Could small businesses and the
community benefit from the optimization of these feeders? Would the community be able
to participate in the renewable energy ecosystem somehow by offsetting demand or
through other efficiencies?
With a total capital project cost of$7 million, $2.5 million has been appropriated and approved by the
Washington State Department of Commerce and will be provided to Avista upon meeting defined Milestones
and$4.5 million is being requested of Avista
Business Case Justification Narrative Page 3 of 6
Staff PR_037 Attachment C 206 of 237

Clean Energy Fund 3 - Eco-District G2G
Strategic Innovation
Innovative Component#1: Business Model
The HUB will deploy a 480 V bus and switchgear which will pass through electric service to
the building owners participating in the Eco-District. For the first time, private investment will
be made in utility infrastructure, which would have historically been made by the utility. Also,
the Eco-District distributed generation resources ("DERs") will be inter-tied to a 480 V bus
which serves the Eco-District load. Ultimately, the HUB's 480 V bus will enable the Eco-
District to serve its own load with its generation, creating a unique and new type of business
model.
Innovative Component#2: Electric and Thermal Storage
The HUB's centralized thermal storage, boiler and chillers will be combined with electric
storage and controller technology to co-optimize value between building efficiency and grid
utilization.
Innovative Component#3: Electrical Transactive Bus
Under the G2G Project, PNNL and WSU will develop a combination of market and control
strategies to simulate transactions that could occur across the HUB 480 V bus for building
tenants. The research goals are to establish the technical and economical capability to deploy
a transactive market in the HUB.
Innovative Component#4: Open Source Energy Operating System
The G2G Project control technology will be designed and deployed to adhere to the openDSP
platform interoperability specification. This specification requirement will allow the G2G
Project deployments to be scalable across the country.
Innovative Component#5: DC Bus
The G2G Project will tie the electric storage assets to the DC bus as a part of its deployment.
The control technology will manage assets on the DC bus to optimize values between
building and grid services. Metrics will be put in place to determine if the energy savings occur
by centralizing the conversion between AC and DC.
Innovative Component#6: Extending Benefits to Local Community
As a part of the G2G Project, PECI will create outreach programs to the local business to
gage interest in programs that could reduce capacity requirements on the local feeders. PECI
will leverage Urbanova's software platform to advertise options for system reduction
programs which would direct specific savings to a neighborhood urban renewal district.
Business Case Justification Narrative Page 4 of 6
Staff PR_037 Attachment C 207 of 237

Clean Energy Fund 3 - Eco-District G2G
Proposed Project Schedule
Scope Development and Partner Coordination 6/2019 through 6/2020
Asset Procurement 9/2019 through 6/2020
Detailed Engineering Design 6/2020 through 3/2021
Equipment Delivery, Installation and Construction 3/2021 through 6/2021
Systems Integration and Commissioning 6/2021 through 8/2021
Analytics and Reporting 8/2021 through 6/2022
Impacts to Future O&M/Stakeholder Involvement
• Spokane Area Engineering/Distribution Engineering
Initial project design, implementation and construction; no ongoing O&M in addition to the
programs in place (project and electrical design)
• Distribution Dispatch
Project implementation, commissioning and ongoing operation; no ongoing O&M in addition
to the staff in place (operation will be assigned to existing staff)
• Asset Maintenance
Ongoing battery maintenance will be addressed through an O&M Agreement with each
supplier, and is expected to be less than $100,000 per year
Budget Development
The proposed budget for the project was created and vetted thought the State of Washington
Clean Energy Fund oversight committee, with significant input from the CEF1 (Turner Energy
Storage Project) and CEF2 (Micro-Transactive Grid) budget and actual costs. This allowed the
Grant Application to include a budget and request developed with a fair amount of confidence.
Expected Spend Schedule
Calendar Year 2019 $ 500,000
Calendar Year 2020 $ 3,000,000
Calendar Year 2021 $ 1,000,000
Business Case Justification Narrative Page 5 of 6
Staff PR_037 Attachment C 208 of 237

Clean Energy Fund 3 - Eco-District G2G
4 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Clean Energy Fund 3 — Eco-
District G2G and agree with the approach it presents. Significant changes to this will
be coordinated with and approved by the undersigned or their designated
representatives.
Signature: ::�L Date: ZG lZo
Print Name: <:A10 Gibson
Title: Chief Engineer, R & D
Role: Business Case Owner
Signature: Date: �� (2 -7 (� 4
Print Name: Heather Rosentrater
Title: VP, Energy Delivery
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role:
5 VERSION HISTORY
Version Implemented Revision Approved Approval Reason
By Date By Date
1.0 Kenneth Dillon 5/29/2019 John Gibson 6/05/2019 Initial version
2.0 Kenneth Dillon 6/26/2019 John Gibson 6/26/2019 Included JW revisions
Template Version: 03/07/2017
Business Case Justification Narrative Page 6 of 6
Staff PR_037 Attachment C 209 of 237

UTA SSiS r
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 paraMphs. Components that should be
included:
The UTASSIST project seeks to better enable and demonstrate the integration of grid
automation, energy storage, and renewable energy resources with enhanced cyber
security across the energy domains of the United States and India. Avista is but one of
30 collaborating entities from the United States and India incorporating 10 different test
sites. The partners include universities, national laboratories, solution providers, and
utilities. Avista's role in the project is to leverage the Innovation Lab to provide circuit and
power hardware in the loop simulation, demonstration assets in the form of the WSU
microgrid, and operational data sharing via Avista's Digital Exchange platform. The total
project is $39.7M with $7.5M provided by DOE, $7.5M provided by US partners, $7.5M
provided by the India government (GOI) and $17.2M provided by India partners. Avista's
capital cost share for the project is $350,000.0 while the DOE is providing $480,000 grant.
Avista is witnessing accelerating customer adoption of rooftop solar as well as energy
storage. DOE considers grid efficient buildings (GEB) to be viable resources for grid
utilization and Avista has developed the South Landing eco-district which is world leading
example of a GEB. How should Avista plan for DERs and GEBs and what types of
operational controls and procedures are needed? The renewable energy eco-system is
relatively immature when compared to existing utility "bread and butter" infrastructure
projects. Within the utility, the design specifications and work practices have not been
established to support the implementation of inverter-based assets. Also, the product
vendors, suppliers and contractors within the eco-system lack market maturity and are
typically operating under thin financial margins. Avista intends to produce standardized
design and operational procedures for the WSU microgrid and to successfully
demonstrate the results with the larger UTASSIST team. Additionally, the university can
leverage Avista's foundation control framework as a platform to build their research
layers. This project represents how the Avista Innovation Lab is developing the
foundational building blocks to operationalize the technology platforms within the utility as
well as support university research goals. The standards developed for this project can
be leveraged for DERs in future years. Non-participation in this phase of the overall
project would be damaging to Avista's reputation with respect to the partners and the US
DOE. That reputation is currently considered top tier.
VERSION HISTORY
Version Author Description Date Notes
1.0
Staff PR_037 Attachment C 210 of 237

UTA SSiS r
GENERAL INFORMATION
Requested Spend Amount $350,000
Requested Spend Time Period 1.25 years
Requesting Organization/Department
Business Case Owner I Sponsor John Gibson. I Jason Thackston
Sponsor Organization/Department
Phase Execution
Category Project
Driver Performance & Capacity
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]
Avista has a clean energy strategy to be carbon neutral by 2027 and carbon free by
2045. Achieving these goals will require diversified renewable bulk power resources
as well as localized distributed energy resources and active energy management of
connected loads. Electrification of transportation and fossil-based loads will stress
distribution capacity and accelerate the need for non-wire alternatives (NWA), a
portion of which the customer might provide or participate with in some way. There
are many barriers to the successful adoption of DERs and GEBs within the utility
that relate to the utility business model and rate design. But perhaps more
importantly, the technology solutions available in the renewable domain are not at
the same maturity level that utility companies expect. Likewise, utilities do not have
a mature understanding of the renewable energy domain either, leaving a gap when
integrating them into the grid.
This project intentionally operationalizes and refines the design for the WSU
microgrid such that other microgrids can be deployed in a standard manner while
accounting for operational concerns. The results of this project will help inform the
interconnection process, hosting capacity assessment methodologies, and planning
for non-wire alternatives with clear expectations for DER behavior. The customer
benefits by providing participation as well as reduced rate pressure from capacity
additions that can be offset by NWAs. The research institutions benefit from
demonstration of the solutions and access to the operational data platform.
What is the current or potential problem that is being addressed?
Staff PR_037 Attachment C 211 of 237

via ssis r
Planning for and integration of distributed energy resources either customer or
utility owned into the distribution grid. Standards for design, hosting and
operations are needed.
1.1 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant& operations) and the benefits to the customer
Performance & Capacity can be improved with DERs for grid benefit. The heat
dome shifts might have been averted with appropriate DER deployment.
Additionally, customer participation can be facilitated leading to benefits with
respect to Customer Service Quality & Reliability.
1.2 Identify why this work is needed now and what risks there are if not
approved or is deferred
Avista is witnessing accelerating customer adoption of rooftop solar as well as
energy storage. Capacity challenges are being exposed with elevated summer
temperatures. The Microgrid in the University district installed as a part of Clean
Energy Fund II revealed the need for operational standards and a clear path for
cyber security within the the grid control network. The DOE grant affords the
opportunity to reduce the cost by 50%. Failure to complete this project will
challenge the planning and integration efforts, delay operating standards and
damage Avista's reputation with the participating universities, national
laboratories, and the U.S. DOE.
1.3 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
Success comes in the form of standards and process definition that is difficult to
measure but which is critical if not established.
1.4 Supplemental Information
1.4.1 Please reference and summarize any studies that support the
problem
The most appropriate documents for reference are the Avista Lab plan for
the project and the proposal submitted to DOE by the lead partner WSU.
Both documents can be found on the Teams site for the project.
Staff PR_037 Attachment C 212 of 237

via SSiS r
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.
This project does not replace any assets. It establishes standards around
the existing WSU microgrid.
2. PROPOSAL AND RECOMMENDED SOLUTION
This project leverages the existing WSU microgrid as a demonstration asset for the larger
project team and establishes a data sharing platform for collaboration and operational
data. Avista will deliver standards that define the design for the microgrid, the
interconnection requirements, and operational procedures expected for future microgrids.
Simulation with control and power hardware in the loop as required will be integral to the
demonstration as well as the standards development.
The recommended solution is to participate in this project as a means for completing
these design standards which can only be done within the Innovation Lab environment.
The larger team is providing benefit to Avista via the very diverse partner makeup and
highly competent team membership. There are really no alternatives to compare short of
hiring a consultant to develop the standards without simulation and demonstration which
may leave Avista personnel out of the equation.
Option Capital Cost Start Complete
WASS/ST Microgrid $0.350M 012022 122023
2.1 Describe what metrics, data, analysis, or information was considered
when preparing this capital request.
Reference key points from external documentation, list any addendums, attachments etc.
Lack of standards has been a hinderance to incorporating DERs in a way that
is advantageous for the grid and hosting capacity is not currently incorporated
in the planning process that considers the capabilities of current technologies.
Clean Energy Fund projects II and III as well as interconnection of the eco-
district has revealed the shortcomings of the existing approach to DER
integration. The current approach creates barriers for adoption due to lack of
standardization. The return is represented in the ability to host DERs as is
needed to meet CETA and Avista clean energy goals. Because no assets are
being deployed, the return on investment comes from enablement of the WSU
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Microgrid and future asset integration which can help better utilize existing
capital investments.
2.2 Discuss how the requested capital cost amount will be spent in the current
year (or future years if a multi-year or ongoing initiative). (ie., what are the
expected functions,processes or deliverables that will result from the capital spend?). Include
any known or estimated reductions to O&M because of this investment.
How will the outcome of this investment result in potential additional 08A4 costs, employee or staffing
reductions to 0&\A(o$sets),etc.?
The total cost of the project is broken down to three phases as described below:
Phase 1 Avista implementation of WSU microgrid control system which aligns
with Avista standards and work artifacts. In this phase, the following tasks will
be performed by the end of the year 2022.
• Develop Control Standards and Specifications
• Develop offline model and load profiles
• Develop test procedure for controller
• Deploy Digital Exchange Platform catalog
Phase 2 Avista implementation of control and power hardware in the loop. The
tasks under this phase will be performed by the end of year 2022
• Program control for islanding, VVC in RTAC
• Testing scheme performance using HIL testbed
• Development of PHL for Inverter settings
• Digital Exchange Platform meta data
Phase 3 Avista will field deploy the microgrid control with new configuration
requirements. The tasks under this phase will be performed by the end of year
2023.
• Communications and physical control architecture for deployment
• VVC demonstrations on the microgrid
• Final demonstration and commissioning
• Digital Exchange Platform CIM modeling
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Operational standards will be developed in cooperation with operational and
engineering personnel on the deployment of solar inverters and microgrid
controllers.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
This project was proposed by WSU and the partner team to create a global
solution for DER integration. Avista joined due to the quality, focus, and
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methodology proposed by the project team and the need to establish
standards for operation as it relates to the WSU Microgrid and future DERs.
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.
[Descnbe ifit is a program or project and details about how often in a year,it becomes used and useful
(ie.,if transfer to plant occurs monthly,quarterly or upon project completion).]
The project was started in 2022 and complete by end of year 2023. The
project should transfer to plant by the end of 2023.
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 ofthe body of-vwrk.]
Mission: The UTASSIST project supports Avista's Mission by designing and
operationalizing a microgrid. The microgrid will "improve our customer lives
through innovative energy solutions.
Focus Areas: Our People: The UTASSIST project is creating design
standards, work plans and artifacts necessary to safely deploy microgrids for
our customers. Our customers: Microgrid assets can be coordinated to
improve system utilization of the grid and reduce cost to customers. Perform:
The microgrid assets illustrate Avista's ability to deploy sustainable services at
the edge of the grid. Invent: The microgrid will be a first of a kind and enable
the workforce to train on future projects.
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 UTASSIST microgrid control assets can be coordinated to improve system
utilization by leveling the load at the point of common coupling. If microgrids
assist in system utilization, they can be deployed across the system to offset
capacity constraints. The microgrid assets of solar, storage and controls can
be deployed to defer large capital investment. Often referred as non-wire
alternatives. The commission expectation is Avista would leverage non-wire
alternatives were cost beneficial.
2.8 Supplemental Information
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2.8.1 Identify customers and stakeholders that interface with the business case
Avista is interfacing with Washington State University as a partner to help fund and
specify the microgrid on their campus in Spokane.
2.8.2 Identify any related Business Cases
N/A
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
The steering committee is the Invent Council.
3.2 Provide and discuss the governance processes and people that will
provide oversight
The Invent Council will provide oversight and governance.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The Invent Council will review all change requests. The Avista Innovation lab
will resource the project and make decisions regarding prioritizing the work.
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4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the UTASSIST 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: �7�, Date: 02/13/2023
Print Name: John Z. Gibson
Title: Avista Innovation Lab Director &
Chief R&D Engineer
Role: Business Case Owner
Signature: /� Date: 03/14/2023
Print Name: Jason Thackston
Title: Senior Vice President Chief
Strategy & Clean Energy Officer
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
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DocuSign Envelope ID:5436073D-863D-4753-9184-B2FD69309C90
Telecommunication & Network Distribution Security
EXECUTIVE SUMMARY
Telecommunication and network distribution locations consist of towers and shelters found in
remote, rural,and difficult to reach mountain top locations.They serve as the backhaul to Avista's
control, customer, and back-office network connectivity and communication systems. They are
critical in providing telecommunication and network connectivity to and from Avista's data
center, system operations, field offices, and field staff. Vandalism, theft, or sabotage at any of
these locations would significantly disrupt Avista's ability to transmit telecommunication signals
and move data utilized daily by staff in offices and in the field across our service territory to
operate our gas and electric systems. Existing physical security measures are not adequate.
Federal agencies call for utilities to step up their physical security posture and take mitigating
steps that include physical protective security measures to reduce or minimize the impact of a
physical attack. These measures should be risk-based and layered to deter, detect, and delay an
attack or intrusion. While these federal agency warnings are specific to the protection of
electrical and gas infrastructure based on recent incidents across the country, the ancillary
infrastructure, such as telecommunication and network distribution locations, is concurrently at
risk. Physical security enhancements consist of fencing, gates, doors, cameras, sensors, and
access management systems. The proposed solutions will implement new or replace inadequate
security measures to mitigate the risk at these locations. These physical security enhancements
directly benefit our customers, as they allow Avista office and field staff to transmit
communication and data required to operate the safe and reliable delivery of electric and gas
service.
Investments in physical security hardening at Avista's telecommunication and network
distribution locations will reduce ongoing risk of theft,vandalism, or sabotage, as well as improve
the safety of field technicians who respond to these facilities during extreme weather conditions.
The requested amount of $112.5K per year allows Avista to continue a steady investment in
increased physical security hardening efforts across our service territory at one mountain top
location per year. Indirect offsets included avoided replacement costs based on an incident
occurring once every 20 years, which results in approximately $110K in costs per year over the
same 20-year period. This is a net neutral benefit in proactive investment versus a reactive
response following an incident, which brings great value to Avista and its customers by reducing
the risk of a system outage at these locations. Additional indirect offsets include avoiding or
reducing the number of trips in response to system alarms over the winter season. Not approving
this business case or its recommended funding amount can pose risks to the people and assets
Avista depends on to conduct business and deliver safe and reliable energy.
VERSION HISTORY
Version Author Description Date
Draft Andru Miller Initial draft of original business case 7/06/2020
1 Andru Miller Updated 5-year funding request 8/09/2022
2 Andy Leija Updated 5-year funding request 5/11/2023
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BCRT I Jeff Smith I Has been reviewed by BCRT and meets necessary requirements 5/30/2023
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GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2024 $112,500 $112,500
2025 $112,500 $112,500
2026 $112,500 $112,500
2027 $112,500 $112,500
2028 $112,500 $112,500
Project Life Span 5 years
Requesting Organization/Department Security
Business Case Owner I Sponsor Andy Leija I Clay Storey
Sponsor Organization/Department Enterprise Technology
Phase Execution
Category Program
Driver Performance & Capacity
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
Telecommunication and network distribution locations consist of towers and shelters found
in remote, rural, and difficult to reach mountain top locations. They serve as the backhaul
to Avista's control, customer, and back-office network connectivity and communication
systems, such as land mobile radio signal coverage, which provide connectivity and
coverage across our service territory. They are critical in providing telecommunication and
network connectivity to and from Avista's data center, system operations, field offices, and
field staff.
These mountain top locations are difficult to reach during the winter season thus providing
them natural protection, however they are not inaccessible other times of the year by
anyone motivated to reach them. Vandalism, theft, or sabotage at any of these locations
would significantly disrupt Avista's ability to transmit telecommunication signals and move
data utilized daily by staff in offices and in the field across our service territory to operate
our gas and electric systems. For example, our field staff, who are required to respond to
events throughout the year, depend on land mobile radios to establish situational
awareness and reduce the risk of a safety incident.Additionally,these sites contain network
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and telecommunication equipment that has direct access to Avista networks, thus an
undetected intrusion could give intruders unauthorized access to systems that can lead to
a cybersecurity event. Existing physical security measures at these telecommunication and
network distribution locations are not adequate. And while the probability of an attack at
one of these locations is low when compared to an urban infrastructure facility, the
consequence is high and thus calls for attention and investment. Moreover, federal
agencies are noticing an increase in the threat landscape for vulnerable infrastructure
locations.
1.2 Discuss the major drivers of the business case.
Performance & Capacity is the primary driver for the Telecommunications and Network
Distribution Location Security program business case as the projects it funds address
security risks by protecting these locations. Keeping the systems at these locations
performing is critical to support our day-to-day operations, which is the reason technicians
immediately deploy when alarms show that systems are down and require intervention.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
These remote unmanned locations, much like substations, have always had inherent risk.
However, based on a heightened awareness around growing threats of targeting electric
and gas utilities, mitigating this risk is important and thus one of Avista's strategic goals of
maturing its physical security program and emergency response system. 1 Understanding
that while each of these locations is critical, working as a mesh or system, no one location
is more important than another. However, some of these locations are more easily
accessible to the public than others, therefore investment in physical security
enhancements primarily focus on those with higher exposure. Deferring or not approving
the requested amount to address the identified security risks pushes the necessary
hardening at each location further into the future.
1.4 Discuss how the proposed investment, whether project or program,
aligns with the strategic vision, goals, objectives, and mission statement of
the organization. See link. Avista Strategic Goals
The Telecommunications and Network Distribution Location Security program business
case provides funding for security-related projects and aligns with Avista's strategic goal to
"affordably operate and maintain, safe, clean, reliable generation and energy delivery
infrastructure." A focus under this strategic goal is to mature Avista's physical security
program and emergency response.z
1 Our Goals 2023—Perform(sharepoint.com)
2 Strategy Scorecard. Board of Directors Meeting. February 2023.
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1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation, photographic
evidence, or other materials that explain the problem this business case will
resolve.
According to the Department of Homeland Security, Domestic Violence Extremist (DVE)
threat, which adheres to a range of ideologies, continues to grow, plot, and encourage
physical attacks against electrical infrastructure.' The Cybersecurity & Infrastructure
Security Agency(CISA) and the Department of Energy (DoE) call for utilities to step up their
physical security posture and take mitigating steps that include physical protective security
measures to reduce or minimize the impact of an attack. The physical security
enhancement should include a risk based, layered approach that dissuades a potential
attacker through visible security measures.4
While these federal agency warnings are specific to the protection of electrical and gas
infrastructure based on recent incidents across the country, the ancillary infrastructure
required to operate the safe and reliable delivery of electric and gas service is concurrently
at risk. This was evident in the Colonial Pipeline ransomware attack that resulted in a
shutdown of refined gas flow to the east coast for several days, causing chaos among the
public. Additionally, recently published warnings in the Annual Threat Assessment of the
U.S. Intelligence Community(Feb. 2023)clearly state that"China almost certainly is capable
of launching cyber-attacks that could disrupt critical infrastructure services within the
United States, including against oil and gas pipelines, and rail systems."' Therefore,
enhanced physical security measures are required to protect both physical and
cybersecurity risks.
s The Third Quadrennial Homeland Security Review(dhs.gov)
4 Sector Spotlight: Electricity Substation Physical Security(cisa.gov)
s ATA-2023-Unclassified-Report.pdf(odni.eov)
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2. PROPOSAL AND RECOMMENDED SOLUTION - Describe the proposed solution
to the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Characteristics for each telecommunication and network distribution location vary, such as
when it was built, the size, and location, as well as the risk posed to it. Investments under
this program business case are therefore risk based and the proposed physical security
enhancements are layered for each location. Physical security enhancements consist of
fencing, gates, doors, cameras, sensors, and access management systems. The proposed
solutions will implement new or replace inadequate security measures to mitigate the
increasing risk at these locations. Because of where these facilities are located, much of the
physical security enhancements are implemented during constructions season when access
to the locations is feasible. In addition to accessibility constraints,other construction season
projects can impact labor resource availability. Therefore, we continue to address the risk
at each of these locations one per year.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other information
that was considered when preparing this business case (i.e., samples of
savings, benefits or risk avoidance estimates; description of how benefits to
customers are being measured; metrics such as comparison of cost ($) to
benefit (value), or evidence of spend amount to anticipated return).6
There are over two dozen telecommunication and network distribution locations across our
service territory. The funding request is based on historical costs for previous physical
security enhancements at a telecommunication and network distribution location. The
costs consist of product replacement, professional services, and labor.
While an actual threat has not occurred at any of these sites to date, the probability is
increasing as reported by federal agencies.'And while an attack at one of these locations is
low in comparison to an urban infrastructure location, the impact is high. Therefore,
assuming that one telecommunication and network distribution location was attacked over
a period of twenty years, the replacement cost of equipment, plus delivery up to a
mountain top would be on the high side of the estimate or around $2.21VI. The amortized
costs over the same 20-year period, would result in approximately $110K per year or
equivalent to the cost of investment, which is $112.5K per year, to reduce this risk.
6 Please do not attach any requested items to the business case, be sure to have ready access to
such information upon request.
'https://www.dhs.jzov/sites/default/files/2023-04/23_0420P1cy 2023-ghsr.pdf
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The physical security investment is but a fraction of the cost associated with the technology
that is being protected, which includes enclosed equipment and that which is mounted on
the tower. While the replacement of the equipment is on average $1.85M per location, the
cost to deliver it to a mountain summit and install it can triple the cost of the equipment,
which can include trailering it up very steep mountain logging roads or flying it in via
helicopter.
In addition to the costs associated with a breach, there are operational savings from
telecommunication technicians using the installed video cameras to inspect the equipment
before rolling a vehicle up to the mountain top. Utilizing video footage from a mountain top
in the middle of winter can prevent a trip or prepare the technicians for the weather
conditions, as well as the tools necessary to address the issue reducing their personal safety
risk. Annual indirect offsets can average $22.21K per year from avoiding trips up to repair
mountain top equipment.
The ability for Avista office and field workers to communicate with one another and for
systems to transmit information and data required to operate our electric and gas systems
brings direct benefits to our customers. So, while our electric and gas infrastructure can
continue to provide service,the data that is carried on these networks is necessary to assure
it is provided safely and reliably.
2.3 Summarize in the table and describe below the DIRECT offsets$ or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital N/A $0 $0 $0 $0 $0
O&M N/A $0 $0 $0 $0 $0
There are no direct offsets associated with investments in physical security enhancements
in telecommunications and network distribution locations. Doing nothing is not an option,
especially as threats grow.
2.4 Summarize in the table and describe below the INDIRECT offsets9
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital Telecommunication $370,000 $370,000 $370,000 $370,000 $370,000
System replacement
8 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
9 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
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O&M Mountain top repairs $22,260 $22,260 $22,260 $22,260 $22,260
Indirect offsets are the avoided costs from a physical and cyber security breach resulting
from an intrusion or attack at one of these locations. Depending on the severity of the
breach, the costs can vary from simple repairs to larger replacements. Using historical costs
for technology system upgrades to a land mobile radio location on a mountain top,
including the replacement of tower antennas, it is between $1.5M - $2.21M, or an average
of $1.85M. Assuming the full capital replacement cost amortized over 5 years, the annual
cost is $370k. Based on an $112.5k annual allocation, the benefit is $257.5k per year.
In addition to the costs associated with a breach, there are operational savings from
telecommunication technicians using the installed video cameras to inspect the equipment
before rolling a vehicle up to the mountain top. Utilizing video footage from a mountain top
in the middle of winter can prevent a trip or prepare the technicians for the weather
conditions, as well as the tools necessary to address the issue reducing their personal safety
risk. On average, Avista's technicians make 6-9 trips to a mountain top per year to respond
to an outage alarm. Each trip consists of 2-3 technicians a minimum of two days utilizing
daylight for safety (visibility and warmer temperatures). The trip requires multiple vehicles
to the trailhead, whereby the logging roads are traveled via snowcat or snowmachines to
the mountain top. Based on this information, 3 technicians traveling 7 times each year for
2 days, with no overtime pay and an average cost of $300 in fuel per incident equals
($60/hour x 8 hours a day x 2 days x 3 technicians x 7 incidents) = $20,160 per year plus
$2,100 in fuel costs is $22,260 total indirect savings. This operational expense can instead
be performing preventative maintenance or project related assignments and reducing
personal safety risk for each responding technician.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, which were considered, and why those alternatives did not provide
the same benefit as the chosen solution. Include those additional risks to
Avista that may occur if an alternative is selected.
Option Capital Cost Start Complete
Address security at telecommunication and network $562,500 012024 122028
distribution locations as funding allows, with a
minimum of one site per year (Recommended)
Address security at telecommunication and network $2,250,000 012023 122033
distribution locations in 10 years or at 2 locations
per year.
Address security at telecommunication and network $2,362,500 012023 062030
distribution locations in 7 years or at 3 locations per
yea r.
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Alternative 1: The recommended alternative is to invest in one mountain top location per
year.This amount is based on historical costs from previous physical security enhancements
at telecommunication and network distribution locations. It also considers construction
season and labor constraints. Like other physical security protective measures, the
investments identified are risk-based and layered, addressing the higher risk locations with
easier public access. This steady investment amount keeps continuous improvements at
these locations and reduces risk accordingly. However, should additional funding be
identified, or risks increased increasing the priority of this work during construction season
over other, physical security enhancements at a higher number of locations should be
considered over the same 5-year period.
Alternative 2: Extending the physical security enhancements at over two dozen locations
in a 10-year period results in two mountain top locations per year.This doubles the number
of locations from the recommended amount, cutting the timeframe from two decades in
half. This was the original recommended amount when this business case originated.
However, after recognizing that other higher priority projects also competing for
construction season and constrained resources,this recommended alternative became the
next best option.
Alternative 3: Addressing the over two dozen locations in a 7-year period, assumes that
physical security enhancements at 3 mountain top locations per year can be achieved by
the project teams. While this is logistically possible, the previously identified constraints
would make this incredibly challenging unless other higher priority projects during the
construction season waned and labor became available.
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
Physical security enhancements at telecommunication and network distribution locations
are necessary to maintain the identified high-risk locations safe, secure, and reliable.
Metrics to demonstrate the success of the investments under this program business case
include averted physical threats, reduction in problem location incidents, and keeping this
equipment available and reliable to aid in deterring, detecting, and delaying an intrusion.
Avista tracks physical security incidents and will monitor for a reduction in incidents,
especially at historically high risk and problem locations that have implemented physical
security enhancements.
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2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
The Telecommunication and Network Distribution Location Security business case is a
program that consists of multiple security projects per year that run concurrently, and at
times over multiple years. They follow all phases of the project lifecycle, facilitated by a
project manager, and governed by a steering committee to determine scope, schedule, and
budget forecasts, including transfers-to-plant.
2.8 Please identify and describe the Steering Committee/governance team
that are responsible for the initial and ongoing approval and oversight of the
business case, and how such oversight will occur.
There are two levels of governance to the Telecommunication and Network Distribution
Location Security program business case and the investments within it. They consist of a
business case governance team and project specific steering committees for in-flight
projects.
Business Case Governance Team: The Enterprise Security Governance Team provides
monthly oversight of this program business case and makes recommendations based on
forecasted inactive planned investments, the pace of in-flight investments, and any new
unplanned activity that surfaces from an emerging security threat. The team also tracks
business case risks and issues that can affect the portfolio of planned investments.
Monthly governance meetings consist of a full review of each in-flight investment, reasons
for any delays or deviation to proposed completion and transfers to plant schedules and
recommends necessary steps to bring the investments back into schedule or defer inactive
work, when possible, to offset delays. However, should a security risk increase by deferring
a planned or unplanned investment into future years, the Enterprise Security Governance
Team will recommend a Capital Planning Group (CPG) In-Year Change Request to surface
the impending need.The Change Requests are presented at a monthly Technology Planning
Group meeting to inform the Director members who are also members of the CPG where
the request will be considered and weighed against other pending requests.
The Enterprise Security Governance Team consists of Avista's Enterprise Security Director,
Cybersecurity Manager, Physical Security Manager, Security Delivery Manager, and the
Project Management Office Manager. The sessions are facilitated by the Security Program
Manager who manages the standing agenda.
Project Steering Committees: Additionally, each security investment is governed by a
project steering committee that consists of the Enterprise Security Director, Cybersecurity
Manager, Physical Security Manager, and Security Delivery Manager, as well as ancillary
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management team members required for the successful implementation of the security
enhancement at the respective location. Steering committee meetings are facilitated by a
Project Manager and held monthly to review scope, schedule, budget, and risks and issues
surfaced from each in-flight project.
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3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Telecommunication & Network
Distribution Location Security business case and agree with the approach it presents.
Significant changes to this will be coordinated with and approved by the undersigned or
their designated representatives.
DocuSigned by:
Signature: -�2�„ Date: Tun-12-2023 1 10:56 AM PDT
6456C8EEF402467..
Print Name: Hnay t_elja
Title: Security Delivery Manager
Role: Business Case Owner
DocuSigned by:
Signature: sfb" Date: 3un-12-2023 111:30 AM PDT
95F7961D4B6
Print Name: clay Storey
Title: Security Director
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
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Upper Falls — Trash Rake Replacement
EXECUTIVE SUMMARY
The trash rake has, since its installation, presented an environmental risk due to the hydraulic
system that utilizes to function. When in use, the hydraulic system is suspended over the Upper
Fall unit intake and the Spokane River. Should a hydraulic line fail during raking operation,
some amount of hydraulic fluid would end up in the river, leading to an environmental cleanup
exercise. The current trash rake is undersized, leading to issues during raking operations. Often,
the rake stalls out mid-operation due to the weight of accumulated debris it is trying to recover.
The rake is also limited in its ability to lift logs and tress which can accumulate in front of the
rakes, leading to potential personnel safety issues with operators being required to cut up the logs
and trees while in very close proximity to the river's edge. Often times this is an operator
leaning out over the handrail to address the problem. A safety action item was identified in 2016
related to the conveyor system that the trash rake utilizes to accumulate cleaned debris into a
dumpster. This conveyor system, at the time posed a personnel safety threat due to its open
operating nature. The risk of someone becoming entangled in the operating conveyor system
drove a safety switch to be installed.
The recommended alternative is to replace the trash rake with an appropriately sized system that
will allow full reach of the intake racks and accommodate large sized trees and logs to be
removed from the river. This alternative would either replace the conveyor belt system with a
new and safer alternative type of debris conveyance system or would remove that system
entirely. This alternative is likely to be a packaged device with modern controls and electrical
systems. The overall project cost of this alternative is estimated at $1,500,000. Should this
project be delayed, the operational safety and environmental issues would still be present, posing
associated risks into the future.
VERSION HISTORY
Version Author Description Date Notes
1.0 PJ Henscheid Format existing BC into exec summary 7.2.20 5-year Capital Planning
Process
2.0 PJ Henscheid Completion of full BCJN document 8.4.20 5-year Capital Planning
Process
Business Case Justification Narrative Page 1 of 8
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Upper Falls — Trash Rake Replacement
GENERAL INFORMATION
Requested Spend Amount $1,500,000
Requested Spend Time Period 2 years
Requesting Organization/Department J07/GPSS
Business Case Owner I Sponsor PJ Henscheid Andy Vickers
Sponsor Organization/Department A07/GPSS
Phase Initiation
Category Project
Driver Asset Condition
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The major driver for this business case is asset condition. The existing trash rake at
Upper Falls is an articulating arm Atlas Polar device.
The trash rake has, since its installation, presented an environmental risk due to the
hydraulic system that utilizes to function. When in use, the hydraulic system is
suspended over the Upper Fall unit intake and the Spokane River. Should a
hydraulic line fail during raking operation, some amount of hydraulic fluid would end
up in the river, leading to an environmental cleanup exercise. While the rake is in
its parked position, the hydraulic system is in very close proximity to the river and
poses a threat to leaking.
The current trash rake is undersized, leading to issues during raking operations.
Often, the rake stalls out mid-operation due to the weight of accumulated debris it
is trying to recover. The rake is also limited in its ability to lift logs and tress which
can accumulate in front of the rakes, leading to potential personnel safety issues
with operators being required to cut up the logs and trees while in very close
proximity to the river's edge. Often times this is an operator leaning out over the
handrail to address the problem.
A safety action item was identified in 2016 related to the conveyor system that the
trash rake utilizes to accumulate cleaned debris into a dumpster. This conveyor
system, at the time posed a personnel safety threat due to its open operating nature.
The risk of someone becoming entangled in the operating conveyor system drove
a safety switch to be installed.
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Upper Falls — Trash Rake Replacement
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 for this business case is Asset Condition. Having an effective and
reliable trash cleaning device is imperative for the continued efficient operation of
our Hydro generating units. Replacing this trash rake will not only provide for the
safety of our operations staff, but will encourage the reliable operation of Upper Falls
HED which contributes to the successful implemtnation of our Spokane River
license.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
This work is needed to address the personnel safety issues related to the converyor
system of the existing trash rake as well as address the potential environmental
risks present with the existing design. Both of these risks remain if this work is
deferred or not performed.
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.
Continued effective operation of upper falls hed will signify successful
implementation of this project, but more importantly addressing the personnel safty
risks as well and the environmental risks present in the current design will determine
project success.
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.
Knuckle Boom Marginal 4.67
Trashrake -EA Marginal 4.00
The above table is from the Net Condition Index and Rating summary. This information
was compiled during the maintenance assessment of all Hydro assets performed in
2018. As shown, the condition of both the knuckle boom and trash rake are currently
marginal, and do take into account the safety and environmental risks.
The recommended alternative is to replace the trash rake with an appropriately sized
system that will allow full reach of the intake racks and accommodate large sized
trees and logs to be removed from the river. This alternative would either replace
the conveyor belt system with a new and safer alternative type of debris conveyance
system or would remove that system entirely. This alternative would likely still utilize
hydraulics to function, however, a robust containment system would be required and
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Upper Falls — Trash Rake Replacement
modern control system can detect and shut off the system when a leak is identified,
often resulting in very small amount of leakage reaching the waters surface. This
alternative is likely to be a packaged device with modern controls and electrical
systems.
This alternative would likely include some amount of concrete work to facilitate and
support the installation of a new trash rake. This could also include some concrete
demolition and removal and replacement of embedded components.
This alternative would allow for reliable and safe operation and cleaning of the intake
racks at Upper Falls, and would take into full consideration all personnel safety
issues highlighted to date, as well as identify and address other possible safety
issues.
This alternative is anticipated to begin in 2023, with an engineering assessment
design starting that year. Construction could start as soon as early fall 2024. The
project is anticipated to be transferred to plant sometime in 2025.
Option Capital Cost Start Complete
Repace Upper Falls Trash Rake $1,500,000 01/2023 12/2024
Alt 1: Do Nothing $0 NA NA
2.1 Describe what metrics, data, analysis or information was considered
when preparing this capital request.
Data compiled from the replacement of the trash rake at Nine Mile in 208 helped to
inform this capital request. It is anticipated the new trash rake at Upper Falls could
be very similar in nature, both in scope of supply and operationally, to what was
installed at Nine Mile.
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.
Some O&M cost savings are anticipated to be realized as a result of this project in
reducing the amount of repairs and maintenance need to be performed on the trash
rake. Also, the intent of the new design would allow for a safe and effective one
person cleaning operations instead of the current practice of two operations
personnel.
2023— Engineering design and procurement of some of the equipment is anticipated
2024 — Completion of procurement and construction is anticipated
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Upper Falls — Trash Rake 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.
Operations and Power Supply will be impacted by this business case during
implementation. Upper Falls generating unit will be required to be off-line during the
totality of construction. This will affect plant operations and power supply, and will
require all river flows to pass through the Control Works spillgates. The duration of
construction activities is unknown at this time.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Alternative 1 — Do Nothing
This alternative would not allow for improving the functionality of the trash
rake nor remove any of the safety risks associated with the existing rake.
The major risk associated with this alternative is the unreliable operation and
personnel safety and environmental risks associated with the existing
design. This alternative would continue to affect the Operation and
Maintenance budget as repairs continue to be an issue and the equipment
continue to age. Downtime for the plant could likely increase if outages of
the trash rack increase due to age.
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.
Design efforts would kick off in 2023, with vendor selection, site visits and
design analysis. Design should be completed by mid to late 2023, and
propcurement of equipment would commence. The majority of the scope of
supply is anticipated to be delivered in early 2024, with construction activities
starting as early as June of 2024 — following spring run-off. Construction is
anticipated to take most of the summer and fall of 2024, with an anticipated
transfer to plant of the entire project of the end of 2024.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
The delivery of this project is highly important in the sustainability and operations
of our Spokane river facilities and operating them safely and responsibly. The
project will focus of the people responsible the delivering with a strong emphasis
on performance. This nature of the project demands a collaborative environment
with the wide array of key stakeholder groups. This will address personnel safety
issues, environmental concerns, and unit reliability all at the same time.
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Upper Falls — Trash Rake Replacement
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 project budget and total cost will be regularly reviewed with the project
steering committee, as well as, receive approvals as described below for any
changes in scope and cost. Prudency is also measured by remaining in
compliance the FERC License such that we can continue to operate Spokane
River dams for the benefit of our customers and company.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
- GPSS Engineering; Civil, Mechanical, Electrical and Controls
- Hydro Operations
- Environmental, Permitting, and Licensing
- Master Scheduler
- Asset Management
- Project Accounting, Finance, and Rates
- Supply Chain and Legal
- Corporate Communications
- Construction Inspection and Project Management
2.8.2 Identify any related Business Cases
This project has no other relevant business cases.
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Upper Falls — Trash Rake Replacement
3.1 Steering Committee or Advisory Group Information
The advisory group for this project will consist of members from the Generation
Production and Substation Support department, Power Supply, and the
Environmental department. Specific individuals of the steering committee will be
selected at a later date by the GPSS leadership team. Advisors are provided with
monthly project status reports but, are only convened in the event of a necessary
decision point.
3.2 Provide and discuss the governance processes and people that will
provide oversight
The project will be led by the core project team. Any changes to scope, schedule
and budget will be submitted for approval to the steering committee
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
The projectis anticipated to utilize the Project Change Log to track and manage all
Project Change Requests (PCR) associated with the delivery of the construction
project. The PCR describes the need for change, supplemental documentation,
related project artifacts, change order proposals, and any other pertinent
information. PCR's are then signed for approval by the project approval thresholds,
and then processed against the project risk registry, and or contract amendment
with the contractor.
The undersigned acknowledge they have reviewed the Upper Falls Trash Rake
Replacement 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: 8/4/20
Print Name: PJ Henscheid
Title: Mgr, Civil and Mechanical Engr
Role: Business Case Owner
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Signature: Date: 8/4/2020
Print Name: Andy Vickers
Title: Director, GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Template Version: 05/28/2020
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