20250131Direct D. Howell_Exhibits.pdf

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

1 I. INTRODUCTION
2 Q. Please state your name, employer and business address.
3 A. My name is David R. Howell and I am currently employed as the Director of
4 Generation Production and Substation Support for Avista Corporation (Avista or Company).
5 My business address is 1411 East Mission Avenue, Spokane, Washington.
6 Q. Would you briefly describe your educational background and
7 professional experience?
8 A. Yes. I graduated from Washington State University in 1992 with a B.S. in
9 Mechanical Engineering and earned my EMBA from the University of Washington in 2012.
10 I am a registered professional engineer in the State of Washington for both electrical and
11 mechanical engineering. I joined the Company in 2005 after spending five years with
12 TransCanada-GTN. Between 2005 and 2015, I held various positions at Avista supporting
13 both natural gas and electric operations,including Gas Design Engineer,Gas Design Manager,
14 Gas Compliance Manager, Operations Manager, and Director of Gas Delivery.
15 In 2015, I transitioned to support the electric business as the Director of Electrical
16 Engineering. I became the Director of Electric Operations in 2016, where my primary
17 responsibilities included the management and oversight of Avista's 13 operating districts,
18 responsibility for construction services and design, as well as the Asset Maintenance and
19 Wildfire teams. In 2023 I transitioned to the Director of Generation Production and Substation
20 Support (GPSS) where I am responsible for the safe and reliable operation of our substation
21 and generating assets.
22 Q. What is the scope of your testimony in this proceeding?
23 A. I will provide an overview of the Company's planned investments in our
24 generating facilities and explain the factors driving our continuing investment in these assets.
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I I will explain how our efforts to maintain the health and performance of our assets, including
2 compliance with mandatory federal standards, are driving a continuing demand for new
3 investment. I will also explain how and why we have realigned our critical resources to
4 support our effort to optimize our generating fleet. Additionally, I will describe our
5 environmental affairs projects that support compliance with and management of the licenses
6 issued by the Federal Energy Regulatory Commission authorizing the Company to operate its
7 hydroelectric facilities. While I address these capital additions for the periods July 1, 2024,
8 through August 31, 2027 in detail within my testimony and exhibits, Company witnesses Ms.
9 Benjamin and Ms. Schultz incorporate the capital additions, and incremental expense
10 associated with these investments,within the Company's request for rate relief over the Two-
11 Year Rate Plan effective September 1, 2025.
12 A table of contents for my testimony is as follows:
13 Description Page
14 I. Introduction 1
15 II. Overview of Generation Production Capital Investment Strategy 2
16 III. Overview of 2024—2027 Generation Production and
17 Environmental Capital Projects 6
18
19 Q. Are you sponsoring any exhibits?
20 A. Yes. Exhibit No. 7, Schedule 1 is Avista's Generation Production and
21 Environmental Capital Business Cases for the July 2024 — December 2027 generation and
22 environmental projects, all of which are discussed later in my testimony.
23
24 IL OVERVIEW OF GENERATION PRODUCTION CAPITAL INVESTMENT
25 STRATEGY
26
27 Q. Company witness Mr. Christie identifies and briefly explains the six
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I "Investment Drivers" or classifications of Avista's infrastructure projects and
2 programs. How then do these "drivers" translate to the capital expenditures that are
3 occurring in the Company's generation area?
4 A. The Company's six Investment Drivers are briefly described as follows:
5 1. Customer Requested — Respond to customer requests for new service or
6 service enhancements required for connecting new distribution customers or
7 large transmission-direct customers. This driver is generally not applicable to
8 Generation.
9
10 2. Mandatory and Compliance — These investment drivers are compelled by
11 regulation or contract and are generally beyond the Company's control as they
12 are a direct result of compliance with laws, regulations and agreements,
13 including projects related to dam safety upgrades, public safety, air and water
14 quality, and equipment essential to legally operating within the interconnected
15 grid among others.
16
17 3. Failed Plant and Operations — This investment driver includes the
18 replacement of equipment that is damaged or fails due to an accident,or normal
19 wearing out requiring periodic replacement. The large, massive rotating
20 equipment and associated support machinery used for electric generation can
21 experience sudden mechanical failures or electrical insulation breakdowns
22 even with the benefit of ongoing maintenance and preventive maintenance
23 programs.
24
25 4. Asset Condition—Replace infrastructure assets or portions of assets at the end
26 of their functional service life based on asset condition due to age,
27 obsolescence and parts availability,and degradation of the asset. This category
28 includes replacement of critical parts requiring replacement prior to failure, as
29 well as replacing or overhauling older equipment to bring it up to meet current
30 codes and standards.
31
32 5. Customer Service Ouality and Reliability — Meet our customers'
33 expectations for quality and reliability of service, as well as increasing the
34 reliability of operating assets.
35
36 6. Performance and Capacity — Programs and projects to address system
37 performance and capacity issues so Company assets can continue to satisfy
38 business needs and meet performance standards to support the interconnected
39 grid and to ensure the ability to participate in the regional wholesale energy
40 market.
41
42 The primary investment drivers for generation projects include Mandatory and
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I Compliance, Failed Plant and Operations, Asset Condition, Customer Service Quality and
2 Reliability, and Performance and Capacity.
3 Q. What is Avista's Generation Capital Investment Strategy?
4 A. Avista's generation capital investment strategy is to modernize the generation
5 fleet for optimal performance. Modernization includes upgrading assets to current and
6 anticipated future performance standards. Optimal performance in this case would also
7 include broadening generation operating ranges to support system renewable integration and
8 increased load variation at the most reasonable cost.
9 Q. Will you please explain the accelerated asset improvement plan?
10 A. The plan will include a steady increase in capital deployment over the course
11 of the next 3-5 years.Traditional capital spend for Avista's generation assets has been between
12 $40 million - $45 million annually (system), but that will need to increase in coming years.
13 This typically includes the normal wear and tear investment needed to maintain operation and
14 one to two generator modernization projects each year. Unfortunately, the asset degradation
15 rate has outpaced the rate of modernization, leaving power generating units at risk for
16 decreased reliability.
17 Q. What is the primary driver for the modernization strategy?
18 A. The primary driver however is asset condition. Avista continues to operate a
19 legacy system which requires increased attention to, and investment in, generating
20 resources. Avista's generating fleet is comprised of assets that range from up to 45 to 120
21 years in operation. Most assets of this size are intended to have 50-60 year life spans. Due to
22 age, criticality, and potential catastrophic failure in the event of loss, it is imperative that
23 Avista continue to invest in these assets in a responsible way. While we are focused first on
24 our most `at risk' assets (those with the greatest risk of failure or the greatest consequence of
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I failure), the Company also needs to continue to invest in our newer assets as well to ensure
2 that they also continue to provide reliable service.
3 To minimize the immediate impact on generation availability and cost to our
4 customers, we have had to rethink the way we replace, repair, and maintain our assets. In
5 GPSS, we have redistributed the workforce to align with the specific needs of each facility
6 and to support our plants and keep them available while they wait for wholesale upgrades. We
7 have coordinated our maintenance efforts with our replacement schedules to assure
8 availability and assigned engineering resources to smaller projects critical to plant availability
9 yet still aligned with the overall optimization initiative. We have classified this ongoing work
10 into three new business cases based on the type of work or the driver for the work:
11 Operational Sustainment—this is the ongoing capital investment our plants need
12 to stay operational and available to our customers. Due to the large nature of our
13 assets, most of them end up being capital expenditures even if they are relatively
14 simple "replace in kind" efforts.
15
16 Asset Lifecycle Management— this program supports the various plant projects
17 within all the Avista-owned generating facilities. These projects are fairly routine
18 and time-based projects intended to extend the life of a system or an asset. The
19 projects are not intended to replace the full system, but rather bring the system
20 back to its original performance objective.
21
22 • Operational Safety and Compliance — This program supports the various
23 compliance and safety-related projects within all of the Avista-owned generating
24 facilities.
25
26 Beyond these efforts are the larger project investments. These projects are supported with an
27 appropriate project manager (based on the project type, impact, and complexity) and rely on
28 both engineering consultants and internal engineering for design and design review to ensure
29 compliance with Avista standards. Whether large or small, these projects are each supported
30 by a Business Case, as contained in Exhibit No. 7, Schedule 1.
31
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1 III. OVERVIEW OF 2024—2027 GENERATION PRODUCTION AND
2 ENVIRONMENTAL CAPITAL PROJECTS
3
4 Q. Please discuss the capital investments you sponsor included in the
5 Company's Two-Year Rate Plan.
6 A. As discussed by Company witnesses Ms. Schultz and Ms. Benjamin, Avista's
7 capital witnesses, including myself, describe the capital projects included in the Company's
8 proposed Two-Year Rate Plan, reflecting pro forma ("PF") capital additions for the period
9 between July 1, 2024 and August 31, 2027. For the generation projects, my testimony and
10 Exhibit No. 7, Schedule 1 provides an overview of the need for the investments made and
11 detail how those projects benefit our customers.
12 Q. Please describe the capital planning process that Generation Production
13 and Substation Support (GPSS) conducts before generation capital projects are
14 submitted to the Capital Planning Group.
15 A. The capital planning process in GPSS consists of a long-range forecast, a five-
16 year forecast, and an execution plan. Descriptions of each phase of the planning process
17 follows. The Company's long-range forecasting uses IBM's Maximo and Oracle's Primavera
18 Cloud (OPC) enterprise asset management software as the central repository for projects and
19 their associated elements. Projects can be added to the long-range forecast database in several
20 ways:
21 • Informal project requests;
22 • Input from asset life cycle, condition, needs assessment;
23 • Periodic reports from Maximo of open corrective maintenance work orders;
24 • Periodic reports from Maximo of scheduled preventive maintenance work orders;
25 • Annual maintenance requirements;
26 • Regulatory mandates;
27 • Project change requests, drop ins, budget changes, etc.;
28 • Formal project request applications; and
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I • Efficiency and IRP-related upgrades.
2 The GPSS management team meets monthly to review and prioritize new project requests,
3 scope prudent solutions, and review the long-range forecast.
4 The GPSS management team participates in an annual workshop in preparation for the
5 budget cycle to prioritize the projects included in the five-year horizon. As projects for the
6 next year are assigned,any capacity or budget constraints are identified, and project schedules
7 are adjusted accordingly by the GPSS Management Team. GPSS management and key
8 stakeholders meet monthly at the Generation Coordination Meeting, the GPSS coordinated-
9 team meeting, and specific program or project steering committee meetings to discuss the
10 progress of projects and any proposed changes to the execution plan. Adjustments and
11 decisions are made at these meetings.
12 Q. For the capital additions in the 2024 through 2027 timeframe, for which
13 you are responsible, is the Company seeking to include all those investments in general
14 rates in this case?
15 A. Yes. The Company is providing more detailed information in testimony and
16 exhibits related to the projects completed since the end of the test year(twelve-months ended
17 June 30, 2024) and over the proposed Two-Year rate Plan beginning September 1, 2025,
18 through August 31,2027. Details about the generation-related capital projects over the period
19 included in this case are discussed below. Table No. 1 below provides the system cost of each
20 generation capital project pro formed in this case for the July 1,2024 through August 31,2027
21 time period.
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I Table No. 1: 2024 through 2027 Maior Generation Capital Proiects
2 Generation Production and Environmental Capital Projects(System)In$(000's)
Rate Year 1 Rate Year 2
3 July 2024- Sept 2025- Sept 2026-
Line# Business Case Name Investment Driver August 2025 Aug2026 Aug2027
4 1 Asset Lifecycle Management Asset Condition $ 2,538 $ 3,628 $ 5,440
2 Automation Replacement Customer Service Quality&Reliability - - 2,250
5 3 Boulder Park Engine Controls Upgrade Asset Condition 2,500 2,790 -
4 Cabinet Gorge Dam Fishway Mandatory&Compliance 537 -
5 Cabinet Gorge HVAC Replacement Asset Condition 2,981 -
6 6 Cabinet Gorge Station Service Asset Condition 18,190 171
7 Cabinet Gorge Stop Log Replacement Asset Condition 1,980 - -
7 8 Clark Fork Settlement Agreement Mandatory&Compliance 2,938 2,664 3,122
9 Coyote Springs 2 CT Rotor Replacement Faded Plant&Operations - 19,583 -
10 CS2 Low Pressure Evaporator Replacement Asset Condition - - 3,799
8 11 HMI Control Software Asset Condition 3,276 3,650 5,554
12 Hydro Safety Minor Blanket Mandatory&Compliance 230 - -
13 KF 4160 V Station Service Replacement Asset Condition 722 1,541
9 14 KF Secondary Superheater Replacement Asset Condition 3,401 - -
15 KF-Ash Landfill Expansion Mandatory&Compliance - 10,189
10 16 KF_ID Fan&Motor Replacement Asset Condition 3,360 -
17 Little Falls Plant Upgrade Asset Condition 566
18 Long Lake Plant Upgrade Asset Condition 300
11 19 Nine Mile Unit 3 Mechanical Overhaul Asset Condition 6,903 -
20 Nine Mile Units 3&4 Control Upgrade Asset Condition 2,200 - 5,122
12 21 Noxon Rapids Gantry Crane Modernization Asset Condition - 19,494 -
22 Noxon Rapids Unit 5 Turbine Runner Replacement Asset Condition - 499 -
23 Operational Safety and Compliance Mandatory&Compliance 3,837 2,907 1,267
13 24 OperationalSustainment Performance&Capacity 6,126 8,066 16,283
25 Peaking Generation Business Case Failed Plant&Operations 372 - -
26 Post Street Substation Crane Rehab Asset Condition 1,080 702
14 27 Regulating Hydro Asset Condition 1,235 - -
28 Spokane River License Implementation Mandatory&Compliance 896 1,040 973
15 Total Planned Generation Production and Environmental Capital Projects $ 66,166 $ 66,733 $ 54,000
16 Q. Would you please explain the generation capital projects included in this
17 case for 2024 through 2027?
18 A. Yes. The capital projects include generation capital investments grouped as
19 Mandatory and Compliance, Failed Plant and Operations, Asset Condition, Performance and
20 Capacity, and the Customer Service Quality and Reliability investment categories. Brief
21 descriptions of each project, the reasons for the projects, and the timing of the decisions
22 follow. Additional details can be found in Exhibit No. 7, Schedule 1 Generation and
23 Environmental Capital Project Business Cases.
24 Asset Lifecycle Management (July 2024-Aug. 2025: $2,538,000, RY1: $3,628,000, RY2:
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1 $5,440,000)
2 This program will support the various plant projects within all the Avista-owned generating
3 facilities. These projects are routine and time-based projects intended to extend the life of a
4 system or an asset. They are not intended to replace the full system but instead bring the
5 system back to its original performance and objective. This program is critical in continuing
6 to support asset management program lifecycle replacement schedules.Identified projects will
7 be governed by the Plant Manager, Operations Engineering Manager, and Senior Operations
8 & Maintenance Manager. The GPSS Operations team will coordinate and manage a 5-year
9 plan of identified projects needed to sustain the safe, reliable, affordable operations of the
10 Avista-owned generation fleet.
11
12 Automation Replacement (July 2024-Aug. 2025: $0, RY1: $0, RY2: $2,250,000)
13 The Automation Replacement project systematically replaces the unit and station service
14 control equipment at our generating facilities with a system compatible with Avista's current
15 control standards for reliability. Upgrading control systems within our generating facilities
16 allows us to continue providing reliable energy. The Distributed Controls Systems(DCS)and
17 Programmable Logic Controllers (PLC) are used to control and monitor Avista's individual
18 generating units as well as each total generating facility. The DCS and PLC work in this
19 capital program is needed to reduce the higher risk of failure due to the age of the currently
20 installed equipment. The current DCSs are no longer supported, and availability of spare
21 modules are limited. The modules in service have a high risk of failure as they are over 20
22 years old. Avista's hydro facilities were designed for base load operation but are now
23 increasingly called on to quickly change output in response to the variability of wind and solar
24 generation, to adjust to changing customer loads, other regulating services needed to balance
25 system load requirements and assure transmission reliability and EIM operations.The controls
26 necessary to respond to these new demands include speed controllers (governors), voltage
27 controls(automatic voltage regulator a.k.a. AVR),primary unit control system(i.e. PLC), and
28 the protective relay system. In addition to reducing unplanned outages, these new systems
29 allow Avista to maximize ancillary services for its own assets on behalf of customers rather
30 than procuring them from other providers. All new work of this type planned in 2024 and
31 beyond will occur under the new Operational Sustainment Business Case.
32
33 Boulder Park Engine Controls Upgrade (July 2024-Aug. 2025: $2,500,000, RY1:
34 $2,790,000,RY2: $0)
35 The engines at the Boulder Park Generating Station have suffered multiple control module
36 component failures over the years on the WECS8000 (Wartsila Engine Control System).
37 These modules are on each of the six generating units and are critical to their operation. Spare
38 parts are no longer available from the station's existing inventory of spare parts and the
39 manufacturer no longer offers support for the WECS8000. To ensure generation reliability,
40 the entire control system needs to be replaced for all six units. The replacement of the control
41 modules at Boulder Park Generating Station will benefit customers by making the generating
42 station more reliable.Being proactive in the replacement allows for equipment to be purchased
43 and designed in preparation for a planned outage,to minimize the outage as much as possible.
44
45 Cabinet Gorge Dam Fishway (July 2024-Aug. 2025: $537,000, RY1: $0, RY2: $0)
46 The Clark Fork Settlement Agreement (CFSA), incorporated into the Clark Fork FERC
47 License, requires Avista to implement the Native Salmonid Restoration Plan (NSRP), which
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I includes a stepwise approach to investigating, designing, and implementing fish passage at
2 the Clark Fork Project. Appendix C of the CFSA commits Avista to fund Fishway design and
3 construction as well as annual operations. Fish passage is intended to restore connectivity of
4 native salmonid species in the lower Clark Fork watersheds. During relicensing, the U.S.Fish
5 & Wildlife Service (USFWS) reserved its authority under Section 18 of the Federal Power
6 Act to require fish passage at both Noxon Rapids and Cabinet Gorge dams, to pursue the
7 NSRP more collaboratively. Those efforts, including involvement of native American tribes
8 and state agencies,as well as other stakeholders,continued over 15 years to the current project.
9
10 Cabinet Gorge HVAC Replacement (July 2024-Aug. 2025: $2,981,000, RY1: $0, RY2:
11 $0)
12 The current ventilation system in the powerhouse at Cabinet Gorge is still the original system
13 and equipment that was installed in 1952. The system needs to be replaced because the
14 original ventilation system controls are no longer functional and have been removed. There
15 is no cooling capacity with the current ventilation system and the current air handling system
16 can only be operated manually for ventilating and exhausting powerhouse air. There is no
17 filter system for plant make up air, which results in outside smoke from wildfires and dust
18 entering the plant. The current summer temperatures in the powerhouse routinely rise to 90°F
19 and additional transformers and electrical equipment planned to be installed within the
20 powerhouse over the next three years will significantly increase internal plant heat loading.
21 The new Station Service upgrade which is expected to be completed in 2025 will produce an
22 additional heat load in the plant. This new HVAC system will provide the plant cooling
23 needed due to this new equipment and provide sufficient heating, ventilation and air
24 conditioning in support of normal operations of the plant. Without this replacement, plant
25 personnel will be subjected to unacceptably high internal powerhouse temperatures and
26 critical electrical equipment will fail due to inadequate cooling.
27
28 Cabinet Gorge Station Service (July 2024-Aug. 2025: $18,190,000,RY1: $171,000,RY2:
29 $0)
30 The 1952 Cabinet Gorge Hydroelectric Development has retained most of its original
31 equipment which is now at end of life. The Station Service equipment is vital to the plant's
32 continued operation. Station Service equipment includes Load Centers, Transformers,
33 Switchgear, Power Centers and Neutral Grounding Resisters. This equipment is used to
34 operate the generating plant. It includes energy consumed for plant lighting, power, and
35 auxiliary facilities in support of the electricity generation system. This capital project replaces
36 aging equipment to ensure the continued safe operation of the plant. Failure to upgrade this
37 equipment would pose substantial hazards to the plant's operation and to plant personnel as
38 failed equipment can cause significant bodily injury and fire danger.
39
40 Cabinet Gorge Stop Log (July 2024-Aug. 2025: $1,980,000,RY1: $0,RY2: $0)
41 The original Cabinet Gorge Stop Logs are used to restrain the water when performing
42 maintenance on the spillway gates. The existing Stop Logs have degraded over many decades
43 of use. The project to replace them was approved in 2023 and was extended into 2024 as
44 installation took longer than anticipated. Three of the seven stop logs were replaced in 2024,
45 and the project is complete. This capital project replaced aging equipment to ensure the
46 continued safe operation of the plant. Failure to upgrade this equipment would have posed
47 substantial hazard to the plant's operation and to plant personnel.
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I Clark Fork Settlement Agreement (July 2024-Aug. 2025: $2,938,000, RY1: $2,664,000,
2 RY2: $3,122,000)
3 This capital program helps ensure the ongoing operation of the Clark Fork Project (Noxon
4 Rapids and Cabinet Gorge dams), which is subject to the Clark Fork Settlement Agreement
5 (CFSA) and FERC License No. 2058. Under this FERC License, Avista must develop and
6 carry out Protection, Mitigation and Enhancement (PM&E) measures each year. These
7 License measures consist of the completion of numerous specific projects each year for
8 habitat,fisheries,recreation, land management,wildlife and other natural and historic/cultural
9 resources related to our Clark Fork hydro operations. The capital projects are all implemented
10 in cooperation with state and federal agencies, Native American Tribes, local governments,
11 and other interested parties. Implementation of these measures also addresses ongoing
12 compliance with Montana and Idaho Clean Water Act Section 401 Certification requirements,
13 the Endangered Species Act, National Historic Preservation Act, Clean Water Act, and
14 additional state, federal and tribal laws and regulations. Some projects are multi-year while
15 other projects are one-time, as the entire capital program continues to evolve over the 45-year
16 License term.
17
18 If the PM&Es and license articles were not implemented and/or funded, Avista would be in
19 breach of an agreement and in violation of our FERC License. There would be a high risk for
20 penalties and fines, new license requirements, higher mitigation costs, and potential loss of
21 operational flexibility of the Cabinet Gorge and Noxon Rapids Hydroelectric Facilities. Loss
22 of operational flexibility, or of these generation assets, would create substantial new costs,
23 which would be detrimental to our electric customers and to the Company. Funding of the
24 Clark Fork License Implementation is essential to remain in compliance with the FERC
25 license and CFSA, which provides Avista the operational flexibility to own and operate the
26 hydroelectric facilities. The investment drivers for this project are predominantly Mandatory
27 and Compliance in nature.
28
29 Coyote Springs 2 CT Rotor Replacement (July 2024-Aug. 2025: $0, RY1: $19,583,000,
30 RY2: $0)
31 Coyote Springs 2 is a 280 MW combined cycle power plant located in Boardman, OR that
32 provides both base load and variable generation as needed by Avista's Balancing
33 Authority. The facility is owned by Avista and operated and maintained by Portland General
34 Electric.Additionally,there is a Long-Term Service Agreement(LTSA)with General Electric
35 that covers most components on the Combustion Turbine and Generator, but not the
36 replacement of the rotor at its normal end of life. The LTSA does cover replacement cost of
37 a rotor that fails within its GE specified operational life(144,000 hours for the rotor currently
38 in service). General Electric utilizes engineering, experience, and best practices in the fleet to
39 provide recommendations and guidance as to when certain pieces of equipment should be
40 replaced or rebuilt to reduce the likelihood of equipment failures. For the combustion turbine
41 rotor, the recommended replacement is after 144,000 hours of operation. For Coyote Springs
42 2, the year we anticipate arriving at 144,000 operating hours, based on historical operational
43 data, is 2026.
44
45 CS2 Low Pressure Evaporator Replacement (July 2024-Aug. 2025: $0, RY1: $0, RY2:
46 $3,799,000)
47 The Coyote Springs 2 Heat Recovery Steam Generator (HRSG) is an energy recovery heat
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I exchanger that transfers heat from the Gas Turbine exhaust into water and steam that is used
2 to power a Steam Turbine. One of the last sections toward the outlet of the HRSG is the Low
3 Pressure(LP)Evaporator,that is used to circulate relatively cool water through multiple tubes
4 from the top to the bottom of the HRSG, and transfers heat from the gas stream to the water.
5 During 2019, there was a forced outage due to Flow Accelerated Corrosion (FAC), which is
6 a type of corrosion that occurs on the inside of the tubes and is magnified by fluid and
7 thermodynamics and material type. During a detailed inspection in the Spring of 2021,
8 additional FAC was noticed in other areas of the LP Evaporator. Modifications were made to
9 the circulating portion of the Evaporator, but if the FAC is not eliminated, or damage
10 continues, there could be widespread issues throughout the LP Evaporator that could cause
11 multiple forced outages. LP Evaporator is a necessary,critical component of the boiler circuit.
12 Without the LP Evaporator the plant is unable to generate electricity. Restoring the LP
13 Evaporator will increase plant reliability. Without restoring the LP Evaporator, the plant will
14 continue to have more frequent forced outages due to LP Evaporator tube leaks.
15
16 HMI Control Software (July 2024-Aug. 2025: $3,276,000, RY1: $3,650,000, RY2:
17 $5,554,000)
18 The existing Human Machine Interface (HMI) software, Wonderware, reached its end of life
19 as support ended in 2017. HMI Control Software is used to develop control screens and to
20 operate and monitor generating systems within Avista Hydroelectric Developments and
21 Thermal Generating facilities. The existing architecture is also outdated and requires the
22 existing software to be loaded and run on each individual computer at each generating facility.
23 Moving to a new HMI platform will allow for upgrading to server-based architecture. The
24 HMI Control Software update is a multi-year effort to transition the controls software at all
25 GPSS generating facilities from Wonderware to Ignition. As a part of this update, supporting
26 software and hardware will also need to be upgraded to ensure communication and support
27 across all parts of our controls system. The timing of this transition is critical due to the
28 expiring support for both Wonderware and Windows 7 (the current, and only, operating
29 system functional with Wonderware)
30
31 Hydro Safety Minor Blanket (July 2024-Aug. 2025: $230,000, RY1: $0, RY2: $0)
32 The Federal Energy Regulatory Commission (FERC) gives broad regulatory discretion (18
33 CFR Section 12.42) over the installation, operation and maintenance of hydro public safety
34 devices near Avista's dams. Devices include lights, sirens, signage and barriers. Avista is
35 subject to potential liability should the company not maintain safety-related equipment and
36 associated safety measures. Projects are identified in a variety of ways, including physical
37 condition/age/function, changing standards in FERC guidance, industry practice, or emergent
38 public safety needs. All projects are subject to conceptual approval by members of the Dam
39 Safety team and additional internal Director review and oversight. This work benefits
40 customers by maintaining and enhancing safety, ensuring compliance and reducing risk.
41
42 This capital spending category covers the ongoing implementation of PM&E programs related
43 to the FERC License No. 2545 and several other settlement agreements for the Spokane River
44 Project including the Post Falls,Upper Falls,Monroe Street,Nine Mile and Long Lake dams.
45 These capital projects include items enforceable by FERC, mandatory conditioning agencies,
46 and through settlement agreements. The FERC License defines how Avista operates the
47 Spokane River Project and includes several hundred requirements that must be met to retain
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I this License. The License is issued pursuant to the Federal Power Act, and it embodies
2 requirements for a wide range of other laws such as the Clean Water Act, the Endangered
3 Species Act, and the National Historic Preservation Act, among others. These requirements
4 are also expressed through specific license articles relating to fish, terrestrial resources, water
5 quality, recreation, education, cultural, and aesthetic resources at the Spokane River Project.
6 The License incorporates specific funding requirements to a 50-year settlement agreement
7 between local and state agencies, as well as the Coeur d'Alene and Spokane Tribes. The
8 License references our requirements for land management, dam safety, public safety and
9 monitoring requirements,which apply for the term of the License and ensures Avista's ability
10 to operate the Spokane River Project on behalf of our electric customers within our service
11 territory over the 50-year license term.
12
13 Kettle Falls 4160 V Station Service Replacement (July 2024-Aug. 2025: $722,000, RY1:
14 $1,541,000,RY2: $0)
15 All generation facilities require station service to provide electric power to the plant. Station
16 service components include motor control centers, load centers, emergency load centers,
17 various breakers, transformers, and conductors. Station service is an elaborate system with
18 multiple built-in redundancies and multiple voltages designed to protect the plant's electrical
19 system. The plant's low voltage 4160-volt switch gear has been identified by AIG insurance
20 inspection as being out of compliance. With aging equipment, the plant is experiencing
21 challenges with service and parts to maintain the breakers. The plant is currently installing
22 new fuel yard equipment which will require new and upsized power needs in the fuel yard.
23 The plant fuel yard project team has put in place a temporary work around to power the new
24 yard,but this solution is not permanent. This project will replace the 4160-volt station service.
25 This replacement will correct the insurance deficiency and increase reliability to the plant's
26 critical loads.
27
28 Kettle Falls Secondary Superheater Replacement (July 2024-Aug. 2025: $3,401,000,
29 RY1: $0,RY2: $0)
30 The Kettle Falls Generating Station processes nearly 450,000 tons of waste wood annually.
31 During the combustion process the waste wood is metered into the boiler and onto the
32 traveling grate where it is burned. Air is blown in and around the fire to ensure complete and
33 efficient combustion. The combustion air is drawn from outside the boiler building from the
34 forced draft fan at ambient temperature then blown into the air heater to increase the
35 temperature of the combustion air. The high temperature combustion air increases the
36 efficiency of the combustion process and reduces air emissions. The air heater has a history
37 of dew point failure where the tubes begin to crack and fail within a few inches of the tube
38 sheet. In 2010, the air heater was rebuilt using new convective tube technology by CMS
39 (Corrosion Monitoring Services).Nearly half of the tubes were replaced,and a comprehensive
40 maintenance plan was put in place. CMS has supported those efforts for the last 11 years, and
41 in 2021, the air heater had 9 tubes removed from service due to corrosion failure. CMS has
42 advised from their experience that once the unit begins having tube failure, the owner can
43 expect to see double the failure from the previous year each year going forward. This project
44 is to replace the air heater to restore air heater efficiency to the plant.
45
46 Kettle Falls Ash Landfill Expansion (July 2024-Aug. 2025: $0, RY1: $0, RY2:
47 $10,189,000)
Howell, Di 13
Avista Corporation

I Kettle Falls Generation Station burns on average 450,000 green tons of wood waste annually.
2 This combustion process creates roughly 30,000 cubic yards of ash that is trucked and stored
3 at the 177-acre parcel south of the plant site. The landfill area is approximately 15 acres nested
4 inside of a 42-acre fenced parcel designated for landfill operations and development. The
5 current ash landfill is reaching its full capacity and is expected to be completely filled between
6 2025 and 2028 depending on plant dispatch and ash production. This project will construct a
7 new Phase 4 lined landfill built to current standards and will incorporate the closure costs of
8 Phase 3 as part of the construction of the new disposal area.
9
10 KF ID Fan&Motor Replacement(July 2024-Aug.2025: $3,360,000,RYI: $0,RY2: $0)
11 The induced draft (ID) fan at Kettle Falls Generating Station is original to the plant,
12 commissioned in 1984. Over time, abrasive ash in the flue gas has caused significant wear to
13 fan components and case. The fan motor is overworked during times of poor fuel quality and
14 high system demand. Asset conditions and inability of the fan to keep up with system need
15 sometimes results in plant output limitations. The plant utilizes dampers to aid flue gas
16 processing to support maximum motor operation, but the plant is forced to drop output
17 capacity. Mounting maintenance costs for the fan and the inability for the motor to keep up
18 with the volume and quality of flue gas has led to higher costs and reduced generation.
19
20 Little Falls Program (July 2024-Aug. 2025: $566,000,RY1: $0,RY2: $0)
21 Little Falls HED was completed in 1910, with various elements at the facility being repaired,
22 replaced, or upgrade over time. This program mainly addresses four areas: Spillway
23 Modernization, Headgate Replacement, Trash Rake, and the Crane Pad/Landing.
24
25 The LF Spillway has, since the 1940's, utilized removeable wooden flashboards to increase
26 the output of the plant by increasing the hydraulic head, with each of the three flashboard
27 sections installed or removed manually based on flow conditions by crews in boats. The two
28 Tainter gates at the Spillway allow for spill versatility and need to be replaced as they are
29 original.
30
31 Headgates are critical equipment,holding back waterflow from the penstock for maintenance,
32 repair, or replacement at the turbine or generating unit assembly. Several features of the
33 headgates no longer function as designed. Electrical and controls upgrades have been
34 completed over the years, but there is no backup power source for the gates should the plant
35 experience a loss of power. Mechanical and structural components are largely original.
36 Concrete around the headgates is in disrepair, making sealing of the gates difficult-to-
37 impossible without assistance of divers.
38
39 The existing Trash Rake was installed in 2001, and it does not have modern detection and
40 containment for any hydraulic fluid which might end up in the river. The Trash Rake is also
41 undersized, often stalling during operation with accumulated debris; the risk to personnel
42 safety increases as operators counter the stalling events. The conveyor system portion of the
43 Trash Rake also contributes to personnel safety risk due to exposed rollers in close proximity
44 to operators.
45
46 The existing Crane Pad and trash boom anchor at Little Falls are at their end of useful life.
47 Material conditions related to the sheet pile wall and pad foundation highlight the risk of
Howell, Di 14
Avista Corporation

I complete failure with equipment falling in the forebay. The only way to currently use the
2 Crane Pad is to adjust outriggers in a way which partially obstructs the Spokane Indian Tribe's
3 Martha Boardman Rd.
4
5 Long Lake Plant Upgrade (July 2024-Aug. 2025: $300,000, RY1: $0, RY2: $0)
6 The equipment needs to be upgraded for continued reliability as soon as possible. The existing
7 equipment ranges in age from 20 to more than 100 years old.We have experienced an increase
8 in forced outages at Long Lake over the past several years, almost zero in 2011 and increasing
9 every year since then. This is caused by equipment failures on several different pieces of
10 equipment. The other major driver for this project is safety. The switching procedure for
11 moving station service from one generator to the other resulted in a lost time accident and a
12 near miss in the past 5 years. In addition,the station service disconnects represent the greatest
13 arc-flash potential in the Company. This area is roped off and substantial safety equipment is
14 required to operate the disconnects. This project will reconfigure this system to eliminate
15 requiring personnel to perform this operation and avoid the arc-flash potential area. In total,
16 the program includes a full plant condition assessment, replacement of all generating units,
17 generator step-up transformers (GSUs), station service, and many of the mechanical,
18 electrical, and controls systems and equipment have met their end of useful life. Direct offsets
19 associated with this project include an increase in production and a reduction in labor and
20 equipment for unplanned maintenance and breakdowns. The annual system estimated value
21 of these Direct Offsets is $50,000 in 2025, $100,000 in 2026 and $150,000 in 2027. Idaho's
22 share is prorated over the Two-Year Rate Plan and included in the Company's revenue
23 requirement as a reduction in expense within pro forma Adjustments 3.10 (Rate Year 1) and
24 26.05 (Rate Year 2).
25
26 Nine Mile Unit 3 Mechanical Overhaul(July 2024-Aug.2025: $6,903,000,RY1: $0,RY2:
27 $0)
28 The 2018 Maintenance Assessment identified NM Unit 3 as high risk due to several issues.
29 Unit 3 was replaced in 1995, but experienced cracked buckets in the runners in 2010 due to
30 erosion from sediment and cavitation damage; these cracks were repaired, but erosion
31 continues, and bucket failure is anticipated. The downstream roller guide bearing has
32 degraded, causing the upstream generator guide bearing to experience increased stress, wear,
33 and increased risk of failure. This project installs new Francis Runners, new downstream
34 bearing and pedestal, new thrust/guide bearing and shaft, as well as refurbishing wicket gate
35 stems and operating components. System direct O&M saving offsets associated with this
36 project approximate $50,000 beginning in 2024. Idaho's share of this O&M savings is
37 included beginning in Rate Year 1 as a reduction in expense within pro forma Adjustment
38 3.10.
39
40 Nine Mile Units 3&4 Control Upgrade(July 2024-Aug.2025: $2,200,000,RY1: $0,RY2:
41 $5,122,000)
42 Nine Mile Units 3 and 4 controls were installed in the early 1990's and are at the end of their
43 intended life. Further, there is an increased likelihood of forced outages and subsequent loss
44 of revenue and reliability. During the 2018 Maintenance Assessment, the unit controls were
45 rated in poor condition and high in risk due to their age and current condition. The switchgear
46 floor is overloaded, which poses a safety risk. In 2010, the switchgear floor was found to be
47 inadequate for any loading above and beyond what it is currently supported, and partially
Howell, Di 15
Avista Corporation

I replaced during the Unit 1 and 2 replacement projects. The remainder of the floor will need
2 to be replaced to ensure adequate floor loading can be achieved. This project will include new
3 speed controllers(governors),voltage controls(automatic voltage regulator or AVR),primary
4 unit control system (i.e., Unit PLC), and an upgraded protective relay system on units 3 and
5 4. Also included is replacement of the switchgear floor inside the Nine Mile powerhouse that
6 will be utilized for relocation of the unit controls and voltage regulation equipment.
7
8 Noxon Rapids Gantry Crane Modernization (July 2024-Aug. 2025: $0, RY1:
9 $19,494,000,RY2: $0)
10 Noxon Rapids construction was completed in 1959. Noxon has the capability of producing
11 over 500 MW of peaking power. A key component of the facility is the gantry crane. The
12 gantry crane is utilized to perform required maintenance and upgrades to the
13 turbine/generators. The crane is rated for maximum lifting capacity of 325 tons. The gantry
14 crane is now over 60 years old. Further, parts are difficult to source, and the crane does not
15 conform to current safety standards. Past failures with the crane have caused delays in
16 projects. A functional crane is critical to completing future planned work including the Unit
17 2 Core and Winding Replacement, Excitation Replacement, the Unit 3 Core and Winding
18 Replacement, and Unit 5 Turbine runner replacement. Without a functional crane, work
19 cannot be performed.
20
21 Noxon Rapids U5 Turbine Runner Replacement (July 2024-Aug. 2025: $0, RY1:
22 $499,000, RY2: $0)
23 The installation of Noxon Rapids turbines was completed in 1959-1960, and Unit 5 was
24 installed in 1977. Units 1-4 were replaced in the early 2000's. Unit 5 runner material seems
25 to be more susceptible to erosion than comparable units, and Avista has utilized annual
26 maintenance periods over the last 25+years to conduct welding on the Unit 5 turbine to repair
27 blade erosions. These repairs have become so extensive that they can no longer be completed
28 during the annual maintenance periods. To provide reliable generating capacity to Avista
29 customers, replacement of the turbine runner is planned. System direct O&M saving offsets
30 associated with this project approximate $100,000 beginning in 2024. Idaho's share of this
31 O&M savings is included beginning in Rate Year 1 as a reduction in expense within pro forma
32 Adjustment 3.10.
33
34 Operational Safety and Compliance (July 2024-Aug.2025: $3,837,000,RY1: $2,907,000,
35 RY2: $1,267,000)
36 This program will support the various compliance and safety-related projects within all of the
37 Avista-owned generating facilities. The projects are intended to address compliance and/or
38 safety related matters at the facilities. Projects will be low in complexity and coordination.
39 This program is critical in supporting facility compliance with agencies including NERC,
40 FERC, WEC and OSHA. Identified projects will be governed by the Plant Manager,
41 Operations Engineering Manager, and Senior Operations&Maintenance Manager. The GPSS
42 Operations team will coordinate and manage a 5-year plan of identified projects to sustain the
43 safe and reliable operations of the Avista-owned generation assets.
44
45 Operational Sustainment (July 2024-Aug. 2025: $6,126,000, RY1: $8,066,000, RY2:
46 $16,283,000)
47 This program will support the operational sustainability of the Avista-owned generating
Howell, Di 16
Avista Corporation

I facilities. These projects primarily include moderate investments in system retrofits or
2 replacements necessary to maintain the operation of the facilities. This program is critical in
3 continuing to support asset management program lifecycle replacement schedules until larger
4 operational enhancement program investments are made. Identified projects will be governed
5 by the Plant Manager, Operations Engineering Manager, and Senior Operations &
6 Maintenance Manager. The GPSS Operations team will coordinate and manage a 5-year plan
7 of identified projects needed to sustain the safe, reliable, and affordable operations of the
8 Avista-owned generation assets.
9
10 Peaking Generation Business Case (July 2024-Aug. 2025: $372,000, RYl: $0, RY2: $0)
11 Avista's Peaking Generation plants offer operational flexibility and are utilized to support
12 energy supply needs. Thermal Peaking Generation provides options for Avista's System
13 Operations and Power Supply groups to maximize value to Avista and its customers. These
14 plants represent more than 255 MW of power and include Rathdrum Combustion Turbines,
15 Boulder Park Generating Station and Northeast Combustion Turbine, all natural gas fired
16 power plants. The operational availability for these generating units in these plants is
17 paramount. The purpose of this program is to fund smaller capital expenditures and upgrades
18 that are required to maintain safe and reliable operation. Maintaining these plants safely and
19 reliably provides our customers with low cost, reliable power while ensuring the region has
20 the resources it needs for the Bulk Electric System(BES). The business drivers for this project
21 in this program is a combination of Asset Condition, Failed Plant, and addressing operational
22 deficiencies. Most of these projects are short in duration, typically well within the budget
23 year, and many are reactionary to plant operational support issues. Starting in 2024, the work
24 under this business case will begin to transition into the new Operational Sustainment, Safety
25 and Compliance, and Asset Lifecycle Management Business Cases based on their specific
26 project driver.
27
28 Post Street Substation Crane Rehab (July 2024-Aug. 2025: $1,080,000, RY1: $702,000,
29 RY2: $0)
30 The 35 Ton Niles Bridge Crane at the Post Street Substation is original to 1907 and services
31 the interior of the building. The primary function for this crane is to service the Upper Falls
32 and Monroe Street GSU's, substation 115kv transformers, switchgear, and miscellaneous
33 other substation equipment. The crane's controls and electrical are mostly original and have
34 degraded in capability over time. Recent experience with the crane exhibited issues with
35 controls and overheating/stalling with extended use.The current state of electrical components
36 on this crane are not capable of supporting the pick of a transformer without extensive
37 refurbishing. This negatively impacts the ability to respond to a failure in a critical downtown
38 substation and increases risk. The problem is aggravated by the lack of ability to use a large
39 enough standard mobile crane inside the building as an alternative. The project includes a
40 replacement of the existing crane electrical and controls, refurbishment of the mechanical
41 components, and replacement of the existing hoist and trolley system with a modern
42 arrangement.
43
44 Regulating Hydro (July 2024-Aug. 2025: $1,235,000,RY1: $0,RY2: $0)
45 Avista's regulating hydro plants are unique in that they have storage available in their
46 reservoirs. This enables these plants to have operational flexibility and are operated to support
47 energy supply, peaking power, provide continuous and automatic adjustment of output to
Howell, Di 17
Avista Corporation

I match the changing system loads, and other types of services necessary to provide a stable
2 electric grid and to maximize value to Avista and its customers. These plants are the four
3 largest hydro plants on Avista's system representing more than 950 MW of power and include
4 Noxon Rapids and Cabinet Gorge on the Clark Fork River in Montana and Idaho and Long
5 Lake and Little Falls on the Spokane River. The purpose of this program is to fund smaller
6 capital expenditures and upgrades that are required to maintain safe and reliable operation.
7 Projects completed under this program include replacement of failed equipment and small
8 capital upgrades to plant facilities. The business drivers for the projects in this program is a
9 combination of asset condition, failed (or failing) plant, and addressing operational
10 deficiencies. Most of these projects are short in duration, typically well within the budget
11 year, and many are reactionary to plant operational support issue. Starting in 2024, the work
12 under this business case will begin to transition into the new Operational Sustainment, Safety
13 and Compliance, and Asset Lifecycle Management Business Cases based on their specific
14 project driver.
15
16 Spokane River License Implementation (July 2024-Aug. 2025: $896,000, RY1:
17 $1,040,000,RY2: $973,000)
18 The Spokane River License Implementation Project, or Spokane River Implementation, is a
19 capital program that helps ensure the ongoing operation of the Spokane River Project which
20 includes the Post Falls, Upper Falls, Monroe Street, Nine Mile and Long Lake dams. The
21 Spokane River Project is subject to FERC License No. 2545 and several other settlement
22 agreements. This license, issued in 2009 following almost seven years of consultation,
23 negotiations, and litigation, defines how Avista operates the Spokane River Project and
24 includes several hundred requirements, expressed as license conditions. The FERC license
25 was issued pursuant to the Federal Power Act(FPA)and embodies the requirements of a wide
26 range of other laws such as The Clean Water Act, The Endangered Species Act, and The
27 National Historic Preservation Act, among others. These requirements are expressed through
28 specific license articles relating to fish, terrestrial issues, water quality, recreation, land use,
29 education, cultural and aesthetic resources. Avista also entered into additional two-party
30 agreements with local,state,and federal agencies, and the Coeur d'Alene and Spokane Tribes.
31 Most of these agreements are embodied in the License. The FERC license ensures Avista's
32 ability to operate the Spokane River Project on behalf of our electric customers within our
33 service territory over the 50-year license term. This capital program consists of numerous
34 projects each year, and the total cost of implementing these projects varies each year,
35 depending on specific license requirements and opportunities.
36
37 Q. Referring to the individual Table No. 1 above, what is the overall level of
38 system capital additions for which you sponsor, and how does this capital investment
39 compare between the Pro Forma and RY1 and RY2 periods?
40 A. Illustration No. 1 below shows overall system Production capital additions
41 (transfers to plant) for the Pro Forma, RY1 and RY2 periods, of$66.2 million, $66.7 million
Howell, Di 18
Avista Corporation

I and $54.0 million, respectively. As also noted in the illustration, the "Pro Forma" period
2 represents 14 months (or July 1, 2024 — August 31, 2025). Finally, this illustration
3 distinguishes between what are ongoing projects or programs from the Pro Forma period
4 ending August 2025, versus incremental projects that are estimated to transfer-to-plant from
5 September 2025 through August 2027, representing $39.6 million in RY1 and $16.2 million
6 in RY2.
7 Illustration No. 1—Production Plant Investment(System Transfers to Plant)
8
9 Avista Production Capital Additions
$'s in millions(System Transfers to Plant)
$80
10
$70
11
$60
12 $50
13 $40
$30
14
$20
15
$to
16 $_
Pro Forma RY1 RY2
17 Total $66.2 00 $66.7 $54.0
■Continuation of Ongoing Business Cases ■Additional Business Cases Initiated in RY1-RY2
18 (1)Pro Forma period includes July 1,2024-August 31,2025 capital additions.
(Z)The majority of the incremental investment in RY1 is associated with Coyote Springs 2 CT Rotor Replacement and Noxon Rapids
19 Gantry Crane Modernization.
(3)The majority of the incremental investment in RY2 is associated with the KF Ash Landfill Expansion and the CS2 Low Pressure
Evaporator Replacement.
20
21 Notably, as can be seen from this illustration, most of the capital investment overall
22 over the Two-Year Rate Plan(54%total; or 41%in RY1 and 70%in RY2)relates to ongoing,
23 multi-year efforts that continue over time, at various funding levels. The rationale and
24 justification for these ongoing projects or programs,however,does not change over time,only
Howell, Di 19
Avista Corporation

I the f indin 1�. The incremental Business Cases of$39.6 million(system) in RY1 relates
2 to the Coyote Springs 2 (CS2) CT Rotor Replacement ($19.6 million), the Noxon Rapids
3 Gantry Crane Modernization ($19.5 million) and the Noxon Rapids Unit 5 Turbine Runner
4 Replacement ($0.5 million). The additional Business Cases of$16.2 million in RY2 relates
5 to the Kettle Falls (KF) Ash Landfill Expansion ($10.2 million), the CS2 Low Pressure
6 Evaporator Replacement ($3.8 million) and the Automation Replacement ($2.2 million). All
7 incremental Business Cases are discussed earlier in my testimony.
8 Q. Does this conclude your pre filed direct testimony?
9 A. Yes, it does.
Howell, Di 20
Avista Corporation

DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
DAVID.MEYER@AVISTACORP.C OM
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-25-01
OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-G-25-01
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 7
AND NATURAL GAS CUSTOMERS IN THE ) OF
STATE OF IDAHO ) DAVID R. HOWELL
FOR AVISTA CORPORATION
(ELECTRIC AND NATURAL GAS)

Exhibit No. 7, Schedule 1
Capital Investment Business Case Justification Narratives Index
Business Case Name Page Number
Generation Production and Environmental Capital Proiects
Asset Lifecycle Management 2
Automation Replacement 11
Boulder Park Engine Controls Upgrade 20
Cabinet Gorge Dam Fishway 29
Cabinet Gorge HVAC Replacement 36
Cabinet Gorge Station Service 44
Cabinet Gorge Stop Log Replacement 54
Clark Fork Settlement Agreement 62
Coyote Springs 2 CT Rotor Replacement 68
CS2 Low Pressure Evaporator Replacement 79
HMI Control Software 97
Hydro Safety Minor Blanket 110
KF 4160 V Station Service Replacement 116
KF Secondary Superheater Replacement 126
KF—Ash Landfill Expansion 139
KF_ID Fan& Motor Replacement 149
Little Falls Plant Upgrade 158
Long Lake Plant Upgrade 165
Nine Mile Unit 3 Mechanical Overhaul 180
Nine Mile Units 3 &4 Control Upgrade 190
Noxon Rapids Gantry Crane Modernization 203
Noxon Rapids Unit 5 Turbine Runner Replacement 213
Operational Safety and Compliance 222
Operational Sustainment 229
Peaking Generation Business Case 237
Post Street Substation Crane Rehab 245
Regulating Hydro 256
Spokane River License Implementation 264
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 1 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Asset Lifecycle Management
EXECUTIVE SUMMARY
The diverse Avista-owned generating facilities include Hydro, Biomass, and Natural Gas fuel power
producing resources. The assets range in age, condition, output, and configuration. Together these facilities
bring a balanced approach to meeting our electric customers' needs throughout the year. The 13 Avista-
owned generating facilities have a total capacity of nearly 1.6GW of electricity. These facilities include 8
hydroelectric dams located on the Clark Fork and Spokane Rivers, a stand-alone biomass facility located in
Kettle Falls, Washington, and four natural gas generating plants spread in Idaho, Washington, and Oregon.
This program will support the various plant projects within all the Avista-owned generating facilities. These
projects are routine and time-based projects intended to extend the life of a system or an asset. They are
not intended to replace the full system but instead bring the system back to its original performance and
objective. Projects will be level 0 to level 1 in project complexity and coordination. This program is critical in
continuing to support asset management program lifecycle replacement schedules. Identified projects will
be governed by the Plant Manager, Operations Engineering Manager, and Senior Operations&Maintenance
Manager.
The GPSS Operations team will coordinate and manage a 5-year plan of identified projects needed to sustain
the safe, reliable, affordable operations of the Avista-owned generation assets. The annual cost of this
program is variable and depends on evaluation of asset condition.
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
1.0 Alexis Alexander Initial draft of original business case
1.1 Glen Farmer Asset Management&Compliance Engineering Review 4/27/2023
1.2 Greg Wiggins Edits to narrative reflecting ongoing work in Asset Management program 8/28/2024
BCRT BCRT Team Has been reviewed by BCRT and meets necessary requirements
Member
Business Case Justification Narrative Template Version: February 2023 Page 1 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 2 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Asset Lifecycle Management
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2025 1,450,000 1,450,000
2026 4,950,000 4,950,000
2027 8,000,000 8,000,000
2028 3,000,000 3,000,000
2029 3,000,000 3,000,000
Project Life Span 5 years
Requesting Organization/Department A07/Generation Production Substation Support
Business Case Owner Sponsor Greg Wiggins/David Howell
Sponsor Organization/Department David Howell/GPSS
Phase Execution
Category Program
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
This program will support the various maintenance projects within all of the Avista-owned generating
facilities. These projects are routine, scheduled and time-based maintenance activities intended to
extend the life of an asset. Projects within this program are designed to maintain continued operations
of the hydro and thermal generating facilities. The projects will be planned and emergent work. The
driver will primarily be asset condition but may vary between individual projects.
1.2 Discuss the major drivers of the business case.
Business Case Justification Narrative Template Version: February 2023 Page 2 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 3 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Asset Lifecycle Management
Major drivers are Asset Condition— Investments to replace assets based on industry accepted, asset
management principles and strategies. GPSS Asset Management strategy is designed to optimize
the overall lifecycle value for our customers.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The Avista-owned hydro and thermal generating facilities have a wide range of aging equipment.
Continual investment will be required for the facilities to meet the demands of future energy markets.
This program will support the ongoing maintenance projects spread across the 13 facilities. Examples
of these projects include: Nine Mile Roof Replacement, Kettle Falls Dozer Certified Powertrain
Replacement, and GSU Monitoring project. The dynamic performance of our assets driven by the
evolving energy markets is leading to increased unplanned failures. The proposed business case
allows for proactive measures to maintain unit availably, ultimately contributing to energy costs
savings for our customers.
Without this funding source the facilities will lack a minimum project funding to maintain safe, reliable,
and affordable operations.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
This program aligns with Avista's core business by delivering energy safely, responsibly, and
affordably to our customers. Through prudent investments in plant operations, we can ensure the
generating facilities are reliable and available to respond to the energy market of the future. In addition,
many of the investments improve the operational safety of our employees, enabling them to achieve
their optimal performance.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 4 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Asset Lifecycle Management
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.'
This program will support 13 Avista-owned generating facilities and will fund several projects
annually. These projects will vary in size and scope and will be governed by the GPSS Operations
team including the Plant Managers, Operations Engineering Manager, and the Senior Operations and
Maintenance Manager. Projects will be analyzed, planned, and executed by one group aligning
investment decisions for optimal operational performance. Operations and Maintenance Engineering
team will work together to create supporting documentation in alignment with the PMO process.
Larger projects will be further vetted through the department Generation Round Table project
approval process for justifying the investment for each project, utilizing existing asset management
analysis and maintenance records.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 5 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Asset Lifecycle Management
2. PROPOSAL AND RECOMMENDED SOLUTION - Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
The combination of renewable integration, unprecedented weather patterns, and new energy policy,
has changed Avista's resource mix. As a result, the investments necessary to sustain the operation
and maintain our facilities has taken on a new forecasting profile.
The new program, accompanied by an enhanced resource strategy, including the development of plant
and regional project teams, will enable better coordinated project delivery for the respective plants. In
addition, a centralized list of projects across Avista's entire generation fleet will be maintained and
prioritized by the Senior Operations and Maintenance Manager. Project and resources will be
managed through OPC and the Project Delivery team.
Past asset management, maintenance, and investment strategies have changed to meet the new
demands. The new resource strategy along with the business case program structure will support
improved project planning, execution, and the adaptability needed to respond to unplanned events.
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
Projects will follow the GPSS risk based investment planning methodology for life cycle analysis, cost
benefit and risk reduction. This work will be done by the GPSS Operations Engineering Team. The
major component projects will have an average lifecycle look with current asset condition. The first year
Risk Cost Reduction will be projected which is the difference between the current risk costs, based on
failure rates, and the risk costs of a new assets. This is analogous to; if Avista were to pay an
"insurance premium"to pay for probable consequences of failure.
1 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 6 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Asset Lifecycle Management
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
0&M $ $ $ $ $
DIRECT offsets will be determined for each project, when applicable. This information will be
calculated and documented in each project file.
2.4 Summarize in the table, and describe below the INDIRECT offsets4(Capital
and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
0&M $ $ $ $ $
INDIRECT offsets will be determined for each project, when applicable. This information will be
calculated and documented in each project file.
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: N/A
Alternative 2: N/A
Alternative 3: N/A
Where applicable, each project will document alternatives that were considered during the research
and planning phase. The alternatives for projects will be determined such as direct replacement,
manufactures recommendations, and industrial standards.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 7 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Asset Lifecycle Management
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
Projects will be tracked and managed in Maximo asset management program. Historical asset data
may be used to compare the project benefits. When available, the data will be used to support the
investment decision.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Projects will commence and complete throughout the year over the various plant locations. This
process will allow"shovel ready" projects to be quickly put into the queue and executed when funds
and resources are available.
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.
Projects will be classified into level 0 and level 1 based on complexity and required coordination.
Level 0 projects will utilize the GPSS Operations team consisting of the Plant Manager, Operations
Engineering Manager, and Senior Operations and Maintenance Manager for project governance.
Projects will be ranked using the GPSS project ranking matrix which focus on various categories
including; Personnel and Public Safety, Environmental, Risk of Equipment Failure, Regulatory
Mandate, Maintenance Issues, Customer Value, Operating Efficiencies, Operating Costs, and
Obsolete Equipment. Level 0 projects are smaller in scope, generally less than $1 M,and completed
within the calendar year.
Level 1 projects, are larger in scope, schedule, and budget, costing between $1 M-$10M and are
completed over the course of two years. Level 1 projects will receive a higher level of scrutiny,
utilizing the GPSS strategic asset management plan to guide capital replacement strategies. Where
data is available, the GPSS risk-based investment planning tool will be used to rank asset condition,
criticality, and risk costs for level 1 projects.
A dedicated GPSS Program Manager will be responsible for monitoring the program and the
associated projects to ensure expected budget and transfer to plant are on target.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 8 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Asset Lifecycle Management
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the GPSS_Operational Preventive
Maintenance Program and agree with the approach it presents. Significant changes to this
will be coordinated with and approved by the undersigned or their designated
representatives.
Business Case Justification Narrative Template Version: February 2023 Page 8 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 9 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Asset Lifecycle Management
Signed by:
Signature: wi �n,s Date: Sep-17-2024 I 4:23 AM PDT
Print Name: Greg Biggins 64F9 .
Title: Manager, GPSS O&M
Role: Business Case Owner
Signed by:
Signature: Fum',k Sawa Date: Sep-17-2024 I 12:37 PM PDT
Print Name: Davic�` f�s` e7�g488-
Title: Director, GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 9 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 10 of 271

Docusign Envelope ID:C003B28D-A736-4712-A545-D8A2EC25F327
Automation Replacement
EXECUTIVE SUMMARY
NEEDS ASSESSMENT: The purpose of this program is to replace aging controllers and
governors. Controllers are used to automate, control and monitor Avista's generating
facilities. The controllers of concern are aging and introducing an increase in hardware,
software, and communication failures that limit Avista's ability to operate generating
facilities reliably. The program allows overdue controller replacements to happen at
quicker pace to improve reliability and support the HMI program. Replacing aging
governors is being added to scope in 2022 as many governor controls will be replaced
with PLC based governors.
The recommended solution is to proactively replace all aging controllers and governors
on a schedule that takes into account resources and outage availability.
ORIGINAL ESTIMATED COST: $6,500,000 with the project cost to replace an outdated
controller about $300,0004500,000 depending on the complexity.
2024 UPDATE: Cost and schedule revisions to reflect current trajectory of scope. The
remaining scope in this BCJN is entirely at Noxon Rapids, and is focused on PLC,
Governors, and related systems associated with Noxon Units 1, 2, 3, 4, and 5. The
associated costs for this scope are higher than earlier phases of the project due to design
considerations at Noxon, as well as larger economic impacts beyond Avista control.
Currently estimating $10,529,321 total spend and project completion in 2027.
DOCUMENT SUMMARY: Proactively replacing these devices benefits customers by
reducing unexpected plant outages that require emergency repair with like equipment. A
planned approach allows engineers and technicians to update logic programs more
effectively and replace hardware with current standards.
When this program was proposed in 2017, a multi-year plan was provided that captured
the various controllers through Avista's generating facilities that need to be upgraded.
RISK: The risk of not continuing this business case slows progress toward replacing aging
and outdated controllers and governors that could results in an unplanned outage or a
APPROVALS: The recommended solution was reviewed by GPSS Engineering and
approved by GPSS Management. The recommended solution was reviewed by GPSS
Engineering and approved by GPSS Management.
VERSION HISTORY
Version Author Description Date Notes
1.0 Kristina Initial version 6/21/2016 1.0
Newhouse
Kristina Added meters to scope, changed
2.0 Newhouse driver to"Asset Condition," and 6/28/2019 2.0
clarified advisory groupinfo
Business Case Justification Narrative Template Version: January 2023 Pale 1 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 11 of271

Docusign Envelope ID:C003B28D-A736-4712-A545-D8A2EC25F327
Automation Replacement
3.0 Kristina Updated to 2020 template 7/31/2020 3.0
Newhouse
Kristina Updated to 2022 template,
Newhouse updated schedule, and updated
4.0 &Jeremy scope to include governors and 8/25/2022 4.0
Winkle removed meters
No substantive
5.0 Jessica Transfer to new BCJN Template 01/06/2023 changes/edits have been
Bean made to the business case
through this transfer
6.0 Don Sherrill Update for annual review and 09/03/2024
approval
GENERAL INFORMATION
Original Requested Spend Amount $6,500,000
Requested Spend Time Period 9 years
Current Total Requested Spend Amount $10,529,321
Current Total Requested Time Period 11 years
Requesting Organization/Department GPSS
Business Case Owner I Sponsor Kristina Newhouse David Howell
Sponsor Organization/Department GPSS
Phase Execution
Category Program
Driver Asset Condition
YEAR PLANNED SPEND AMOUNT ($) PLANNED TRANSFER TO PLANT
2017 $ 400,314 (actual) $ 289,863 (actual)
2018 $ 1,438,633 (actual) $ 1,231,420 (actual)
2019 $ 552,342 (actual) $ 319,503 (actual)
2020 $ 474,442 (actual) $ 405,105 (actual)
2021 $ 538,741 (actual) $ 649,170 (actual)
2022 $ 91,343 (actual) $ 273,451 (actual)
2023 $ 218,507 (actual) $ 0 (actual)
2024 $ 815,000 (planned) $ 600,000 (planned)
2025 $ 1,500,000 (planned) $ 2,000,000 (planned)
2026 $ 2,500,000 (planned) $ 2,500,000 (planned)
2027 $ 2,000,000 (planned) $ 2,260,810 (planned)
Business Case Justification Narrative Template Version: January 2023 Page 2 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 12 of 271

Docusign Envelope ID:C003B28D-A736-4712-A545-D8A2EC25F327
Automation Replacement
Business Case Justification Narrative Template Version: January 2023 Page 3 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 13 of 271

Docusign Envelope ID:C003B28D-A736-4712-A545-D8A2EC25F327
Automation Replacement
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The purpose of this program is to replace aging Distributed Control Systems
(DCS), Programmable Logic Controllers (PLC). DCSs and PI-Cs, referred to as
controllers, are used throughout Avista's generating facilities to control and
monitor Avista's generating units and auxiliary systems. Controllers collect
meter data that is used in logic programs. Controllers used in generating
facilities to automate, control, and monitor are aging and introducing an increase
in hardware, software, and communication failures that limit Avista's ability to
operate generating facilities reliably. The aging hardware of concern requires
computer drivers that do not fit in new computers therefore we are required to
operate computers with legacy operating systems. This creates a Cyber
Security risk.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant& Operations) and the benefits to the customer
The major driver of this business case is Asset Condition. Outdated controllers
have modules that are over 20 years old and spare parts are limited. Additional
laptops must be maintained to configure Bailey and Modicon. Vulnerability
scanning is not performed on outdated control systems. Incorporating aging
controllers into modern designs is limited and often not possible. Improving the
asset condition in this case will improve reliability within the generating facilities.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Replacing controllers with new standards will reduce cyber security risk and
unexpected plant outages that require emergency repair with like equipment.
Planned projects to replace aging controllers and governors before they fail will
allow for more efficient upgrades with standardized hardware and software that
engineers, and technicians are trained on.
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.
Replacing hardware before it fails and software before it introduces a security
risk while moving toward our standardized controllers and governors will be a
success. In the past we've planned on upgrading controllers and governors
during unit overhauls, but this pace is slow when equipment is 20 years old and
spare parts are not readily available. The intent of this business case is to
increase the number of controllers being replaced today which is about 1-3
controllers a year.
Business Case Justification Narrative Template Version: January 2023 Page 4 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 14 of 271

Docusign Envelope ID:C003B28D-A736-4712-A545-D8A2EC25F327
Automation Replacement
2. PROPOSAL AND RECOMMENDED SOLUTION
The recommended solution is to upgrade all controllers and governors. It
includes replacing all aging controllers proactively on a schedule that takes into
account resources, outage availability, and EIM schedule demands. This option
addresses aging hardware and software concerns as well as the cyber security
vulnerabilities.
Remaininq in Scope: Noxon Rapids PLC, protection components, governors,
and the network components and interfaces to support same.
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The out-going equipment has aged to the point to present significant risk to
operation, either due to increased maintenance/attention or failure. These
upgrades are consistent with similar efforts across the Avista network, and will
contribute to unit, site, and network reliability for years to come.
2.2 Discuss how the requested recommended solution 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 or increases to O&M, Depreciation, Amortization or other
related Capital projects as a result of this investment.
Year Planned Spend Amount per Year
2025 $1,500,000
2026 $2,500,000
2027 j $2,000,000
Limited resources for design and construction, as well as available outages,
make it necessary for upgrades to be spread out over several years.
Business Case Justification Narrative Template Version: January 2023 Page 5 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 15 of 271

Docusign Envelope ID:C003B28D-A736-4712-A545-D8A2EC25F327
Automation 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.
Additional resources are required in order to maintain a schedule and
consistently meet the objectives. Engineering will require a designer to develop
new logic programs and designs for installations. The Protection Control Meter
Shop will need a resource to install and commission the PLC programs. The
capital cost takes into account resources needed to perform designs and
installations. It also takes into consideration feasibility of plant outages as
projects are spread out over time.
This project will benefit Power Supply and System Operations as they are
responsible for dispatching power from Cabinet Gorge plant to meet contractual
obligations and managing the day-to-day transmission system operational
requirements. It will also benefit engineering and the shops as they are
responsible for providing maintenance and support with the generating facilities.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The recommended solution is to upgrade all controllers and governors. It
includes replacing all aging controllers proactively on a schedule that takes into
account resources, outage availability, and EIM schedule demands. This option
addresses aging hardware and software concerns as well as the cyber security
vulnerabilities.
Alternative 1: Upgrade Software on the Controllers
This would include replacing each system's software that runs on Windows 95
and Windows XP with a separate software for each platform that runs on
Windows 10. This will mitigate the software and cyber security issue but not the
aging hardware issue. Outages would be required, and the new logic programs
would need to be rewritten and fully commissioned. Upgrading the Bailey
software and the Modicon software do not align with our standard PLC platform
that our engineers and technicians are trained on. This would introduce two new
software applications. Efficiency to troubleshoot and resolve issues in a timely
manner could be impacted.
Alternative 2: Do Nothing
The do nothing alternative would be to maintain existing controllers as we
currently do today. This includes replacing controller modules as they fail with
old spare parts or refurbish third party parts. Maintaining spare parts allows us
to continue using existing infrastructure and logic programs but it does not
resolve the long-term issue which is aging equipment that will eventually no
longer be available. The risk of outages at undesirable times to replace failed
parts becomes more likely the longer the aging hardware is in service. This
alternative also does not resolve the issue with computers that have
unsupported operating systems and are considered a cyber security risk.
Business Case Justification Narrative Template Version: January 2023 Page 6 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 16 of 271

Docusign Envelope ID:C003B28D-A736-4712-A545-D8A2EC25F327
Automation Replacement
2.5 Include a timeline of when this work will be started and completed.
Describe when the investments become used and useful to the custome
The work under this BUN began in 2018 and shifts to Noxon for 2025, 2026,
and 2027. Similar to the other upgrade efforts, designs takes place in the first
year with installation and transfer to plant immediately following. In this
instance, the installation and TTP of the Noxon units are planned for 2026 and
2027.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
By proactively replacing aging controllers and governors we are able to increase
reliability within our generating facilities. This program safely, responsibly, and
affordably improves our customers' lives through innovative energy solutions.
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 controllers and governors are both single point failures. If these devices fail,
they will cause either a single unit outage or a wider plant outage. If spare parts,
from the limited supply on hand, can be found then the outage can be minimized
but operating generating facility on outdated equipment requiring computers
with unsupported operating systems is not sustainable, responsible, or cost
effective, and exposes the generating facilities to unnecessary risk.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
• Controls Engineering
• SCADA Engineering
• Mechanical Engineering
• Project Management
• Network Engineering
• Network Operations
• PCM Shop
• Electric Shop
• Mechanic Shop
• Telecom Shop
• Hydro Operations
• Thermal Operations
Business Case Justification Narrative Template Version: January 2023 Page 7 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 17 of 271

Docusign Envelope ID:C003B28D-A736-4712-A545-D8A2EC25F327
Automation Replacement
2.8.2 Identify any related Business Cases
This business case is related to the HMI Control Software business case.
As new control software and computers with Windows 10 are planned to
be installed over the next couple years they need to communicate to
controllers. The oldest of the aging controllers require computer drivers
that do not fit in new computers.
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Each project will have a project manager and steering committee for ongoing
vetting. The steering committee for each project will consist of the Controls
Engineering Manager, the Protection Control Meter Technician Foreman, the
SCADA Engineering Manager, and either the Spokane River Plant Operations
Manager, Cabinet Gorge Plant Operations Manager, Noxon Rapids Plant
Operations Manager, Lower Spokane River Plant Operations Manager, or
Thermal Operations Plant Manager
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 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.
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.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
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.
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
Business Case Justification Narrative Template Version: January 2023 Page 8 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 18 of 271

Docusign Envelope ID:C003B28D-A736-4712-A545-D8A2EC25F327
Automation Replacement
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 Automation Replacement
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.
Signed by:
Signature: Date: Sep-16-2024 1 3:39 PM PDT
Print Name: risTna3 ewhouse
Title: Controls/Electrical Engineering
Mgr
Role: Business Case Owner
Signed by:
Signature: Date: Sep-17-2024 1 12:49 PM PDT
avu ewt,l.(,
Print Name: 6VJff5HM11
Title: Director, GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: January 2023 Page 9 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 19 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Boulder Park Engine Control Upgrades
EXECUTIVE SUMMARY
PROJECT NEED: The engines at Boulder Park Generating Station (BPGS) have suffered
multiple control module component failures over the years on the WECS8000 (Wartsila Engine
Control System). These modules are on each of the six generating units and are critical to their
operation. Spare parts are no longer available from the station's existing inventory of spare parts
and the manufacturer no longer offers support for the WECS8000.
RECOMMENDED SOLUTION: To ensure generation reliability, the entire control system
needs to be replaced for all 6 units.
ALTERNATIVES CONSIDERED:
• Alternative 1 (approved): Non-OEM Vendor Upgrade only exciter and governor controls
• Alternative 2: OEM Upgrade
• Alternative 3: Do Nothing
COST OF RECOMMENDED SOLUTION: The total cost of the project is expected to be
$5,000,000 based on quotes from the vendor that will be performing the upgrade. Engineering
will be completed in 2024, with the most equipment installation in 2025. The balance of equipment
installation is planned for 2026. The anticipated TTP schedule reflects this installation plan, as
the upgraded equipment will be immediately'used and useful' as each unit is complete and placed
in service.
ADDITIONAL INFO: The replacement of the control modules at Boulder Park Generating
Station will benefit customers by making the generating station more reliable. Being proactive in
the replacement allows for equipment to be purchased and designed in preparation for a planned
outage, to minimize the outage as much as possible. Since spare parts and support are no longer
available on the existing control modules, the plant is at risk of a failure on any of the 6 generating
units that would put the failed unit out of service until a new control module can be designed and
installed.
Alternative 1 was approved via FCR in April 2024. Spend estimates and timelines for this project
are consistent with that FCR and have been confirmed for annual review/approval.
VERSION HISTORY
Version Author Description Date Notes
1.0 Kristina Initial draft of original business 05/25/2022 Executive Summary Only
Newhouse case
Kristina
1.1 Newhouse & Original submission 08/26/2022
Jeremy Winkle
No substantive
2.0 Jessica Bean Transfer to new BCJN Template 01/06/2023 changes/edits have been
made to the business
case through this transfer
2.1 Kristina Modifications and additional 05/10/2023
Newhouse information for the new template
Business Case Justification Narrative Template Version: January 2023 Page 1 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 20 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Boulder Park Engine Control Upgrades
BCRT Team Has been reviewed by BCRT
BCRT member and meets necessary
re uirements
3.0 Kristina Update for FCR submittal 03/15/2024
Newhouse
3.1 Don Sherrill Updated/confirmed following 07/23/2024
annual CPG approval.
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2024 $ 1,500,000 $ 0
2025 $ 2,500,000 $4,000,000
2026 $ 1,000,000 $ 1,000,000
2027 $ 0 $ 0
2028 $ 0 $ 0
1.1 CLICK OR TAP HERE TO ENTER TEXT.
Project Life Span 2 years
Requesting Organization/Department GPSS
Business Case Owner I Sponsor Mike Mecham David Howell
Sponsor Organization/Department GPSS
Phase Execution
Category Project
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's
site see link.
Investment Drivers
Business Case Justification Narrative Template Version: January 2023 Page 2 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 21 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Boulder Park Engine Control Upgrades
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.
1.2 What is the current or potential problem that is being addressed?
The engines at the Boulder Park Generating Station have suffered multiple
control module component failures over the years on the WECS8000 (Wartsila
Engine Control System). These modules are on each of the six generating units
and are critical to their operation. Spare parts are no longer available from the
station's existing inventory of spare parts and the manufacturer no longer offers
support for the WECS8000. To ensure generation reliability, the entire control
system needs to be replaced for all six units. The replacement of the control
modules at Boulder Park Generating Station will benefit customers by making
the generating station more reliable. Being proactive in the replacement allows
for equipment to be purchased and designed in preparation for a planned
outage, to minimize the outage as much as possible.
1.3 Discuss the major drivers of the business case.
The major driver for this business case is asset condition. Since spare parts and
support are no longer available on the existing control modules the plant is at
risk of a failure on any of the six generating units that would put the failed unit
out of service until a new control module can be designed and installed. The
replacement of the control modules at Boulder Park Generating Station will
benefit customers by making the generating station more reliable. Being
proactive in the replacement allows for equipment to be purchased and
designed in preparation for a planned outage, to minimize the outage and impact
to the system as much as possible.
1.4 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 engine control modules have experienced periodic failures over the years.
These modules are necessary to control and monitor the engines. A failure of a
single module causes a unit outage and loss of generation. The engine
manufacturers no longer offer spare parts for the control system and there are
no third-party spare part suppliers. As control modules fail, the engine will need
to be placed out of service until a new control system can be designed and
installed. The OEM provided an estimated delivery time of 52 weeks to replace
a failed control system.
1.5 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
Business Case Justification Narrative Template Version: January 2023 Page 3 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 22 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Boulder Park Engine Control Upgrades
Our goal is that this project safely, responsibly, and affordably improves the level
of service we provide to our customers by minimizing direct impacts to services.
This approach allows us to proactively replace equipment that spare parts are
not available for. This in turn, shortens potential outage times if there is a failure
and allows our operations team to reserve capacity for other critical needs.
1.6 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.
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.
Approved (Recommended) Solution: The approved solution is to upgrade the
engine controls and protection systems for all six engines. Utilizing a non-
Original Equipment Manufacturer (OEM) vendor for the control system design,
equipment procurement, and construction support instead of the standard OEM
design is preferred. The advantages of utilizing a third-party vendor include
competitive pricing, a modular design with multiple spare part options, and an
improved support model. This approach increases the pool of qualified
resources to support the engine control system and make operational
improvements. Also, the engineering cost and equipment costs are much less
than utilizing OEM's propriety design and equipment.
While this option is very economical and maintainable, there is risk to
proceeding with not utilizing the OEM. The greatest risk is design and
construction challenges that could result in delays due to insufficient proprietary
engine knowledge. The risk will be mitigated by verifying the vendor's
qualifications and past performance. Additionally, the design and construction
contract will be structured to limit negative impacts to Avista.
In Scope: Exciter replacement, all WECS8000 items including wiring harnesses,
control modules, new PLC. Updates to ethernet switches, routers, firewall,
engine controls, control modules with 10, governor controls, voltage regulator,
operator panel, SEL generator protective relay, speed probes, junction boxes,
' 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 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 23 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Boulder Park Engine Control Upgrades
ignition coils, and other items listed per cost estimate from vendor. Ignition
design and HMI cutover.
Out of Scope: Operating screens for the units; operating computers
Assumptions: reuse existing transducers
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
• Multiple factors were considered to prepare this capital request.
Investigations created valuable information on the current state of the control
system. Budgetary quotes requested and received to establish estimated
budgets and project delivery schedules. Financial analyses were conducted
to estimate the value of the unplanned outages potentially caused by failed
controls system.
• After inventorying and testing existing spare parts, Avista reached out to the
OEM and third-party part suppliers for additional spare parts. The OEM
informed Avista there was no longer support or spare parts available and
provided the control system upgrade as the only support option. Due to the
propriety nature of the OEM control system, third party suppliers were not
able to locate any spare parts.
• The limited number of spare parts on hand and the inability to purchase
additional spare parts creates a significant risk for operating the engines
reliably in the short and long term. The first step in starting to mitigate the
risk was to reach out to parties qualified and experienced to replace engine
control systems. Avista received budgetary quotes from the OEM and a non-
OEM vendor. These budgetary quotes provide the basis for analyzing the
benefits and drawbacks of each solution and greatly inform the preferred
solution.
• The 2023 Thermal Daily Outage Cost Estimation Tool was used to consider
the cost of an extended unplanned outage. The tool is used to generate an
approximate daily outage cost for thermal plant and estimates the cost of
daily outage for a 4.1 MW engine at BPGS to be $1,300.00 per day.
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 5 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 24 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Boulder Park Engine Control Upgrades
• CARS (Capital Additions and Retirement) form which documents added and
removed assets associated with Avista's facilities. This document helps
Avista maintain accurate continuing property records.
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 NA $0 $0 $0 $0 $0
O&M NA $0 $0 $0 $0 $0
Estimated direct savings, including hard cost savings, has not been quantified.
However, it is recognized that the recommended solution will result in a more
reliable and maintainable control system that will help control and minimize O&M
costs over the expected life of the system. The replacement parts for modular
design of the new control system will be more readily available and cost efficient.
Wherever possible Avista's standard equipment and design protocol, such as
Schweitzer Protection Relays and Allen Bradley Controllogix PI-Cs, will be
utilized. Utilizing standard equipment will reduce labor cost associated with
troubleshooting and maintaining the control system.
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital NA $0 $0 $0 $0 $0
O&M NA $0 $0 $0 $0 $0
Overall, the capital cost will result in less O&M costs without adding any
additional staffing. However, estimated indirect savings and/or productivity
gains and associated benefits have not been quantified at this time; however,
as applicable, please see the referenced Risk Based Investment report (see
Section 2.2) for additional information.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: January 2023 Page 6 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 25 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Boulder Park Engine Control Upgrades
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
RECOMMENDED ALTERNATIVE: The recommended solution is to upgrade
the engine controls and protection systems for all six engines. Utilizing a non-
OEM vendor for control system design, equipment procurement, and
construction support instead of the standard OEM design is preferred.
Approved Alternative 1: Non-OEM Vendor Upgrade only exciter and
governor controls.; $5,000,000
There was limited production and installation of the Wartsila 18V28SG Engine.
Consequently, the OEM has limited experience upgrading these engines with
new control systems resulting in increased engineering costs. Additionally, the
OEM uses proprietary parts that are difficult to troubleshoot and maintain over
the expected life of the control system. The additional cost to upgrade the
engine control system utilizing the OEM's proposed solution does not provide
any additional benefit to customers or improved reliability compared to a non-
OEM solution.
Alternative 2: OEM Upgrade; $5,080,853
There was limited production and installation of the Wartsila 18V28SG Engine.
Consequently, the OEM has limited experience upgrading these engines with
new control systems resulting in increased engineering costs. Additionally, the
OEM uses proprietary parts that are difficult to troubleshoot and maintain over
the expected life of the control system. The additional cost of over two million
dollars to upgrade the engine control system utilizing the OEM's proposed
solution does not provide any additional benefit to customers or improved
reliability compared to a non-OEM solution.
Alternative 3: Do Nothing; $0 Capital Cost
The option to not upgrade the engine control system has been considered and
creates the highest amount of risk. Since spare parts are not available, the
failures will eventually result in an extended outage. The OEM provided an
estimated delivery time of 52 weeks to replace a failed control system.
Therefore, the expected outage time for an engine would be at least 52 weeks.
Based on the 2023 Thermal Daily Outage Estimation Tool developed with
Avista's Power Supply department, the daily outage cost for a 4.1 MW engine
is $1,300.00 and the potential cost for a 52-week outage would be $473,200.
There are few options to mitigate the risks in this scenario. Plan for upgrade and
minimize outage time with other options. Eventually, remove an engine from
service and utilize parts to keep other engines in service.
Business Case Justification Narrative Template Version: January 2023 Page 7 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 26 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Boulder Park Engine Control Upgrades
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 continued delivery of reliable power from the BPGS will determine whether
the investment is successful. This will be measured by determining the overall
cost of lost generation due to extended outages and the number of unplanned
outages due to control system issues.
• Without this investment, the engine control system modules will continue to
fail until there are no longer spare parts to restore the engine. This will
require permanently shutting down the engine until a new control system can
be restored. As stated above, upon failure, it is currently estimated to take
52 weeks to replace the control system for an engine. Proceeding with this
investment will allow Avista to plan a shorter outage during the optimal time
of year to significantly reduce the cost of lost generation.
• The existing control system experiences failures or malfunctions that are
difficult to troubleshoot due to lack of spare parts and the proprietary nature
of the OEM control system. An upgraded control system will increase the
availability of spare parts and provide Avista engineers and technicians with
better visibility for troubleshooting. This will reduce the number and length
of unplanned outages.
2.7 Include a timeline of when this work is scheduled to commence and
complete, if known.
❑x Timeline is Known
• Start Date: 2024
• End Date: 2025
❑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
The Steering Committee consists of the following members: Manager of Project
Delivery, Manager of Maintenance and Construction, and Manager of Thermal
Operations & Maintenance.
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
Business Case Justification Narrative Template Version: January 2023 Page 8 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 27 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Boulder Park Engine Control Upgrades
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.
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Boulder Park Engine
Controls Upgrade 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.
[:�
gned by:
Signature: U, hu'6w Date: Sep-04-2024 1 2:33 PM PDT
Print Name: Mike Mecham
Title: GPSS Plant O&M Manager, Spokane
Thermal
Role: Business Case Owner
5Signed by:
AW1Rewt,l.(,Signature: Date: sep-06-2024 1 3:17 PM PDT
Print Name: Wfd l6WeII
Title: Director, GPSS
Role: Business Case Sponsor
Signature: NA Date:
Print Name: NA; Committees have not been
stood up at this time.
Title: NA
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: January 2023 Page 9 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 28 of 271

Cabinet Gorge Dam Fishway
EXECUTIVE SUMMARY
The Clark Fork Settlement Agreement (CFSA) and FERC License require Avista to implement
the Native Salmonid Restoration Plan (NSRP), which includes a stepwise approach to
investigating, designing and implementing fish passage at the Clark Fork Project. Appendix C
of the CFSA commits Avista to fund the Cabinet Gorge Dam Fishway (Fishway) design and
construction as well as annual operations and maintenance. Additionally Avista is required to
evaluate and optimize the operation of the Fishway by implementing the Monitoring and
Evaluation Plan. Fish passage is intended to restore connectivity of native salmonid species in
the lower Clark Fork watersheds. During relicensing the U.S. Fish & Wildlife Service (USFWS)
reserved its authority under Section 18 of the Federal Power Act to require fish passage at both
Noxon Rapids and Cabinet Gorge dams, in order to pursue the NSRP more collaboratively.
Those efforts, including involvement of Native American tribes and state agencies, as well as
other stakeholders, continued over 15 years to the current project.
The Agreement and License support all electric customers in Washington and Idaho by
authorizing the continued operation of Noxon Rapids and Cabinet Gorge dams. In Amendment
No. 1 to the CFSA, Avista agreed to construct and operate a permanent upstream fishway
facility, consistent with the objective and purpose of the design approved by a Design Review
Team (DRT)on January 13, 2013, and modified to include a two-chamber trap and siphon water
supply approved by the DRT in July 2017. Any subsequent changes to the design that may
affect the design criteria identified in the final Basis of the Design Report would require approval
by the USFWS. This agreement provides protection for Avista from being ordered to build
alternative facilities at Cabinet Gorge for the term of the FERC License and also satisfies
obligations under the Endangered Species Act as well as Federal Power Act Section 18. The
construction of the Fishway was successfully completed Q2 of 2022. Approval of this business
case will benefit our customers by maintaining compliance with the CFSA and FERC License
and subsequent agreements, which provide operational flexibility at Avista's Noxon Rapids and
Cabinet Gorge Hydro-Electric Facilities.
VERSION HISTORY
Version Author Description Date
1.0 Monica Ott Initial draft of original business case 811123
2.0 Monica Ott Information moved to new 2025-2029 template 512124
BCRT I Heide Evans Has been reviewed by BCRT and meets necessary requirements 1 9130123
Business Case Justification Narrative Template Version: February 2023 Page 1 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 29 of 271

Cabinet Gorge Dam Fishway
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2025 $400,000 $400,000
2026 $100,000 $100,000
2027 $100,000 $100,000
2028 $100,000 $100,000
2029 $100,000 $100,000
Project Life Span 1 year
Requesting Organization/Department B04/Clark Fork License
Business Case Owner I Sponsor Monica Ott/ Bruce Howard
Sponsor Organization/Department A04 / Environmental Affairs
Phase Execution
Category Mandatory
Driver Mandatory& Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
Cabinet Gorge Dam blocks upstream passage for key fish species to spawning
tributaries. To address these impacts to fisheries, a fish passage program requirement
was incorporated into the Clark Fork Settlement Agreement and FERC License No.
2058 issues for the Clark Fork Project in 2001. Design, Construction and Operation of
the Fishway partially fulfills the upstream fish passage requirements.
1.2 Discuss the major drivers of the business case.
Investment Drivers
The investment driver associated with the CFSA and FERC License fall under
Mandatory and Compliance. Benefit to our customers and the company is the ability to
provide clean, reliable and cost-effective power.
Business Case Justification Narrative Template Version: February 2023 Page 2 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 30 of 271

Cabinet Gorge Dam Fishway
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, working closely with interested stakeholder groups, began implementation of an
Upstream Fish Passage Program for Bull Trout in 2001 as part of Appendix C of the
CFSA. A similar program for Westslope Cutthroat Trout was initiated in 2015, and the
results of this study help inform fish passage decisions. Bull Trout are listed as
threatened under the Endangered Species Act and Westslope Cutthroat Trout are a
species of specific concern in both Montana and Idaho. A number of fish collection
methods have been employed to capture these fish in order to transport them upstream
of the dams. The use of these methods has resulted in some level of fish capture
success; however, there is evidence the majority of the fish that are approaching
Cabinet Gorge Dam are not being captured and not all fish that are captured are
captured the first time they approach the dam. The Fishway was constructed to
capture a larger number of the migratory native salmonids that are approaching Cabinet
Gorge Dam. The goal of construction and operation of the CGDF is to provide timely
and effective upstream passage for native trout species in support of broad native
salmonid recovery and connectivity in the lower Clark Fork watershed. The signatories
to the CFSA agree that the construction and operation of upstream and downstream
fishways, and the provisions in Amendment No. 1 to the CFSA is in the public interest
and that it satisfies various agency authorities applicable to the Project. Critical among
the authorities cited are Section 18 of the Federal Power Act, the Endangered Species
Act, the Clean Water Act, state fishway and transport regulations, and USFWS's 1999
Biological Opinion for licensing and operating the Project for the term of the License.
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
Remaining in compliance allows for the continued operation of the Clark Fork and Clark
Fork River HED facilities and operating them safely and responsibly. The project will
focus on the people responsible for the delivering with a strong emphasis on
performance. The nature of the project demands a collaborative environment with a
wide array of key stakeholder groups. These efforts align with Avista's values of
collaboration and environmental stewardship.
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 CFSA under FERC License No. 2058 issued for the Clark Fork Project in 2001,
and Amendment No. 1 of the CFSA both stipulate that Avista will construct and operate
a fish passage facility for Bull Trout at Cabinet Gorge Dam.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 31 of 271

Cabinet Gorge Dam Fishway
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.
Construction and successful operation of the Cabinet Gorge Dam Fishway is a
requirement of the Clark Fork FERC License and CFSA. Compliance with these
obligations allows the continued operations of Cabinet Gorge and Noxon Rapids dam,
maintains relationships with the stakeholders making management decisions of
Avista's obligated funding, and is in Avista's best interest for continued operational
flexibilty on the Clark Fork River.
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
Operation of the Cabinet Gorge Dam Fishway is a requirement of the Clark Fork FERC
License and CFSA.
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&M $ $ $ $ $
There are no quantifiable direct savings for implementing this compliance element of
the Clark Fork Settlement Agreement and FERC License. Construction of the Fishway
is required under the CFSA. Making the Fishway successful will provide cost saving in
the future as other methods of fish passage currently employed will not need to be used
and Avista will likely not be required to construct a new facility during the next
relicensing of the Clark Fork Project.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 32 of 271

Cabinet Gorge Dam Fishway
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
There are no quantifiable in-direct savings for implementing this compliance element
of the Clark Fork Settlement Agreement and FERC License. Construction of the
Fishway is required under the CFSA.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
Alternative 1:
No alternative exists for construction and operation of a fish passage facility at Cabinet
Gorge Dam (see above). This plan is a result of our FERC License requirements and
subsequent negotiations. If Avista does not build a fish passage facility at Cabinet
Gorge Dam, FERC could issue orders, penalties or even rescind our operating license.
Additionally, the USFWS could take legal action under Section 18 to order Avista to
build the facility, with none of the assurances enacted by agreement in the CFSA
Amendment No. 1.
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).
Avista is implementing a robust monitoring and evaluation plan that includes fish
monitoring devices both downstream of the Fishway and at strategic locations in the
Fishway. The fish monitoring devices will provide valuable information on the presence
of tagged Bull Trout and Westslope Cutthroat Trout in the area. These metrics will be
used to evaluate the success of the Fishway including the ability of flow in the Fishway
to attract target species to the Fishway and whether or not fish are attracted into the
final capture pool.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
This is an ongoing commitment running with the Clark Fork FERC License No.2058
and will continue until the License expires in 2046.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 33 of 271

Cabinet Gorge Dam Fishway
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.
Avista and over 20 other parties, including the States of Idaho and Montana, various
federal agencies, five Native American tribes, and numerous Non-Governmental
Organizations form the Clark Fork Management Committee which has ultimate
authority on actions and budgets for the Fishway. In addition, we coordinate with
numerous internal stakeholders, in particular within GPSS and Power Supply. The
steering committee for the Fishway is made up of representatives from GPSS and
Environmental.
Responsible managers include the Clark Fork License Manager, Sr. Director of
Environmental Affairs, and Sr VP Energy Resources & Env Comp Officer along
withmany other internal and external stakeholders. Externally, we submit annual work
plans and reports to FERC for its review and approval. Many decisions are subject,
per the License, to oversight by the Clark Fork Management Committee, consisting of
settlement party members.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 34 of 271

Cabinet Gorge Dam Fishway
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Cabinet Gorge Dam Fishway and agree with
the approach it presents. Significant changes to this will be coordinated with and approved by the
undersigned or their designated representatives.
Signature: Date:
Print Name: Monica Ott
Title: Clark Fork License Manager
Role: Business Case Owner
Signature: Date:
Print Name: Bruce Howard
Title: Sr Dir Environmental Affirs
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 7 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 35 of 271

Docusign Envelope ID:07DDDF28-E3C9-4DB7-ABCF-DF47A8FECO26
Cabinet Gorge HVAC
EXECUTIVE SUMMARY
The current ventilation system in the powerhouse at the Cabinet Gorge Hydroelectric
Development (Cabinet Gorge) is still the original system and equipment that was installed
in 1952. The system needs to be replaced because the original ventilation system
controls are no longer functional and have been removed. There is no cooling capacity
with the current ventilation system and the current air handling system can only be
operated manually for ventilating and exhausting powerhouse air. There is no filter system
for plant make up air which results in outside smoke from wildfires and dust in the outside
air from entering the plant. The current summer temperatures in the powerhouse routinely
rise to 90°F and additional transformers and electrical equipment planned to be installed
within the powerhouse over the next three years will significantly increase internal plant
heat loading.
To be able to support a satisfactory work environment for plant personnel and enable
sufficient cooling for critical electrical equipment, the Cabinet Gorge powerhouse needs
to have a new HVAC System with significant cooling capacity. 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. Operating Cabinet Gorge 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).
Cabinet Gorge has operational flexibility and is 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. The capacity of this plant alone
is 270 MW. The estimated cost of the project is $1.75 Million, and it is critical that this
project is completed. The new Station Service upgrade which is expected to be completed
in 2023 will produce an additional heat load in the plant. This new HVAC system will
provide the needed plant cooling of this new equipment and provide sufficient heating,
ventilation and air conditioning in support of normal operations of the plant. Without this
system replacement, plant personnel will be subjected to unacceptably high internal
powerhouse temperatures and critical electrical equipment will fail due to inadequate
cooling.
VERSION HISTORY
Version Author Description Date Notes
Draft Bob Weisbeck Initial draft of original business case 06/30/2020
1.0 Bob Weisbeck Updated Approval Status 06/30/2020 Full amount
approved
2.0 Chris Clemens Updated for the 2022-2026 07/6/2021 5-year Capital
SCRUM Planning Process
Business Case Justification Narrative Pale 1 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 36 of 271

Docusign Envelope ID:07DDDF28-E3C9-4DB7-ABCF-DF47A8FECO26
Cabinet Gorge HVAC
2.0 Chris Clemens Updated for the 2023-2027 08/23/2022 5-year Capital
SCRUM Planning Process
3.0 Don Sherrill Updated/confirmed following 09/03/2024
annual CPG approval.
GENERAL INFORMATION
Revised Spend Amount $2,750,000
Requested Spend Time Period 2 years
Requesting Organization/Department D07/GPSS
Business Case Owner I Sponsor Greg Wiggins I David Howell
Sponsor Organization/Department A07/GPSS
Phase Execution
Category Project
Driver Failed Plant&Operations
YEAR PLANNED SPEND AMOUNT ($) PLANNED TRANSFER TO PLANT
2024 $ 1,500,000 $ 0
2025 $ 1,250,000 $ 2,750,000
2026 $ 0 $ 0
2027 $ 0 $ 0
2028 $ 0 $ 0
Business Case Justification Narrative Page 2 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 37 of 271

Docusign Envelope ID:07DDDF28-E3C9-4DB7-ABCF-DF47A8FECO26
Cabinet Gorge HVAC
�. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The HVAC system at Cabinet Gorge is nearly 70 years old and is no longer in
working order. The controls have failed and have been removed. The system
is operated manually and currently only provides unfiltered outside air which is
problematic during wildfire season and the introduction of dust in the
powerhouse. The temperature in the plant is not regulated effectively with
summertime temperatures reaching up to 90OF inside the powerhouse. New
electrical upgrades to the station service will introduce a significant heat load.
Without a new system the temperature in the plant will exceed acceptable
temperatures for operational personnel and critical electrical equipment.
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 heating and ventilation
system is no longer functional. A new HVAC system will support the loads of
critical upgrades to the electrical system, improve the working conditions of the
powerhouse with filtered air and temperature control and enable the plant to
function effectively into the future. Cabinet Gorge has operational flexibility and
is operated to support energy supply, peaking power, provide continuous and
automatic adjustment of output to match changing loads, and other types of
services necessary to provide a stable electric grid and to maximize value to
Avista and its customers.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
There is no cooling capacity with the current ventilation system and the current
air handling system can only be operated manually for ventilating and
exhausting powerhouse air. There is no filter system for plant make up air which
results in outside smoke from wildfires and dust in the outside air from entering
the plant. The current summer temperatures in the powerhouse routinely rise to
90OF and additional transformers and electrical equipment planned to be
installed within the powerhouse as part of the Station Service Upgrade Project
over the next three years will significantly increase internal plant heat loading.
Business Case Justification Narrative Page 3 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 38 of 271

Docusign Envelope ID:07DDDF28-E3C9-4DB7-ABCF-DF47A8FECO26
Cabinet Gorge HVAC
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 HVAC system will be designed to heat and cool the plant to adequate
working temperature for plant personnel. The system will also be designed to
adequately filter outside air to protect personal and equipment from outside
contaminants. In addition, the system will be designed to compensate for the
heat load of existing and proposed critical electrical equipment. These types of
systems currently exist in other facilities similar to this powerhouse. The
measure of success will be air quality and temperature control inside the
powerhouse.
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.
The metric supporting the replacement of the current system is that it is
no longer functional. Air intake and exhaust are now performed manually.
Make up air is not filtered allowing outside contaminants such as smoke
and dust to enter the powerhouse. Internal temperature of the plant is not
controlled effectively. The introduction of new electrical equipment which
will significantly increase the heat load, will only make the problem worse.
Option Capital Cost Start Complete
Replace with new HVAC System $1,750,000 01 2023 122024
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. The
current system is not adequate to prevent contaminates from entering the plant,
Business Case Justification Narrative Page 4 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 39 of 271

Docusign Envelope ID:07DDDF28-E3C9-4DB7-ABCF-DF47A8FECO26
Cabinet Gorge HVAC
is manually controlled, does not adequately control internal plant temperature
and will not support critical plant electrical upgrades due to the increased heat
load. Without a proper HVAC system, operation of the plant will be put at risk
due to unacceptable working conditions for operational personnel and risk to
critical electrical equipment overheating.
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 and sourcing of the equipment. This is estimated to be $250,000. The
second year will include equipment removal, new equipment installation and
commissioning. This is estimated to be $1,500,000. This will not offset
significant O&M charges because the equipment has failed so it is no longer
maintained. The risk is to personnel due to the lack of air quality control and
powerhouse temperature control and the risk to critical electrical equipment.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
The execution of this project will enable the needed upgrade of the Cabinet
Gorge Station Service project. The Station Service at this plant is at the end of
its useful life. The plant cannot function without this critical system. This critical
system will be at risk without adequate cooling. The temperature in the plant
and inadequate air quality is also no longer be acceptable.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The repair of the existing unit was considered, but the age of the equipment and
the removal of failed components prevent this from being a feasible option. In
addition, even if this system could be repaired, the heat load of the plant will
increase with critical electrical system upgrades which are planned in the next
three years.
The only feasible alternative is to install a HVAC system which will handle the
new electrical loads, filter the air properly, and adequately control the
temperature in the powerhouse.
Business Case Justification Narrative Page 5 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 40 of 271

Docusign Envelope ID:07DDDF28-E3C9-4DB7-ABCF-DF47A8FECO26
Cabinet Gorge HVAC
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 and equipment sourcing. The effort in the second year will
consist of equipment removal, new equipment installation and system
commissioning. The transfer to plant will be at the end of the second year with
the completion of commissioning.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Cabinet Gorge affordably supports the power needs of our company and our
customers. 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 Cabinet
Gorge is performing at a high level and serving our customers with affordable
and reliable energy.
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 HVAC systems of this size and complexity fall into this range of cost.
The system will need to be designed based on the estimated heat load and the
air make up systems will need to be custom made to fit this powerhouse.
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
at Cabinet Gorge, Cabinet Gorge Plant personnel, GPSS Engineering,
Business Case Justification Narrative Page 6 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 41 of 271

Docusign Envelope ID:07DDDF28-E3C9-4DB7-ABCF-DF47A8FECO26
Cabinet Gorge HVAC
GPSS Construction and Maintenance, Power Supply, Environmental
Resources. 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 or along with the completion
of the Cabinet Gorge Station Service Project. The HVAC system needs
to be in place to support the increased heat load due to the critical
electrical system that will be part of the station service system.
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
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 42 of 271

Docusign Envelope ID:07DDDF28-E3C9-4DB7-ABCF-DF47A8FECO26
Cabinet Gorge HVAC
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.
Signed by:
Signature: Date: Sep-17-2024 1 4:32 AM PDT
A2 75CG64F9
Print Name: Greg ...
Igglns
Title: GPSS Manager of O&M
Role: Business Case Owner
Signed by:
Signature: 44 Rbwt,a Date: Sep-17-2024 1 12:28 PM PDT
Print Name: Davicowe�8
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 8 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 43 of 271

Docusign Envelope ID:C3C6C645-E841-48DC-A23D-A2966087CED8
Cabinet Gorge Station Service
EXECUTIVE SUMMARY
PROJECT NEED: Cabinet Gorge Hydroelectric Development (HED) is the second largest
such 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. In
particular, the Station Service equipment is vital to the plant's continued operation. Station
Service equipment includes Load Centers, Transformers, Switchgear, Power Centers
and Neutral Grounding Resisters. This equipment is used to operate the generating plant.
It includes energy consumed for plant lighting, power, and auxiliary facilities in support of
the electricity generation system. Built in 1952, the plant has retained most of its original
equipment which is now aging and at end of life.
RECOMMENDED SOLUTION: This approved project is upgrading the Station Service
Power Centers and associated equipment.
ALTERNATIVES CONSIDERED:
• Alternative 1: n/a. This is an approved, in-flight project.
COST OF RECOMMENDED SOLUTION AT TIME OF APPROVAL (2022): $17.6MM
CURRENT ESTIMATE AT COMPLETION (2025): $18.7MM.
ADDITIONAL INFO: If this equipment is not upgraded, failure poses substantial hazards
not only to the plant's operation but also to plant personnel as failed equipment can cause
significant bodily injury and fire danger. Increases in project cost are attributed to
inflationary impacts during the project, as well as costs associated with deferring elements
of the project to 2025 to free up capital in 2024 for other projects.
Business Case Justification Narrative Template Version: January 2023 Page 1 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 44 of 271

Docusign Envelope ID:C3C6C645-E841-48DC-A23D-A2966087CED8
Cabinet Gorge Station Service
VERSION HISTORY
Version Author Description Date Notes
1.0 Glen Farmer Initial draft of original business 08/1/2020
case
2.0 Chris Clemens Updated for the 2022-2026 07/6/2021 5-year Capital Planning
SCRUM Process
3.0 Chris Clemens Updated for the 2023-2027 08/23/2022 5-year Capital Planning
SCRUM Process
No substantive changes/edits
4.0 Jessica Bean Transfer to new BCJN Template 01/06/2023 have been made to the
business case through this
transfer
BCRT BCRT Team Has been reviewed by BCRT and
Member meets necessary requirements
5.0 Don Sherrill Updated/confirmed following 09/03/2024
annual CPG approval.
GENERAL INFORMATION
YEAR ACTUAL/PLANNED SPEND PLANNED TRANSFER TO
AMOUNT ($) PLANT ($)
2023 $ 6,913,566 $ 0
2024 $4,084,150 $ 0
2025 $ 1,250,000 $ 18.7MM
2026 $ 0 $ 0
2027 $ 0 $ 0
Project Life Span 2017-2025
Requesting Organization/Department GPSS
Business Case Owner I Sponsor Jeff Vogel David Howell
Sponsor Organization/Department GPSS
Phase Execution
Category Project
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's
site see link.
Investment Drivers
Business Case Justification Narrative Template Version: January 2023 Page 2 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 45 of 271

Docusign Envelope ID:C3C6C645-E841-48DC-A23D-A2966087CED8
Cabinet Gorge Station Service
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?
Station Service equipment is vital to the plant's continued operation. Station
Service equipment includes Load Centers, Transformers, Switchgear, Power
Centers and Neutral Grounding Resisters. This equipment is used to operate
the generating plant. The existing equipment is the original equipment. Issues
include manufacturers no longer support maintenance activities; can't add
anything to Station Service due to capacity limitations; decrease in reliability
and safety from the standpoint of protecting equipment and personnel.
1.2 Discuss the major drivers of the business case
Major drivers for this project include improved reliability and safety;
manufacturers support for maintenance; address additions to capacity and
obtain better insight into each individual feeder or starter.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
As many other equipment upgrades are underway at Cabinet Gorge, the timing
of these Station Service replacements has been coordinated to reduce plant
outages. In terms of risk, if this equipment is not upgraded, failure poses
substantial hazards not only to the plant's operation but also to plant personnel
as failed equipment can cause significant bodily injury and fire danger.
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
Upgrading the Station Service equipment at Cabinet Gorge contributes to the
safe and responsible design, construction, operation and maintenance of
Avista's generating fleet.
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.'
No studies were performed. However, in the 2000's, additional protection was
added to the existing main feeders to improve safety. Feeder breakers were
rebuilt in 2006. It was identified that the Power Centers and Load Centers were
in poor condition and without replacement parts, as equipment failed, we would
have to take either the Load Centers or Power Centers offline to attach
' 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 3 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 46 of 271

Docusign Envelope ID:C3C6C645-E841-48DC-A23D-A2966087CED8
Cabinet Gorge Station Service
disconnects to the bus. This would allow us to place equipment back in service
but would leave us exposed from a protection standpoint.
Business Case Justification Narrative Template Version: January 2023 Page 4 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 47 of 271

Docusign Envelope ID:C3C6C645-E841-48DC-A23D-A2966087CED8
Cabinet Gorge Station Service
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: This request is to upgrade the Station Service Power
Centers and associated equipment. This aging equipment should be replaced
to ensure the continued safe operation of the plant. New equipment will
contribute to grid optimization, reliability, and personnel safety.
In Scope: Upgrading capacity and configuration of the Station Service including
both Power Centers, Load Centers, Station Service Transformers; Emergency
Generator; Emergency Generator building to accommodate a much larger
generator; replacing all cabling from the load side of 480v station service, adding
new 13.8 KV protection breaker in SS1 .
Out of Scope: Individual utilization equipment will not be replaced.
Assumptions: New Station Service will connect to existing loads; Station Service
components are being designed from 13kV level to the lowest voltage and
approaching it as one system rather than individually addressing equipment
failures as they arise. The proposed solution is to replace the Transformers and
Power Centers first, subsequently these will feed the existing plant Load
Centers. Next, the team will install the Load Centers and energize them from
the new Power Centers in parallel to the existing plant. This will allow cutover of
individual loads without major downtime of the plant.
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
• When preparing this capital request for Emergency Loads, Power Centers
and Load Centers, we worked with Power Engineers to develop an
approach and preliminary budget.
• The project is in-flight, most of the equipment has been purchased, and
construction has started. The proposed budget to finish this project is based
on recent crew estimates.
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 5 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 48 of 271

Docusign Envelope ID:C3C6C645-E841-48DC-A23D-A2966087CED8
Cabinet Gorge Station Service
• The 2018 Hydro Generation Condition & Risk Assessments, is referred to as
the "2018 Assessment". Early 2018 GPSS-Hydro department undertook an
initiative to revamp their maintenance programs. This included the 2018
Assessment, which was conducted in the hydro plants and incorporated
both Risk Assessments and Condition Assess mentsTeams consisting of
representatives from the Mechanic, PCM Tech, and Electric Shops, as well
as Spokane River Hydro, Clark Fork River Hydro, and Maximo teams were
formed and tasked with performing a condition and risk based assessment
for assets in all of Avista's hydro facilities. Additional details may be found
in the "2018 Hydro Asset Management Program Directory". The full
reference is provided below:
The Condition Assessments were based on the CEATI hydroAMP 2.0 guide.
The database developed during the 2018 assessment has been used to
create business information tools to identify and analyze equipment
strategies to be used by GPSS for making business decisions.
The purpose of the Risk Assessment was to identify the environmental,
financial, and safety risks associated with each asset and what possible
consequences might result from an asset failure. Consequences were
framed within the Avista Business Risk Matrix. Financial risks might include
lost generation during an outage. Probabilities were then estimated as an
answer to the following question: Given an asset failure, what is the
probability that a particular, potential consequence will actually occur? As
an aid to this process, probabilities were selected from a menu of specified
probability levels. Results of the Risk Assessments have been used to
estimate asset risk costs. Risk cost is the product of the Failure Rate,
Potential Consequence of failure. This risk cost is a probable dollar value
associated with Avista's exposure risk of each asset.
The results of the 2018 Assessment have been used to develop Asset
Management Plans (AMPs) and a Risk Based Investment Planning (RBIP)
tool. AMPs have been developed for a number of the asset classes, such
as the generators, turbine runners, GSUs, trash rakes, etc. The AMPs outline
capital and maintenance strategies. A primary purpose of the RBIP tool is
to bring a risk-based perspective to the capital budget process.
Reference - Avista Utilities, "2018 Hydro Asset Management Program
Directory", Avista Utilities GPSS Dept., March 15, 2019
• 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,
Business Case Justification Narrative Template Version: January 2023 Page 6 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 49 of 271

Docusign Envelope ID:C3C6C645-E841-48DC-A23D-A2966087CED8
Cabinet Gorge Station Service
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 associate 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 NA $0 $0 $0 $0 $0
O&M NA $0 $0 $0 $0 $0
Direct offsets are a reduction in maintenance costs for aging equipment, however, no
cost estimates have been completed for the savings. Operational safety will be
improved by utilizing modern arc-rated equipment.
2.4 Summarize in the table and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: January 2023 Page 7 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 50 of 271

Docusign Envelope ID:C3C6C645-E841-48DC-A23D-A2966087CED8
Cabinet Gorge Station Service
Offsets Offset Description 2024 2025 2026 2027 2028
Capital NA $0 $0 $0 $0 $0
O&M NA $0 $0 $0 $0 $0
The proposed equipment installation will reduce the risk of downtime due to
redundant feeds to the power distribution equipment.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
APPROVED / RECOMMENDED ALTERNATIVE: This request is for budget to
continue/complete the previously approved Station Service project.
Alternative 1: Do Nothing; $0
n/a. The project is in-flight.
2.7 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).
Reduced failures of replaced components including Power Centers, Load
Centers, Power Cables, Transformers, and PLC Control Centers will increase
reliability and demonstrate successful delivery on identified objectives.
2.8 Include a timeline of when this work is scheduled to commence and
complete, if known.
❑x Timeline is Known
• Start Date: Construction started Feb 2023
• End Date: Current scheduled Transfer to Plant is Q3 2025
❑Timeline is Unknown
2.9 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
The Steering Committee consists of the following members: Jacob Reidt, and
Greg Wiggins. Governance Team includes: Chris Clemens and Kristina
Newhouse.
Business Case Justification Narrative Template Version: January 2023 Page 8 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 51 of 271

Docusign Envelope ID:C3C6C645-E841-48DC-A23D-A2966087CED8
Cabinet Gorge Station Service
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
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 52 of 271

Docusign Envelope ID:C3C6C645-E841-48DC-A23D-A2966087CED8
Cabinet Gorge Station Service
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Cabinet Gorge Station
Service 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.
Signed by:
Signature: FjdF "a Date: Sep-17-2024 1 10:50 AM PDT
Print Name: e VU6617498.-
Title: Sr Mgr, Maint and Const
Role: Business Case Owner
Signed by:
v
Signature: aw-� f�bwt,a Date: Sep-17-2024 1 10:52 AM PDT
Print Name: avic��lowell
Title: Director, GPSS
Role: Business Case Sponsor
Signature: NA Date:
Print Name: NA
Title: NA
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: January 2023 Pape 10 of 10
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 53 of 271

Cabinet Gorge Stoplogs
EXECUTIVE SUMMARY
Cabinet Gorge Spillgates are original to the project (early 1950's vintage). The spillgates
are old and in need of replacement. Without a set of reliable stop logs we cannot
accomplish the spillgate work that is expected to take place over the next several years.
Stop logs are used to isolate spillway gates from the reservoir for the Cabinet Gorge
Hydroelectric project. Each stop log assembly comprises nine individual stop log
elements or units, which when combined, will allow dewatering of one spillway gate. Each
stop log unit is predominantly a welded steel structure designed to fit inside stop log
guides embedded inside a large concrete structure, and to minimize water seepage by
means of a rubber seal that is compressed under unit self-weight and hydrostatic forces.
Without these structures, we cannot efficiently and safely perform the upcoming spillgate
work.
Currently Cabinet Gorge spillgates are in need of repair due to missing rivets, bent
members, worn-out seals and heavy corrosion. It is worth mentioning that when the
condition assessment was performed at Cabinet Gorge, the Spillgates ranked poorly. If
those repairs are not made, we pose the risk of a spillgate being out of operational use
or a possible gate failure, which could result in an uncontrolled release of water. This
would not be in the best interest of public safety, plant safety, and would negatively affect
our relationship with FERC, our main governing body and our customers at this facility.
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. Operating
Cabinet Gorge 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).
Cabinet Gorge has operational flexibility and is 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, as well as to maximize value to Avista and its customers. The capacity of this plant
alone is 270 MW.The estimated cost of the project is $1.2 Million. It is critical that this
project is completed prior to the completion of the planned Cabinet Gorge Spill gate
upgrade which is expected to be starting in 2024.
VERSION HISTORY
Version Author Description Date Notes
1.0 Andrew Burgess Updated Draft of original business 7/6/2020 Budget and year change
case.
2.0 Chris Clemens Updated for the 2022-2026 SCRUM 7/6/2021 5-year Capitol Planning
Process
Business Case Justification Narrative Page 1 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 54 of 271

Cabinet Gorge Stoplogs
GENERAL INFORMATION
Requested Spend Amount $1 200 000
Requested Spend Time Period 1 years
Requesting Organization/Department D07/GPSS
Business Case Owner I Sponsor Chris Clemens I 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 Cabinet Gorge spillgates are nearly 70 years old and are in need of repair
due to missing rivets, bent members, worn out seals and heavy corrosion. In
order to do this needed spillgate work a functional set of Stoplogs must be
designed and built prior to spillgate work commencing in 2024. These stoplogs
would also help increase the safety factor of the spillway by giving the ability to
stop water flow should one of the old spillgates fail or get stuck in the open
position. The condition assessment performed in 2018 ranked the spillgates at
Cabinet in "poor condition". A new set of stoplogs are needed to provide stability,
reliability and safety of the aging spillway.
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 stoplogs we have are
no longer functional and require major work to become of use. A new set of
stoplogs will support the spillgate work, which will provide stability and longevity
in the aging spillway into the future. Cabinet Gorge has operational flexibility and
is operated to support energy supply, peaking power, provide continuous and
automatic adjustment of output to match changing loads, and other types of
services necessary to provide a stable electric grid and to maximize value to
Avista and its customers.
Business Case Justification Narrative Page 2 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 55 of 271

Cabinet Gorge Stoplogs
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
Currently, there is not a functional set of stoplogs at Cabinet. Needless to say
we can cannot effectively begin spillgate work in 2024 until a functioning set is
constructed. If we stick with the current plan and construct the stoplogs in 2023
we can perform the much needed work to the spillgates and keep the current
plan in motion. If this is deffered it will prolong the work to the spillway gates and
will put the plant and spillway at risk.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
The stoplogs would be designed in a similar fashion as Noxon's newly built
stoplogs. With the improved design they were able to achieve a better fit to the
slot, a tighter seal to mitigate leakage through the stoplog and a safer and more
effficient way to pick and set the stoplogs into place. Using the design and
construction criteria applied at Noxon for their stoplogs will help ensure that we
end up with a set of stoplogs that function properly and provide a level of safety
for the expected spillgate work and at Cabinet Gorge.
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.
The metric supporting the replacement of the current stoplogs is that they
are no longer functional or useful. The original stoplogs in their current
state are not feasible or safe to use. Estimated cost to refurbuish the
existing set is 700-800k.
Option Capital Cost Start Complete
Replace with new Stoplogs $1,200,000 01 2023 122023
Refurbish existing set (O&M) $700,000 01 2023 122023
Business Case Justification Narrative Page 3 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 56 of 271

Cabinet Gorge Stoplogs
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
A field study was performed on the current set of stoplogs by McMILLEN
JACOBS in 2017. The study showed that the current set of stoplogs is in
"satisfactory" condition. The paint, seals and welds were noted as needing to be
addressed. However, these are the original stoplogs and it may be hard to get
an engineer to sign off on these as ever being deemed safe to use. The study
showed that refurburshement of the existing could be accomplished but the
O&M cost estimated to be 700-800k to refurbuish would be more than half the
cost of a complete new set. The old set have never been placed in service, so
there is some risk involved in refurbuishing. New stoplog design would be
similar to the Noxon set that was built in 2018. Major spillgate work in 2024 will
require a well designed functional set of stoplogs to complete the work safely.
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 of $1,200,000 will be spent in 2023. In first quarter
design/engineering will take place. Second quarter material will purchased and
fabricratrion will begin. Third quarter fabrication complete. Fourth quarter
delivery/commissioning of the stoplogs. If this request moves forward we can
offset O&M costs that would be incurred to refurbuish the existing set. There is
significant risk involved with not procuring a set of stoplogs prior to the spillgate
work scheduled for 2024. The original 1950's vintage spillgates have exceeded
there expected life cycle and are in need of replacement.
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
The timing and execution of this project will enable the needed upgrade of the
Cabinet Gorge Spillgate project to proceed in 2024. The spillgates at Cabinet
Gorge are original to the project and are at the end of their useful life. With
Noxon and Cabinet preparing to officialy enter the EIM in April 2022 it is
expected that we will Operate and cycle the spillgates even more once we enter
the market. Failure of a spillgate would impose significant operational impacts
to the plant , power schedulers, and public by limiting our ability to safey and
efficiently control the flow of water through the dam.
Business Case Justification Narrative Page 4 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 57 of 271

Cabinet Gorge Stoplogs
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The repair of the existing set of stoplogs was considered but due to the high
cost to refurbuish and the outdated design of the old stop logs, this is not the
most reliable and safest option.
The most feasibleand safest option is to design and build a new set of stoplogs
for the anticipated spillgate work in 2024.
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.
In first quarter design/engineering will take place. Second quarter material will
purchased and fabricratrion will begin. Third quarter fabrication complete.
Fourth quarter delivery/commissioning of the stoplogs. Tranfer to plant will occur
at the end of the first year once commissioning is complete.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Cabinet Gorge affordably supports the power needs of our company and our
customers. 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 Cabinet
Gorge is performing at a high level and serving our customers with affordable
and reliable energy.
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 Stoplogs of this size and weight fall into this range of cost. The overall
length and width of the stop logs are similar to the set that was built in 2018 for
the upcoming Noxon spillgate project. We used the dollar figure spent on
Noxon's stoplogs to determine the overall project cost at Cabinet.
Business Case Justification Narrative Page 5 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 58 of 271

Cabinet Gorge Stoplogs
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 identify with the Business
Case.
The primary stakeholders for this project are, the Hydro Regional Manager
at Cabinet Gorge, Cabinet Gorge Plant personnel, GPSS Engineering,
GPSS Construction and Maintenance, Power Supply, Environmental
Resources. 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 the spillgate project
expected to start in 2024. The stoplogs will need to be designed built and
commissioned prior to any major spillgate work at Cabinet Gorge.
3.1 Steering Committee or Advisory Group Information
A formal Project Manager will be assigned to this project. The project will be
managed within project management practices adopted by the Generation
Production and Substation (GPSS) Department. A Steering Committee will be
formed for this project. The Project Manager will manage the project through its
conclusion.
Business Case Justification Narrative Page 6 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 59 of 271

Cabinet Gorge Stoplogs
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 mangers representing the key stakeholders involved in this
project. Thproject 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 intiated, 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 undersigned acknowledge they have reviewed the Cabinet Gorge Stoplogs 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: 7/6/2021
Print Name: Chris Clemens
Title: Cabinet Gorge Ops/Maint Manager
Role: Business Case Owner
Signature: Date: 7/7/2021
Print Name: Andy Vickers
Title: Director GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Page 7 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 60 of 271

Cabinet Gorge Stoplogs
Template Version: 05/28/2020
Business Case Justification Narrative Page 8 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 61 of 271

Clark Fork Settlement Agreement
EXECUTIVE SUMMARY
The ongoing operation of the Clark Fork Project is conditioned by the Clark Fork Settlement
Agreement (CFSA) and the Federal Energy Regulatory Agency (FERC) License No. 2058. The
CFSA and License are the result of a multi-year stakeholder engagement and negotiation
process, which established the terms of the 45-year license issued to Avista. Imbedded in the
License is the requirement to continue to consult agencies, tribes and other stakeholders. In
addition, the CFSA and License provide decision-making participation for the settlement
signatories, resulting in ongoing negotiations on implementing license terms. The CFSA and
License also include a number of funding commitments to help achieve long-term resource goals
in the Clark Fork and related watersheds. Some items are relatively predictable each year; many
others are dynamic, depending on potential projects, natural resource conditions and evolving
resource management goals. Most projects are implemented with collaborating agencies and
Tribes, often with multiple funding sources.
Avista is required to develop an annual implementation plan and report, addressing all Protection,
Mitigation and Enhancement (PM&E) measures of the License. Implementation of these
measures is intended to address ongoing compliance with Montana and Idaho Clean Water Act
requirements, the Endangered Species Act, and state, federal and tribal water quality standards,
among other statutory and regulatory requirements. License articles also describe our operational
requirements for items such as minimum flows, and reservoir levels, as well as dam safety and
public safety requirements, land use, and related matters.
If capital funds were not available for CFSA projects Avista would have to fund them through O&M
dollars, or be in breach of an agreement and in violation of its FERC License. There would be risk
for administrative orders and penalties, new license requirements, increased mitigation costs, and
potential loss of operational flexibility of the Cabinet Gorge and Noxon Rapids Hydro Electric
Facilities. Loss of operational flexibility, or of these generation assets, would create substantial
new costs, which would be detrimental of all our electric customers. Funding of the Clark Fork
License implementation is essential to remain in compliance with the FERC License and CFSA,
which provides Avista the operational flexibility to own and operate the Clark Fork hydroelectric
facilities. Therefore, if these costs were not capitalized, Avista would continue to implement
License articles and all costs would be an operating expense.
VERSION HISTORY
Version Author Description Date
1.0 Monica Ott Initial draft of original business case 10/23/23
2.0 Monica Ott Information moved to new 2025-2029 template 512124
BCRT I Heide Evans Has been reviewed by BCRT and meets necessary requirements 1 915123
Business Case Justification Narrative Template Version: February 2023 Page 1 of 6
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 62 of 271

Clark Fork Settlement Agreement
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2025 $2,663,700 $2,663,700
2026 $3,121,711 $3,121,711
2027 $3,251,462 $3,251,462
2028 $4,013,006 $4,013,006
2029 $3,700,000 $3,700,000
Project Life Span 1 year
Requesting Organization/Department B04/Clark Fork License
Business Case Owner I Sponsor Monica Ott/ Bruce Howard
Sponsor Organization/Department A04 / Environmental Affairs
Phase Execution
Category Mandatory
Driver Mandatory& Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
with the FERC License and the CFSA for permission to continue to own and operate
the hydro-electric facilities. This commitment was made in 2001 and is ongoing. At
that time, Avista determined that the Settlement was in the best interest of Avista, our
customers, our shareholders, and the communities we serve.
1.2 Discuss the major drivers of the business case.
Investment Drivers
The investment driver associated with the CFSA and FERC License fall under
Mandatory and Compliance. Benefit to our customers and the company is the ability to
provide clean, reliable and cost-effective power.
Business Case Justification Narrative Template Version: February 2023 Page 2 of 6
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 63 of 271

Clark Fork Settlement Agreement
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.
If the PM&E activities and license articles are not funded and implemented, we would
be in breach of an agreement and in violation of our FERC License. There would be
high risk for penalties and fines, new license requirements, higher mitigation costs, and
loss of operational flexibility of the Cabinet Gorge and Noxon Rapids Hydro-Electric
(HED) Facilities.
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
Remaining in compliance allows for the continued operation of the Clark Fork and
Noxon HEDs for the benefit of our customers and company. This supports our
commitments to collaboration, environmental stewardship, and trustworthiness — all to
help deliver clean, renewable energy for our customers.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
N/A
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
We are required by the license to develop, in consultation with the Management
Committee, an annual implementation plan and report, addressing all PM&E measures
of the License. In addition, implementation of these measures is intended to address
ongoing compliance with Montana and Idaho Clean Water Act requirements, the
Endangered Species Act (fish passage), and state, federal and tribal water quality
standards as applicable. License articles also describe our operational requirements
for items such as minimum flows, and reservoir levels, as well as dam safety and public
safety requirements.
' Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 6
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 64 of 271

Clark Fork Settlement Agreement
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
Primary consideration occurred during the multi-year negotiations that led to the CFSA
and License, and all decisions were documented throughout the process. If the PM&Es
and license articles are not funded and implemented, Avista would be in breach of an
agreement and in violation of our License. There would be high risk for penalties and
fines, new license requirements, higher mitigation costs, and loss of operational
flexibility of the Cabinet Gorge and Noxon Rapids Hydro Electric Facilities. Loss of
operational flexibility, or of these generation assets,would create substantial new costs,
which would be detrimental to all our electric customers and the company. Funding of
the CFSA is essential to remain in compliance with the FERC license, which provides
Avista the operational flexibility to own and operate the hydro-electric facilities in
Cabinet Gorge, Idaho and Noxon, Montana.
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
There are no quantifiable direct savings calculable, as this Business Case funds
implementation of the CFSA, which is contained in and enforceable under the Clark
Fork FERC License, for Project#2058
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 1 2027 2028 2029
Capital $ $ $ $ $
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 6
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 65 of 271

Clark Fork Settlement Agreement
00 $ $ $ $ $
implementation of the CFSA, which is contained in and enforceable under the Clark
Fork FERC License, for Project#2058
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:
Funding and implementation of the FERC License and CFSA is necessary to operate
the Clark Fork Project. Obligated funding is outlined in the CFSA. The alternative to not
funding the CFSA is to be out of compliance with the FERC License. Penalties would
include fines, new license requirements, higher mitigation costs and potential loss of
operational flexibility.
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 from implementation and funding of the CFSA can be demonstrated through
continued compliance with regulators (FERC, USFWS, others), continued collaboration
with CFSA stakeholders, lack of litigation, and continued operational flexibility for Noxon
Rapids and Cabinet Gorge dams. Individual CFSA projects are monitored and
quantified from a resource perspective to show project success or progress over time
toward meeting the goals of mitigating impacts from the Clark Fork Project.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
This is an ongoing commitment running with the Clark Fork FERC License #2058 and
will continue until the License expires in 2046
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.
FERC and over 20 other parties, including the States of Idaho and Montana, various
federal agencies, five Native American tribes, and numerous Non-Governmental
Organizations. In addition, we coordinate with numerous internal stakeholders, in
particular within GPSS and Power Supply.
Responsible managers include the Clark Fork License Manager, Sr. Director of
Environmental Affairs, and Sr VP Energy Resources & Env Comp Officer, and many
other internal and external stakeholders provide oversite. Externally, we submit
annual work plans and reports to FERC for its review and approval. Many decisions
are subject, per the License, to oversite by the Clark Fork Management Committee,
consisting of settlement parties. And many elements receive oversite from internal
staff in GPSS and Power Supply.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 6
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 66 of 271

Clark Fork Settlement Agreement
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Clark Fork Settlment Agreement and agree
with the approach it presents. Significant changes to this will be coordinated with and approved by
the undersigned or their designated representatives.
Signature: Date:
Print Name: Monica Ott
Title: Clark Fork License Manager
Role: Business Case Owner
Signature: Date:
Print Name: Bruce Howard
Title: Sr Dir Environmental Affirs
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 6 of 6
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 67 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) Combustion Turbine Rotor
Replacement
EXECUTIVE SUMMARY
PROJECT NEED: Coyote Springs 2 is a 280 MW combined cycle power plant located in
Boardman, OR that provides both base load and variable generation as needed by
Avista's Balancing Authority. The facility is owned by Avista and operated and maintained
by Portland General Electric. The combustion turbine rotor is rated for 144,000 operating
hours, which, based on typical annual operations, will occur in 2026. A combustion
turbine rotor replacement will require a facility outage of 6-8 weeks.
There is a Long-Term Service Agreement (LTSA) with General Electric that covers most
components on the combustion turbine and generator. The LTSA does cover replacement
cost of a rotor that fails within its GE specified operational life (144,000 hours for the rotor
currently in service) but not the replacement of the rotor or related parts beyond its rated
end of life.
Insurance on the facility is also tied to the rated end of life. Should Avista operate the
combustion turbine beyond this point, insurance is at risk.
RECOMMENDED SOLUTION: Replace the Combustion Turbine Rotor
ALTERNATIVES CONSIDERED:
• n/a This approved project is in-flight.
ORIGINAL ESTIMATED COST OF RECOMMENDED SOLUTION: $14,600,000
CURRENT ESTIMATED COST AT COMPLETION: $19,274,170
ADDITIONAL INFO: The replacement of the Coyote Springs 2 combustion turbine rotor
at the recommended time will reduce the risk of unplanned failures that would cause a
disruption in the electrical generation that supports the Bulk Electric System and increase
safety around the unit while in service. Increase in project cost estimate since original
approval due to inflationary pressures to material and labor, as well as incurred AFUDC
payments during rotor manufacture.
Business Case Justification Narrative Template Version: January 2023 Page 1 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 68 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) Combustion Turbine Rotor
Replacement
VERSION HISTORY
Version Author Description Date Notes
Draft Mike Mecham Initial draft of original business 7/6/2021
case
Draft Mike Mecham Reviewed 8/19/2022
No substantive
changes/edits have
Draft 1.0 Jessica Bean Transfer to new BCJN Template 01/06/2023 been made to the
business case through
this transfer
Draft 1.1 Mike Mecham Updated spend table 5/10/2023
BCRT Team Has been reviewed by BCRT
BCRT Member and meets necessary
re uirements
BCRT Don Sherrill Updated document for annual 05/01/2024
review/approval.
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2023 $4,170,000 $ 0
2024 $ 500,000 $ 0
2025 $ 500,000 $ 0
2026 $ 14,100,000 $ 19,274,170
2027 $ 0 $ 0
2028 $ 0 $ 0
Project Life Span 4 year
Requesting Organization/Department GPSS
Business Case Owner I Sponsor Mike Mecham David Howell
Sponsor Organization/Department GPSS
Phase Execution
Category Project
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's
site see link. Investment Drivers
Business Case Justification Narrative Template Version: January 2023 Page 2 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 69 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) Combustion Turbine Rotor
Replacement
BUSINESS PROBLEM- This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem
statement.
1.1 What is the current or potential problem that is being addressed?
A turbine is reaching its rated "end of life." Utilizing experience and expertise
with the fleet of their F Class Combustion Turbines, General Electric provides
recommended guidance for periodic maintenance and/or replacement for many
components on GE equipment, including Combustion Turbines. Coyote Springs
2 utilizes a GE 7FA combustion turbine that has a recommended replacement
cycle on the rotor after 144,000 operating hours. With recent annual average
operating hours as guidance, Coyote Springs 2 is anticipated to reach 144,000
operating hours in 2026.
1.2 Discuss the major drivers of the business case
The major driver for this project is Asset Condition. The ability to keep Coyote
Springs 2 in operation helps manage Avista's ability to provide reliable electricity
and the lowest cost possible by giving Avista's System Operations and Power
Supply departments the ability to utilize this asset when needed.
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.
Using recent historical operating needs of Coyote Springs 2, the required rotor
replacement is projected to be in 2026 as per GER-3620P (see section 1.5
below).
A separate consideration is the required maintenance on the remaining gas
turbine parts not included in the rotor replacement. There is XX day/week
maintenance outage that is necessary every 32,000 fired hours. Coyote Springs
2 will reach this next 32,000 hours benchmark in 2025Q4 (when total fired hours
reaches 138,000hrs).
Should the 32,000 required maintenance hours trigger work in 2025, it will be
the most cost-effective practice to replace the rotor at that time although the
rotor hours will be less than its 144,000 hours limit.
Business Case Justification Narrative Template Version: January 2023 Page 3 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 70 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) Combustion Turbine Rotor
Replacement
Avista and GE have a Long Term Service Agreement (LTSA) that covers the
replacement and/or repair of many combustion turbine and generator
components. Within the LTSA, Avista pays GE an amount for each fired hour
on the combustion turbine that is used to cover many major components repair
and replacement on the Turbine/Generator, during the life of the LTSA. Two
items to note: 1.) End of life replacement of the rotor is not covered under the
LTSA conditions, although sudden failure is covered if such failure occurs within
the recommended hours of operating life and 2.) If Avista chooses to defer the
replacement of the rotor past the GE recommended replacement guidelines,
there may be exclusion to the remainder of the covered equipment. For
instance, should Avista choose to defer the rotor replacement past the 144,000
hour GE recommendation, other parts typically covered under the LTSA may
become ineligible if damaged due to a rotor failure or issue.
Moreover, facility insurance is tied to the same manufacturer-rated end of life.
Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. AVISTA STRATEGIC GOALS
The purpose of this project is to fund the replacement of the combustion turbine
rotor at Coyote Springs 2 to ensure Coyote Springs 2 remains available to
support the power needs of our company and our customers. By doing this we
support our mission of serving our customers.
The use of Coyote Springs 2 by Avista Power Supply provides great value
energy for Avista's customers via both Base Load generation and turn-down
ability. This allows Avista's Balancing Authority flexibility to reduce the plant
generation without removing it from service.
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. `66�,
The recommendation for combustion rotor replacement is based solely on
extensive manufacturer expertise on the well-utilized Class F combustion
turbines. This recommendation is supported by LTSA agreement conditions
and Insurance terms which are tied to the rated life of the combustion turbine
rotor. No additional studies, independent analyses, or other evidence/materials
are referenced in this
Using recent historical operating needs of Coyote Springs 2, the rated end of
life is projected to be needed in 2025 as per GER-3620P (see section 1.5
below). Q4 2025 is the year we are projecting to be at the point of replacement
needs due operating hours, which is the replacement guideline provided by GE.
Business Case Justification Narrative Template Version: January 2023 Page 4 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 71 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) Combustion Turbine Rotor
Replacement
Recent historical operating hours on Coyote Springs 2:
2016 — 6,837
2017 — 6,465
2018 — 5,910
2019 — 7,410
2020 — 6,735
Business Case Justification Narrative Template Version: January 2023 Page 5 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 72 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) Combustion Turbine Rotor
Replacement
2. PROPOSAL AND RECOMMENDED SOLUTION- Describe the proposed
solution to the business problem identified above and why this is the best and/or least cost
alternative (e.g., cost benefit analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Recommended Solution: The recommended alternative is to replace the
Turbine Rotor before the operating hours reach 144,000. By doing this, the risk
to LTSA application and Insurance coverage will be mitigated.
In Scope: Complete replacement of the combustion turbine rotor by GE,
including stationery vanes, rotating vanes, and rotor shaft. The out-going rotor
will be returned to GE, which is captured in their new rotor pricing.
Out of Scope: Already covered equipment under the existing LTSA.
Assumptions: Contract not in place; there is an LTSA in place with GE that handles
maintenance items and provides direction. Assume GE equipment. No Avista craft labor
anticipated. Based on the past 5-year estimate of operating hours, it is estimated the in-
service rotor will exceed 144,000 operating hours in 2026. The purchase and installation
of a new rotor is projected to occur in Q2 of 2026. The facility outage is estimated to be
6-8 weeks in duration. Transfer to plant is projected to occur in June 2026.
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).'
• GE published "GER-3620P Heavy-Duty Gas Turbine Operating and
Maintenance Consideration" in January of 2021. This is the most recent
revision that outlines the "Maintenance Consideration" and includes the
replacement of the Combustion Turbine Rotor. Below is some text copied
from GER-3620P that gives some of the GE guidance for rotor replacement:
Rotor Inspection Interval Like hot gas path components, the unit rotor has
a maintenance interval involving removal, disassembly, and inspection.
This interval indicates the serviceable life of the rotor and is generally
considered to be the teardown inspection and repair/replacement interval
for the rotor.
Business Case Justification Narrative Template Version: January 2023 Page 6 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 73 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) Combustion Turbine Rotor
Replacement
Hours-Based Rotor Inspection
Maintenance Interval = R
(Hoursl Maintenance Factor
Factored Hours H+2P11- MF for H+2P+2T,121
MF -
Actual Hours H +P BIE-class H+P
H =Non-peak load operating hours
P = Peak load operating hours
T,= Hours on turning gear
R =Baseline rotor inspection interval
Machine R"'
FA-05&HA Class Refer to unit specific documentation.
F-class 144.000
B &E Class 200,000
11)Maintenance factor equation to be used unless otherwise notified in unit-
specific documentation.
t2)To diminish potential turning gear impact,major inspections must include
a thorough visual and dimensional examination of the hot gas path turbine
rotor dovetails for signs of wearing,galling,fretting,or cracking_If no
distress is found during inspection or after repairs are performed to the
dovetails,time on turning gear may be omitted from the hours-based
maintenance factor.
131 Baseline rotor inspection intervals to be used unless otherwise notified in
unit-specific documentation-
Figure"Rotor maintenance interval.hours-bast-d criterron
• 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)
' 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 7 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 74 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) Combustion Turbine Rotor
Replacement
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 associate with the assets that fail that year.
Annual Risk Cost
= [Probability of Failure (that year)] x [Consequence $]
x [Likelhood of actually experiencing that consequence]
Summarize in the table and describe below the DIRECT offsets2 or
savings (Capital and OW) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital NA $0 $0 $0 $0 $0
O&M NA $0 $0 $0 $0 $0
Estimated direct savings, including hard cost savings, has not been quantified.
Summarize in the table, and describe below the INDIRECT offsets3
(Capital and OW) that result by undertaking this investment.
Offsets Offset 2024 2025 2026 2027 2028
Description
Capital Equipment $0 $0 $18,612,000 18,612,000 18,612,000
purchase in
2024, install
in 2026
O&M j NA j $0 j $0 $0 j $0 j $0
OEM recommendations were considered. Additionally, PGE's unit 1 did have a
rotor failure which resulted in a long outage.
Depending on market conditions, power supply expense associated with such
an outage could exceed 10's of millions of dollars for Avista's customers.
Depending on the type of failure that could occur, personnel safety could also
be at risk.
2 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.
s 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 8 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 75 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) Combustion Turbine Rotor
Replacement
A forced outage caused by a failed Gas Turbine Rotor could extend many
months. The estimated daily Power Supply outage cost for this facility is
$206,800 (refer to 20220825 Thermal Daily Outage Cost Estimation Tool
CONFIDENTIAL.xlsx). Using an estimated 3 months for an emergency
replacement, total Power Supply outage costs due to a failure is estimated to
be: $18,612,000
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
to Avista that may occur if an alternative is selected.
(APPROVED) RECOMMENDED ALTERNATIVE: The recommended
alternative is to replace the Turbine Rotor when the operating hours reach
138,000, which will be in alignment with the next scheduled Major inspection for
other major maintenance on the Combustion Turbine. General Electric provided
budgetary estimates for the below options: (Estimates provided by GE Service
Manager Zach Metcalf on 3/16/2023).
Alternative 1: Exchange Rotor (100,000 hour run time); $9,600,000
The exchange rotor option would be to remove the in-service rotor and replace
it with a rebuilt rotor that would be rated for 100,000 hours of operation. The
rotor that was removed from service would be returned to GE.
This alternative was not selected because of Avista's Integrated Resource
Planning and Power Supply groups recommendation. The purchase of a new
rotor reduces risk further HOW.
Note, all budgetary estimates are escalated 3.5% annually from the provided
budgetary estimate for the next 5 years to allow for inflation.
Alternative 2: Rotor Inspection & Repair; $11,876,000
This option would be to inspect the Coyote Springs 2 in-service rotor and
determine what type of repairs would be needed, then transport to a repair shop
for rebuild. The un-escalated inspection cost is estimated to be $2,000,000 and
the repair estimate is $6,000,000 - $8,000,000 depending on damage. Shop
repair is estimated to be 3 — 5 months. This option is the least favorable due to
the outage time needed for repair. Note, all budgetary estimates are escalated
3.5% annually from the provided budgetary estimate for the next 5 years to allow
for inflation..
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).
Business Case Justification Narrative Template Version: January 2023 Page 9 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 76 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) Combustion Turbine Rotor
Replacement
Success will be measured by the continued safe, reliable and efficient operation
of the 7FA gas turbine at Coyote Springs 2 while being supported by LTSA and
Insurance coverage.
Include a timeline of when this work is scheduled to commence and complete,
if known.
❑x Timeline is Known
• Start Date: 2024
• End Date: 2026
❑Timeline is Unknown
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 and Project Oversight
The Project Delivery Roundtable (PDRT) has determined that the Steering
Committee for this project will consist of Thermal Ops & Maintenance Manager,
Thermal Engineering and the Thermal Ops Manager. These key managers will
meet regularly to make impactful financial, schedule, risk, and other decisions
to provide oversight. The project team will be led by an assigned Project
Manager, who will manage the project directly in accordance with internal
processes and procedures.
Business Case Justification Narrative Template Version: January 2023 Page 10 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 77 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) Combustion Turbine Rotor
Replacement
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the CS2 Combustion Turbine
Rotor Replacement 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.
gned by:
Signature: F�L' k Date: sep-04-2024 1 2:33 PM PDT
3B6 F AB OCB40A...
Print Name: Mike ec am
Title: GPSS Plant O&M Manager, Spokane
Thermal
Role: Business Case Owner
Signed by:
Signature: Fo � R'Wa Date: Sep-06-2024 1 3:17 PM PDT
Print Name: 8AI 5 "8B488.
Davl owell
Title: Director, GPSS
Role: Business Case Sponsor
Signature: NA Date:
Print Name: NA; Committees have not been
stood up at this time.
Title: NA
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: January 2023 Pape 11 of 11
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 78 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) LP Evaporator Replacement
EXCUTIVE SUMMARY
PROJECT NEED: The Coyote Springs 2 Heat Recovery Steam Generator (HRSG) is an
energy recovery heat exchanger that transfers heat from the Gas Turbine exhaust into
water and steam that is used to power a Steam Turbine. One of the last sections toward
the outlet of the HRSG is the Low Pressure (LP) Evaporator, that is used to circulate
relatively cool water through multiple tubes from the top to the bottom of the HRSG, and
transfers heat from the gas stream to the water. During 2019, there was a forced outage
due to Flow Accelerated Corrosion (FAC), which is a type of corrosion that occurs on the
inside of the tubes and is magnified by fluid and thermodynamics and material type.
During a detailed inspection in the Spring of 2021, additional FAC was noticed in other
areas of the LP Evaporator. Modifications were made to the circulating portion of the
Evaporator, but if the FAC is not eliminated, or damage continues, there could be
widespread issues throughout the LP Evaporator that could cause multiple forced
outages.
APPROVED RECOMMENDED SOLUTION: The recommended solution is to replace the
entire LP Evaporator section with new tubes and headers, and with different metallurgy
that will better withstand FAC.
ALTERNATIVES CONSIDERED:
• n/a This is an approved project in-flight.
ORIGINAL COST ESTIMATE OF RECOMMENDED SOLUTION: $4,500,000
CURRENT COST ESTIMATE OF APPROVED SOLUTION: $3,800,000
ADDITIONAL INFO: LP Evaporator is a necessary, critical component of the boiler circuit.
Without the LP Evaporator the plant is unable to generate electricity. Restoring the LP
Evaporator will increase plant reliability. If this project is not funded the plant will continue
to have more frequent forced outages due to LP Evaporator tube leaks.
Business Case Justification Narrative Template Version: January 2023 Page 1 of 18
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 79 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) LP Evaporator Replacement
VERSION HISTORY
Version Author Description Date Notes
Draft Mike Mecham CS2 LP Evaporator Replace 8/19/2022 Draft
No substantive
Draft changes/edits have
1.0 Jessica Bean Transfer to new BCJN Template 01/06/2023 been made to the
business case through
this transfer
Draft Mike Mecham Updated spend and transfer to 5/10/2023
1.1 lant estimates
BCRT BCRT Team Has been reviewed by BCRT
Member and meets necessary
requirements
2.0 Don Sherrill Updated for annual 09/03/2024
review/approval
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2024 $ 0 $ 0
2025 $ 300,000 $ 0
2026 $ 1,500,000 $ 0
2027 $ 2,000,000 $ 3,800,000
Project Life Span 3
Requesting Organization/Department GPSS
Business Case Owner I Sponsor Mike Mecham I David Howell
Sponsor Organization/Department GPSS
Phase Execution
Category Project
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's
site see link.
Investment Drivers
Business Case Justification Narrative Template Version: January 2023 Page 2 of 18
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 80 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) LP Evaporator Replacement
1. BUSINESS PROBLEM- This section must provide the overall business case
information conveying the benefit to the customer, what the project will do and current
problem statement.
1.1 What is the current or potential problem that is being addressed?
The Heat Recovery Steam Generator (HRSG) at Coyote Springs 2 is a multi-
section heat exchanger that transfers energy from the heat in the flue gas (gas
turbine exhaust) to water and steam that is used to power the steam turbine.
The HRSG is essentially a large network of pipes, some contain water, some
contain steam depending on the location of the piping module and the
temperature and pressure of the water or steam. The water or steam is made to
flow through the pipes and the hot gases are made to contact the outside of the
pipe. The pipes are equipped with extended fins in order to increase the
effectiveness of the heat transfer area.
The CS2 HRSG is a three drum/pressure design to allow the most efficient
transfer of energy: High Pressure (HP), Intermediate Pressure (IP) and Low
Pressure (LP). For each of the different pressures there is a section in the HRSG
called an evaporator. The evaporator the liquid water converts to steam, and
their associated drum is where the water level is monitored and controlled.
Coyote Springs 2 Process Flow «.Elwk one Level
Sterlm Turbine HP` iP/LP: —,
NeWrYOet FAN-raGee 9477 MW
--
0
~ Reac
Purrp
156.16 MW
a —
m � N � L..aerekllj,
ComOufUOn m G 6 2 C~'e IdeleuD
Turbine d L f71 W ,
a x y a aJ e
4��t ♦ � �♦ � U�
t 1 --
hrt FDgger r l.l^^�
FI[er C
F1eeh GP'- SJGE :ele
TeM
DernhNWM Cooing
�, Towe
O Aut Meal i Auc OooYg
P.mo Loatle _
0
LP Evaporator with FAC
Business Case Justification Narrative Template Version: January 2023 Page 3 of 18
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 81 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) LP Evaporator Replacement
The LP Evaporator is near the outlet end of the HRSG, and the tube material is
made up of carbon steel. Due to the design of the HRSG Flow-Accelerated
Corrosion (FAC) occurs in the LP evaporator section during operation. FAC is a
corrosion mechanism where a normally protective oxide layer (typical
throughout the internals of HRSG Evaporators and supplemented with water
chemistry) dissolves in fast flowing water. The underlying metal corrodes to
recreate the oxide, and the metal loss continues as water circulates in the LP
Evaporator.
Two tube leaks were discovered after filling the boiler following the 2020
maintenance outage. The header end plate was cut and moved in 14"to bypass
the leaking and most severely damaged tubes. During the 2021 maintenance
outage, inspection ports were drilled into the upper headers to provide
borescope access to look for additional FAC damage. Inspection ports were
also drilled into the baffle plate inside the LP Drum to provide access to the LP
Evaporator risers. FAC damage exists in each of the LP Evaporator upper
sections. The most severely damaged section is the LP Evaporator 2 Western
end where the 2020 tube leaks occurred. The 3 areas showing the worst
damage were selected for Ultrasonic thickness measurement to determine the
minimum wall thickness.
• LP Evaporator 2 West end tube. Minimum UT Thickness: 0.070" (0.105" original)
• LP Evaporator 3 East Header in-board header outlet pipe. Minimum UT
thickness: 0.152" (0.258" Nominal)
• LP Evaporator 2 West Header west header outlet pipe. Minimum UT
thickness:0.207" (0.280" Nominal)
• Two tube leaks were discovered after filling the boiler following the 2020
maintenance outage. The header end plate was cut and moved in 14" to bypass
the leaking and most severely damaged tubes. During the 2021 maintenance
outage, inspection ports were drilled into the upper headers to provide
borescope access to look for additional FAC damage. Inspection ports were
also drilled into the baffle plate inside the LP Drum to provide access to the LP
Evaporator risers. FAC damage exists in each of the LP Evaporator upper
sections. The most severely damaged section is the LP Evaporator 2 Western
end where the 2020 tube leaks occurred. The 3 areas showing the worst
damage were selected for Ultrasonic thickness measurement to determine the
minimum wall thickness.
• LP Evaporator 2 West end tube. Minimum UT Thickness: 0.070" (0.105" original)
• LP Evaporator 3 East Header in-board header outlet pipe. Minimum UT
thickness: 0.152" (0.258" Nominal)
• LP Evaporator 2 West Header west header outlet pipe. Minimum UT
thickness:0.207" (0.280" Nominal)
LP Evaporator 2 —West End
This section has the most FAC damage to the tubes. There were 2 tube leaks
in 2020 that were discovered during startup after outage. The end of the
header was cut and moved in approximately 14" to bypass the 6 tubes that are
in the worst condition.
Business Case Justification Narrative Template Version: January 2023 Page 4 of 18
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 82 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) LP Evaporator Replacement
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IIIIIIIIIIIIIIIIII{IIIIIIIIIIIIIIIIIIIII . ... ..IIIIII
I I , IIIIIIIII{Ilflllllllllllllllllllllll I , {
IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIiIII
I (IIlIIIIIIIIIIIIIIIIIIIIIIIIIIIII
IIIIIIIIIIIIIIIIIIIIIIIIIII {IIIIIIIIIIIIIIIIIIIIIIII
Photo showing section of header and end plane moved bypassing 6 tubes that
are in the worst condition. Two of the tubes were leaking and too thin to repair.
rt
s '
RIr �i
Photos showing what the inside of the 0.070" remaining wall thickness tube
looks like, "divots" in the pipe are caused by unprotected metal being washed
away during FAC
Business Case Justification Narrative Template Version: January 2023 Page 5 of 18
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 83 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) LP Evaporator Replacement
s
r
�f
View looking on the leading edge of the gas side of the LP Evaporator tube
bank. The rust-colored tubes are indicative of water leaking out of the tubes.
i
c
Business Case Justification Narrative Template Version: January 2023 Page 6 of 18
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 84 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) LP Evaporator Replacement
A tube leak in the LP Evaporator has potential to be located when the plant is
offline for maintenance or can be located while the unit is online. If found while
online the unit might need to be taken offline immediately but can sometimes
run for a few weeks until the best economic opportunity allows for the shutdown
to be scheduled. If the unit is left running with a LP Evaporator tube leak the
water blowing from the tube may hit an adjacent tube and has the potential to
cause additional damage to neighbor tubes and create another tube leak. The
random thinning and FAC make it impossible to predict when and where the
next tube leak will occur.
1.2 Discuss the major drivers of the business case
Major driver for this project is Asset Condition. The LP Evaporator is a critical
component of the boiler circuit. Without the LP Evaporator the plant is unable to
generate electricity. Restoring the LP Evaporator will increase plant reliability.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
The plant will continue to experience forced outages due to LP Evaporator tube
leaks. Repairs, outage duration and costs vary depending on location of the leak
and the number of tubes that have been impacted. Repair costs vary with
outages lasting between 96 hours to two weeks. Depending on the time of year
and the current power needs and cost of replacement power, the costs to repair
the tubes and replace power could be extreme.
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 aligns with providing safe and reliable renewable energy for our
customers.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
• See Section 1.1
' 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 7 of 18
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 85 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) LP Evaporator Replacement
• The grid below is used to map out the borescope and photo location of
the LP Evaporator.
B--pe Riser Layout
S
Al B1 f C1 D7 E1 F1
A2 B2 C2 D2 E2 F2 1
E A3 B3 C3 D3 I E3 F3 I W
A4 84 C4 D4 E4 F4 I
AS BS C5 DS ES FS
N
DATE: 5 17 2022
PIPE MATERIAL:A106
NOMINAL MINIMUM
MATERIAL WALL WALL MIDDLE MIDDLE
RISER SIZE THICKNESS THICKNESS` DIRECTION TOP UPPER LOWER LOWER HEADER
Al WEST 0.243 0.235 0.219 0.228 0.692
81 EAST 0.256 0.254 0.227 0.236 0.692
C1 5"SCH 40 0.258 0.063 WEST 0.253 0.245 0.230 0.237 0.719
D3 EAST 0.248 0.244 0.244 0.252 0.746
ES WEST 0.246 0.247 0.255 0.273 0.733
F1 EAST 0.262 0.262 0.263 0.269 0.733
A2 WEST 0.298 0.293 0.274 0.258 0.667
B2 EAST 0.286 0.282 0.275 0.289 0.690
C2 6"SCH 40 0.280 0.065 WEST 0.279 0.280 0.268 0.255 0.676
D2 EAST 0.285 0.295 0.286 0.277 0.728
E2 WEST 0.278 0.278 0.285 0.293 0.756
F2 EAST 0.279 0.275 0.277 0.260 0.691
A3 WEST 0.258 0.236 0.262 0.263 0.743
83 EAST 0.169 0.169 0.180 0.190 0.710
83 NORTH 0.175 0.170 0.1-1u 0.710
C3 5"SCH 40 0.258 0.063 WEST 0.241 0.240 0.203 0.176 0.715
D3 EAST 0.266 0.266 0.266 0.264 0.750
E3 WEST 0.255 0.262 0.257 0.268 0.738
F3 EAST 0.270 0.262 0.265 0.264 0.739
84 EAST 0.250 0.248 0.220 0.220 0.730
C4 WEST 0.260 0.256 0.256 0.256 0.750
D4 5"SCH 40 0.258 0.063 EAST 0.275 0.246 0.249 0.264 0.760
E4 WEST 0.243 0.249 0.243 0.251 0.719
F4 EAST 0.253 0.251 0.254 0.266 0.721
CS WEST 0.242 0.241 0.248 0.229 0.746
DS 4"SCH40 0.237 0.070 EAST 0.219 0.216 0.216 0.228 0.745
ES WEST 0.241 0.240 0.235 0.233 0.731
FS EAST 0.236 0.242 0.248 0.236 0.744
'MINIMUM WALL THICKNESS CALCULATED PER ASME CODE
RED HIGHLIGHTED CELLS INDICATE THICKNESS READINGS BELOW MINIMUM ALLOWABLE WALL LOSS
YELLOW HIGHLIGHTED CELLS INDICATE READINGS WITH MORE THAN S(Y%ALLOWABLE WALL LOSS
GREEN HIGHLIGHTED AREAS INDICATE READINGS WITH LESS THAN SO%ALLOWABLE WALL LOSS
Business Case Justification Narrative Template Version: January 2023 Page 8 of 18
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 86 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) LP Evaporator Replacement
The tables above are used to record key areas of the LP Evaporator.
PGE uses nondestructive testing equipment to accurately measure the
thickness of the tube walls and compare to a new tube. Show in the
chart is the color-coded different levels of concern. The color green is
considered in good condition. Yellow color is concern while red is high
concern. Focus areas of the LP Evaporator are found in riser B3 mostly,
with caution locations sparsely found in other locations measurements
showing different levels of concern.
The table below indicates a Prioritized List of FAC locations as provided
by HRST from engineering analysis and HRSG inspections.
Business Case Justification Narrative Template Version: January 2023 Page 9 of 18
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 87 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) LP Evaporator Replacement
2. PROPOSAL AND RECOMMENDED SOLUTION- Describe the proposed
solution to the business problem identified above and why this is the best and/or least cost
alternative (e.g., cost benefit analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Recommended Solution: Replace the LP Evaporator. CS2 will likely need
additional O&M projects to repair damage in the existing LP Evaporator. Due to
the difficulty in accessing the LP Evaporator (due to the location in the HRSG),
full tube replacement is the recommended solution with a higher corrosion
resistant material to eliminate the threat of FAC.
This project will invest into a base load facility that will increase plant reliability.
The current LP Evaporator will have been in service for 23 years at the time of
replacement. The plant cannot operate without the LP Evaporator and data
shows many of the tubes have reached a point needing to be replaced. Once
replaced NDT testing will continue tracking the new tubes as before to ensure
proper maintenance and planning is documented for future replacement
In Scope: New tubes not made of carbon steel; procure, fabricate and install
Out of Scope: LP Evaporator is one component in the Heat Recovery Steam
Generator; no other components will be modified.
Assumptions: Depending on material supply, procurement process will begin 12
— 24 months prior to the installation of the LP Evaporator, estimated in the year
2027. The LP Evaporator will need to be shipped to Coyote Springs at least a
month prior to installation. A third party contractor will provide installation
expertise of the new LP Evaporator with oversight from both Avista Engineering
and Coyote Springs Management. This project will transfer to plant upon project
completion. Final tube material is TBD, but should be a corrosion resistant alloy.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
• The Non-destructive testing and internal tube borescope inspections as
shown below
HRST Risk Assessment Report dated 3/16/2021
This report discusses in further detail the science of FAC, Risk Factor
calculations used, and results of analysis with areas of concern and
points of focus. The area indicating the most areas of risk are listed
as the LP Evaporator.
Business Case Justification Narrative Template Version: January 2023 Pape 10 of 18
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 88 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) LP Evaporator Replacement
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 Pape 11 of 18
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 89 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) LP Evaporator Replacement
Portland General Electric Non-Destructive examination reports
5/16/2021 and 5/15/2022
Annual Outage NDT and borescope inspection reports beginning in
2021 and repeated in 2022 further detail areas of concern. These
inspection record tube thickness of key areas of the HRSG and
internal photographs reveal areas of FAC and tube metal loss.
Highlighted section of LP Evaporator tube bundles are the section of the
HRSG that are proposed for replacement, and a pictorial location of the LP
Evaporator inspection location.
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Business Case Justification Narrative Template Version: January 2023 Pape 12 of 18
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 90 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) LP Evaporator Replacement
Prioritized List of FAC Risk Factors
Project ID:H2O11137 User ID:SAS
0000,
H RS D Crctnn,er:Coyote Sprinys II Date:03l05/2021
esalption:FAC Risk Assessment
6.59 LP-Evapmatot.3_Bellypao Above Riser Inlet LP Evap Rber discharge to bell n
6.49 LP-Evaporator_5_U4per Header Outlet Piping LP Evap Pipe T 2
6.61 LP_Evaporator 5.Bellypan Above Riser IML4 LP Evap Riser discharge to beeypan
6.55 LP._Evaporator 5_Riser 90 Degree El bow LP Evap 'Long radius 90 deg pipe dbow
6.47 LP-Evaporator-3 Upper Header Outlet Plpinq LP Evap -Ipe T 2
6.58 LP_Evapwator_2 Bellypan Above Riser Inlet LP Evap Riser discharge to beilypan
6.52 LP-Evaporator 3_Riser 90 Degree Elbow LP Evap -ong radius 90 deg pipe elbow
2.62 IPEVI_Rtser Inlet Born Upper(leader IP Evap -lipe T 2
6.15 LP_Evaporator_3_Tubes Adjacent to Lower LP Evap Pipe T 1(pipe discharge to
Header Inlet 'leader/manl/old w/tubes)
2.67 IPEV Riser 1 90 Degree Elbows IP Evap _unq radius 90 deg pipe elbow
2.64 IPEV3 Riser Inlet horn Upper Header IP Evap Pipe T 2
6.16 LP_Evaporator_4.Tubes Adjacent to Lower LP Evap -I pe T 1(pipe disctharge to
Header Inlet Header/nhanirokt w/tubes)
2.80 IPEV Cyclone Separators TP Evap Cyalcne Separator
2.70 IPEV Riser 3 90 Degree Elbows IP Evap -_ong radius 90 deg pipe elbow
6.46 LP-Evapwato, 2_Upper Header Outlet Piping LP Evap -4pe T 2
6.56 LP-Evapmatot 5_Riser 45 Degree Elbow LP Eva _un radius 45 de elbow
6.48 LP_Evapwator 4 Upper Header Outlet Rpinq LP Evap -ipe T 2
6.28 LP_Evapwator_1_Row 1 Discharge Into Upper LP Evap Tube dlsctuisge Into header
Header Near Panel End
6.10 LP_Evaporator 3_Feeder 90 Degree Elbow LP Evap Long radius 90 deg pipe elbow
6.11 LP_Evaporator 4 Feeder 90 Degree Elbow LP Evap Long radius 90 deg pipe elbow
6.51 LP_Evaporator_2 Riser 90 Degree Elbow LP Evap Long radius 90 deg pipe elbow
6.53 LP_Evaporator_4_Riser 90 Degree Elbow LP Evap Long radius 90 deg pipe elbow
2.63 IPEV2 Riser Inlet hom Upper Header IP Evap -Ipe T 2
6.30 LP,_Evapwator 2_Row 1 Discharge Into Upper LP Evap Tube discharge into header I o HS rca-!1
Header Near Panel End
6.17 LP Evapwator 5 Tubes Adjacent to Lower LP Evap of Pe
T 1(pipe discharge to o .-­, .
Header Inlet !leader/rnaMfoid w/tubes:
2.68 IPEV Riser 2 90 Degree Elbows IP Evap -ong radius 90 deg pipe ei1.- v•12
2.71 IPEV Riser 3 45 Degree Elbows IP Every -ong radius 45 deg pipe elbow - 1
6.32 LP_Evaporator 2 Row 2 Discharge Into Upper LP Evap Tube discharge into header
Header Near Panel End
2.65 IPEV4_.Rlset Inlet from Upper Header IP Evap Pepe T 2
2.35 IPEV2_RG1 Upper Tube Bend Near Panel End IP Evap Tube bend adjacent to header
co flon
6.12 LP_Evaporator_5_Feeder%Degree Elbow LP Evap Long radius 90 deg Pipe elbow 7­4 .+.+. .
2.72 IPEV Riser 4 90 Degree Elbows IP Evap Long radius 90 deg pipe etbow 7;a
6.54 LP,Evaporator 4_Rher 45 Degree Elbow LP Evap Long radius 45 deg pipe elbow 7 a
6.13 LP_Evaporator.1_Tubes Adjacent to Lower LP Evap Pipe T 1(pipe discharge to
Header Inlet header/manlrold w/tubes)
2.69 lIPEV Riser 45 Degree Elbows TP Evap lLong radius 45 deg pipe elbow
March 16,2021 Page 1 of 7
TM M anvr.r it r . ..-­ .rr f­nrnir nM HDTr I M rk-r n-.n n.­ - m.
• The requested amount is based on an estimate received from the PGE Plant
Manager and is based on a similar project recently completed at a close by
facility.
• The LP Evaporator has been in service since 2003, with minimal outages
caused by failures until recently. Budget estimates were provided by the
Coyote Springs 2 Plant Manager, and will include upgrading the material
from Carbon Steel tubes to a higher chrome tube to eliminate the damage
caused by FAC
• 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
Business Case Justification Narrative Template Version: January 2023 Pape 13 of 18
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 91 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) LP Evaporator Replacement
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 associate 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 Forced repair of tube leaks $0 $0 $0 $0 $0
The benefits to completion of this project will be increased reliability to the plant.
Some O&M savings will be recognized material and repair services.
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital N/A $0 $0 $0 $0 $0
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: January 2023 Pape 14 of 18
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 92 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) LP Evaporator Replacement
O&M Estimated one forced $0 $0 $0 $0 $20,000
outage repair per year
The estimated daily Power Supply outage cost for this facility is $206,800 (refer
to 20220825 Thermal Daily Outage Cost Estimation Tool CONFIDENTIAL.xlsx).
Time to repair the portion of the LP Evaporator that is the cause of a forced
outage is estimated to be anywhere from 4 to 14 days depending on location
and severity. To date there has only been one forced outage but understanding
the condition of the LP Evaporator from recent inspections indicates more are
likely.
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: Evaporator section with new tubes and
headers, and with different metallurgy that will better withstand FAC.
Alternative 1: Continue to Mitigate; $0 Capital Cost
Mitigation strategies have been in place since the first leak appeared on the LP
Evaporator (since October 2020), and continued inspection and monitoring will
occur until the replacement. As discussed in section 1.1 above, a section of LP
Evaporator header was modified to remove from service the tube section that
was damaged beyond the option of repair. Additionally, Oxygen injection has
been placed in certain areas of the LP Evaporator (as a mitigation effort
suggested by HRST)to encourage passivation of a protective layer on the inside
of the LP Evaporator tubes to attempt to reduce the FAC. This step has the
potential to reduce the effects of FAC, but to determine if this helps or now will
require operation and inspection over the next few years (there is no immediate
indication that can be monitored without NDT testing). CS2 will likely need
additional O&M projects to repair damage in the LP Evaporator. Due to the
difficulty in accessing the LP Evaporator (due to the location in the HRSG), full
tube replacement is the recommended solution with a higher corrosion resistant
material to eliminate the threat of FAC.
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).
Plant reliability will increase, and risk of forced outages will decrease. The LP
Evaporator tube material currently installed is made out of carbon steel, which
is susceptible to FAC due to the metal composition. The upgraded LP
Evaporator tubes material will be made out of a higher corrosion resistant
material (higher amount of chrome), which will drastically reduce the threat of
FAC on the internals of the tubes. Non-destructive testing and internal tube
borescope inspections will be able to monitor tube integrity with data that will
Business Case Justification Narrative Template Version: January 2023 Pape 15 of 18
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 93 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) LP Evaporator Replacement
help predict when the next replacement should take place. The benefits to
completion of this project will be increased reliability to the plant. Some O&M
savings will be recognized material and repair services.
2.7 Include a timeline of when this work IS SCHEDULED TO COMMENCE AND
COMPLETE, IF KNOWN.
❑Timeline is Known
• Start Date: Pending further condition assessment
• End Date: Pending further condition assessment
❑xTimeline 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
Sr Manager Operations and Maintenance
Coyote Springs Plant Management
Thermal Operations Plant Manager
GPSS Thermal Engineer
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 Pape 16 of 18
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 94 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) LP Evaporator Replacement
Business Case Justification Narrative Template Version: January 2023 Pape 17 of 18
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 95 of 271

Docusign Envelope ID:8467516B-2F74-4E55-B860-149924B6214F
Coyote Springs 2 (CS2) LP Evaporator Replacement
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the CS2 LP Evaporator
Replacement 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.
Signed by:
Signature: Date: Sep-04-2024 1 2:33 PM PDT
Print Name: i e Fl�ecKa'M
Title: GPSS O&M Manager, Spokane
Thermal
Role: Business Case Owner
Signed by:
Signature: FVAW',4 f-bwdt Date: sep-06-2024 1 3:v PM PDT
Print Name: avic owell
Title: Director, GPSS
Role: Business Case Sponsor
Signature: NA Date:
Print Name: NA; Committees have not been
stood up at this time.
Title: NA
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: January 2023 Pape 18 of 18
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 96 of 271

Docusign Envelope ID: F1 E99513-4130-4BD6-8E83-0053FDB641 E2
HMI Control Software
EXECUTIVE SUMMARY
PROJECT NEED: The existing Human Machine Interface (HMI) software, Wonderware,
reached its end of life as support ended in 2017. HMI Control Software is used to develop
control screens and to operate and monitor generating systems within Avista
Hydroelectric Developments and Thermal Generating facilities. The existing architecture
is also outdated and requires the existing software to be loaded and run on each individual
computer at each generating facility. Moving to a new HMI platform will allow for
upgrading to a server-based architecture.
RECOMMENDED SOLUTION: The HMI Control Software update is a multi-year effort to
transition the controls software at all GPSS generating facilities from Wonderware to
Ignition. As a part of this updated, supporting software and hardware will also need to be
upgraded as to ensure communication and support across all parts of our controls
system. The timing of this transition is critical due to the expiring support for both
Wonderware and Windows 7 (the current, and only, operating system functional with
Wonderware).
ALTERNATIVES CONSIDERED: The alternatives considered ranged from inaction to
complete product replacement. The selection of complete replacement was made based
upon the risk/reward analysis performed at the onset of the project. The decision to
procure and design an entirely new solution better positions Avista for the future and
mitigates more of the long-term risks associated with sunsetting technologies.
PREVIOUS COST OF RECOMMENDED SOLUTION: $17,800,000
$7M through 2022, $5M planned spend in 2023, $5.8 requested in 2024-2028 CPG cycle.
2024 UPDATE: Cost and schedule updated to reflect current trajectory of project. Current
total cost projection $23,066,029 with project completion in 2027.
ADDITIONAL INFO: This project will benefit customers as the transition is integral to the
continued safe and reliable operation of our generating units. Risk likelihood, exposure,
and severity increase the longer we continue to operate on extended service agreements
and unsupported technology. If we do not stay current with supporting operating systems,
then cyber security risks increase. Additionally, continuing operations on unsupported
equipment puts our facilities at an increased risk of technology failure with much longer
repair durations and continually increasing costs for support.
Business Case Justification Narrative Template Version: January 2023 Page 1 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 97 of 271

Docusign Envelope ID: F1 E99513-4130-4BD6-8E83-0053FDB641 E2
HMI Control Software
VERSION HISTORY
Version Author Description Date Notes
1.0 Kit Parker Original submission 07/17/2017 Signed/approved
1.1 Kara Heatherly Conversion to new format 06/20/2020 Includes budget update
2.0 Kara Heatherly Update for current budget 07/09/2021
ro'ects and new schedule
Kristina Updated to 2022 template and
3.0 Newhouse& to reflect most current 5-year 08/25/2022
Kara Hensley Ian
No substantive
4.0 Jessica Bean Transfer to new BCJN 01/06/2023 changes/edits have been
Template made to the business
case through this transfer
5.0 Don Sherrill Updated/confirmed following 09/03/2024
annual CPG approval.
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT ($) PLANNED TRANSFER TO
PLANT ($)
2018 $ 57,608 (actual) $ 54,541 (actual)
2019 $ 506,653 (actual) $ 2,918 (actual)
2020 $ 588,356 (actual) $ 0 (actual)
2021 $ 1,863,048 (actual) $ 336,041 (actual)
2022 $ 4,154,010 (actual) $ 3,597,119 (actual)
2023 $ 3,896,354 (actual) $ 1,772,317 (actual)
2024 $ 3,000,000 (actual + planned) $ 3,000,000 (actual + planned)
2025 $ 4,000,000 (planned) $ 4,000,000 (planned)
2026 $ 4,000,000 (planned) $ 5,300,000 (planned)
2027 $ 1,000,000 (planned) $ 5,000,000 (planned)
Project Timelines: Ignition Go-Live (Earliest Possible Cutover Start Dates)
Rini,nim(RCT)Ig^iron —Kw(9M1)"did.
Dec 27 ft Aug 22
PST MON Ignition operational Upper Falls(UPF)Ignitian Imle Falls(IF)lgiib- Cabinet Gorge(CAB)Ignition Now'(NOx)Ignition
Sep 2J �Oo 11 �Jull ftFeb 27 Feb 23
PFH Ignirm Operational long lake)DN)Ignition Boulder Park(BIRK)I,— Port falls(Pm) N—a—(NET)Ignition
Sep 27 Mar 18 �NO 6 4 Jul 3 Feb 27
2026
Aug Today Aug 29 Apr Jul 23 Dec Apr 28 Jun 30
TIITlellne Start RCT old din lF did date PFH old date CAB old date 9.1 did daffi Timeline End
Jun 6 Jul 12
UPF old dine BPx old dine
Business Case Justification Narrative Template Version: January 2023 Page 2 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 98 of 271

Docusign Envelope ID: F1 E99513-4130-4BD6-8E83-0053FDB641 E2
HMI Control Software
Site conversion began in 2020 and will continue in accordance with the graphic
above showing the remaining planned cutovers within the 5-year planning
window. These dates reflect anticipated start dates for cutover work. Some
cutover activities may be re-sequenced due to the nature of the required outage,
coordination with Power Supply for minimally impactful outage scheduling, and
in some cases "outage" activities range from 2 weeks (Ignition cutover only) per
PLC to upwards of 6 weeks per PLC (full PLC replacement).
Original Requested Project Life Span 8 years
Requesting Organization/Department GPSS
Business Case Owner I Sponsor Kristina Newhouse David Howell
Sponsor Organization/Department GPSS
Phase Execution
Category Project
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's
site see link.
Investment Drivers
Business Case Justification Narrative Template Version: January 2023 Page 3 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 99 of 271

Docusign Envelope ID: F1E99513-4130-4BD6-8E83-0053FDB641E2
HMI Control Software
1. BUSINESS PROBLEM- This section must provide the overall business case
information conveying the benefit to the customer, what the project will do and current
problem statement.
1.1 What is the current or potential problem that is being addressed?
The existing Human Machine Interface (HMI) software, Wonderware has
reached end of life as support ended in 2017. HMI Control Software is a platform
used to control generating systems within Avista Hydroelectric Developments
and Thermal Generating facilities. The HMI screens allow an operator to run the
station from a computer in a control room rather than directly from the equipment
on the generating floor. New control screens need to be developed using a new
software platform and that new software platform needs to exist on new
technology infrastructure (servers, network, PCs etc.). The major driver for the
HMI Control Software business case is the Asset Condition. This project aligns
with Avista's Safe & Reliable Infrastructure strategy.
The existing architecture is outdated and requires software to be run on each
individual computer. Moving to a new HMI platform will require moving to a
server-based architecture.
1.2 Discuss the major drivers of the business case
Asset Condition: New HMI control software is needed now to prevent limitations
going forward that will introduce security risks. The existing HMI software runs
on Windows 7, which is planned to be unsupported after 2020.
Developing new controls screens on a new software platform will modernize
control screens and allow operators to carry out their responsibilities more
effectively. Control Screen will need to be developed for each generating facility;
therefore, a planned approach will allow engineering and technicians to develop
screens over time to coordinate with control upgrades.
In addition, a new server-based architecture will also create efficiencies for
technicians as they will be able to maintain and update screens remotely.
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.
If we do not stay current with supporting operating systems, then cyber security
risks increase. Additionally, continuing operations on unsupported equipment
puts our facilities at an increased risk of technology failure with much longer
repair durations and continually increasing costs for support.
Business Case Justification Narrative Template Version: January 2023 Page 4 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 100 of 271

Docusign Envelope ID: F1 E99513-4130-4BD6-8E83-0053FDB641 E2
HMI Control Software
Currently, failure of the controls system at our generating facilities would be
nearly immediately catastrophic. Especially at remote facilities where resources
are not physically available to bring systems online and facilities are not staffed
to assume fully manual operations, having a central system "brain" for these
functions is essential to keeping the system online and, if necessary, getting the
system back online quickly. Minimizing the severity of non-preventable failure is
the prudent and responsible thing to do.
Additionally, operating systems that are no longer supported on extended
maintenance agreements is not sustainable, responsible, or cost effective, and
exposes the plants to unnecessary risk.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
Mission: This project safely, responsibility and affordably improves the level of
service we provide to our customers by minimizing direct impacts to services.
This innovative approach allows us to pilot software updates and configurations
before implementing on active sites. This in turn, shortens our outage time and
allows our operations team to reserve capacity for other critical needs
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 an example, the existing HMI software runs on Windows 7, which has been
unsupported since 2020.
' 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 5 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 101 of271

Docusign Envelope ID: F1 E99513-4130-4BD6-8E83-0053FDB641 E2
HMI Control Software
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: The preferred alternative is to purchase new HMI
control software that better meets the need of operators, protection control and
meter (PCM) technicians, and engineers.
The successful implementation of this new control software will improve remote
monitoring and controls at all our facilities, secure and protect Avista's critical
infrastructure, and minimize the impact of future technology upgrades and
versioning on plant operations.
Bringing this system up to date will also ensure continued support from ET
Applications, software licensing and versioning, as well as visibility into potential
network and version conflicts. The Ignition design will also provide our PCM
techs with real-time support from Controls Engineering by providing read-only
access to the plant control screens from the Mission campus.
The alternatives considered ranged from inaction to complete product
replacement. The selection of complete replacement was made based upon the
risk/reward analysis performed at the onset of the project. The decision to
procure and design an entirely new solution better positions Avista for the future
and mitigates more of the long-term risks associated with sunsetting
technologies.
In scope: 12 Generating Facilities are in the scope of this replacement project.
• Monroe Street/Post Street
• Upper Falls/Control Works
• GCC (Generation Control Center)
• Rathdrum
• Boulder Park
• Northeast
• Long Lake
• Little Falls
• Nine Mile
• Post Falls
• Noxon
Business Case Justification Narrative Template Version: January 2023 Page 6 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 102 of 271

Docusign Envelope ID: F1 E99513-4130-4BD6-8E83-0053FDB641 E2
HMI Control Software
• Cabinet
The following scope components apply to all 12 facilities:
• Replacement of Wonderware with Inductive Automation Ignition
product. Such replacement requires: design of new screens, tag
naming/architecture changes across all facilities for standardization,
integration with Pi, upgrades to Windows10 supported equipment,
addition of two servers (one primary and one backup at each generating
facility), addition of two firewalls at each generating facility and central
Generation Control Network facility, addition of redundant plant switches
on the primary Generation Control Network, and transition to new
network architecture/isolated Generation Control Network for added
security and to meet current cyber security compliance requirements.
The following scope components apply to some of the 12 facilities:
• Depending on the age of the controls infrastructure at each of the 12
plants, some PLC's need to be upgraded from Bailey and Modicon (non-
Win10 supported systems) to new Allen Bradley technology. As the
project timeline is continually refined, the Steering Committee is asked
to evaluate the value to the company of pursuing synergies in line with
this project's schedule. In some cases, the decision has been to bring
PLC replacements into the HMI program, and in other cases, due to the
nature, driver, complexity, timing, and planned future of other facilities,
the decision has been to keep the work separate (or reduce the HMI
scope of work to avoid later rework). These decisions are made on a
case-by-case basis and are evaluated at strategic project life cycle
phase gates to avoid rework and waste.
o Examples of PLC replacements in the HMI Program: LL Bailey
Replacement, PF Bailey Replacement
The following scope components are outside of the HMI program scope
at this time, even though in some cases the execution of these projects
is still coordinated with the HMI timeline, again, to avoid rework, and
minimize total generation (availability) impacts. Examples include:
• Any upgrades to the CORP network are excluded from this project
• EOL network hardware (switches) replaced in kind is being replaced
under the coordinated, ET funded, VDR program.
Business Case Justification Narrative Template Version: January 2023 Page 7 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 103 of 271

Docusign Envelope ID: F1 E99513-4130-4BD6-8E83-0053FDB641 E2
HMI Control Software
• Any transport/backhaul enhancements addressing network
infrastructure technical debt/single points of failure are not included in
the scope of this project. In some cases, other projects funding this work
may be coordinated with HMI outages to reduce total impact to
generation.
• Some PLC replacements are excluded from this project
o Examples of PLC replacements outside of the HMI Program:
Noxon Rapids Units 1-5 PLCs (Funding in Automation
Replacement, scheduled to align with HMI), Nine Mile Units 3 and
4 Controls Upgrade (Controls design coordinated to maximize
efficiency and reduce total time in design) OF Unit Upgrade,
Boulder Park Balance of Plant PLC (Funding in Automation
Replacement, scheduled to align with HMI)
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
• The budgetary refinement for this project has been an ongoing joint effort
between GPSS and ET based in constant re-evaluation of actual spend
against forecasts. In a lot of ways, this work is very new to both business
units. The level of complexity involved in building network redundancy,
designing to new security standards, standardizing controls data points and
hierarchies, and designing custom plant screens and layouts that meet the
diverse needs of our plants has proven much more complicated than
originally anticipated.
At project inception, an alternatives analysis was conducted between the
proposed potential product offerings (Cimplicity, Ignition, Wonderware, etc.)
and a cross-functional team of controls experts, operations staff, PCM
technicians and ET operations support staff selected the product that would
be the most scalable to our plants' diverse needs and the most supportable
over time. The costs of the products were relatively equal and the cost of
the effort to bring the plants up to standard (operations on Win10) were
distinct from any vendor technology decision.
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 8 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 104 of 271

Docusign Envelope ID: F1 E99513-4130-4BD6-8E83-0053FDB641 E2
HMI Control Software
The decision to add the interface PLCs at some of the plants was a cost-
saving to defer the need to expedite the timeline to obsolete the Bailey and
Modicon systems - a multi-million dollars savings to the company's capital
proforma. This decision also allows us to continue to operate safely and
reliably on our Bailey and Modicon systems for longer without exposing the
network to undue security risk. Similarly, the decision to replace Unit PLC's
at Noxon, while adding cost to the project, reduced the overall cost to the
company by eliminating rework and replacement cost that would be incurred
by the plant in the near future. The estimate savings on this work is $1 M.
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 Server Hardware (CS) $x $X X X X
Support: Win7 Support
Contract (extended) net
out with Win10 support
contract
Application Ongoing
Support: Inductive
Automation Support
agreement, budget from
App Ops for support, net
with current support (from
PCM)
Network Support Cost(net
out from what it has been,
cost of maintenance,
management, repair,
troubleshooting, what
about risk cost due to
technical debt, single
points of failure, can we
calculate a value?)
It is expected that a server-based architecture will reduce O&M costs as it will
allow for modifications to be made to HMI control screens from one central
location and eliminate the need to drive to each facility when changes are
required. However, the servers will require ongoing support, therefore
increasing O&M costs. Eliminating the extended Windows 7 support contract
will also reduce O&M costs.
s Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: January 2023 Page 9 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 105 of 271

Docusign Envelope ID: F1 E99513-4130-4BD6-8E83-0053FDB641 E2
HMI Control Software
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 N/A $0 $0 $0 $0 $0
O&M Put PCM calc from above $x x x x x
down here for availability
for higher priority/core
competency work.
Potential savings through
centralization of
Generation Control and
changed Local
Control/Dispatch Model —
not likely to be realized in
5-year window.
Security cost reduction
due to security of Win10
as opposed to ongoing
oversight/risk exposure of
the network due to Win7
Indirect offsets are not quantifiable at this time due to the unknown future of
our generation control and operator dispatch model. This HMI enhancement,
however, does afford the Company the functional capability to operate
facilities in a remote state without a full-time local (on-site) control presence.
No additional hires are forecast in current budgets to sustain the current
system design and support operations at this time. Potential efficiencies could
be gained with the ability to redirect PCM (Protection Control Meter Tech) time
and capacity to other core function work. However, the current support work
for Wonderware performed by the PCM Techs will be replaced by a central
support model shared by ET Application Operations and a support contract
with the vendor (Inductive Automation) both with an additional cost to the
Company.
a Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: January 2023 Page 10 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 106 of 271

Docusign Envelope ID: F1 E99513-4130-4BD6-8E83-0053FDB641 E2
HMI Control Software
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: The preferred alternative is to purchase
new HMI control software that better meets the need of operators, protection
control and meter (PCM) technicians, and engineers.
CONSIDERED ALTERNATIVES: The alternatives considered ranged from
inaction to complete product replacement. The selection of complete
replacement was made based upon the risk/reward analysis performed at the
onset of the project. The decision to procure and design an entirely new solution
better positions Avista for the future and mitigates more of the long-term risks
associated with sunsetting technologies.
For instance, an alternative was considered to upgrade existing software
(Wonderware) and develop new control screens (for $1,000,000). however, the
risk was too great: maintaining the Wonderware product still posed a near-term
risk to operations by continuing a relationship with an antiquated and
unsupported product.
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 project execution team (co-led by GPSS and ET PM resources) has
established a draft implementation schedule which addresses the following
high-level deliverables:
• Develop design standards and validate ET implementation plan — Summer
2021
• Complete GCC PLC Lab (Summer 2021) and Monroe Implementation (new
projected ET completion date: Spring 2022) to provide GPSS and ET
opportunities to test screen design and practice conversions in order to
minimize impact to generating facilities and outage durations during site
installation.
Business Case Justification Narrative Template Version: January 2023 Page 11 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 107 of 271

Docusign Envelope ID: F1 E99513-4130-4BD6-8E83-0053FDB641 E2
HMI Control Software
2.7 Include a timeline of when this work is scheduled to commence and
complete, if known.
❑x Timeline is Known — see current schedule graphic in "General Information"
section.
• Start Date: 2018
• End Date: 2026
❑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
The need to address the risk of aging control software and outage control
screens has been vetted through the Generation Production and Substation
Support (GPSS) planning process.
The Controls Engineering Manager, along with the assigned Project Manager,
will provide oversight and monthly tracking of the ongoing work within the
project.
The Joint ET/GPSS Steering Committee will be comprised of the following
members: GPSS Hydro Operations Manager, GPSS Thermal Operations
Manager, GPSS Construction and Maintenance Manager, GPSS Manager of
Project Delivery, ET Manager of Systems Engineering, ET Manager of
Applications Delivery, ET Manager of Network Engineering.
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.
Project decisions will be made at the PM level where appropriate and escalated
to the joint ET/GPSS Steering Committee when and if determined to be
necessary. Regular updates will be provided to the Steering Committee by the
PM team as project scope, schedule and budget are defined, and through the
course of the project execution, change
Business Case Justification Narrative Template Version: January 2023 Page 12 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 108 of 271

Docusign Envelope ID: F1 E99513-4130-4BD6-8E83-0053FDB641 E2
HMI Control Software
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the HMI Control Software
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.
Signed by:
Signature: `� u `f.eo Vh,. Date: Sep-16-2024 1 2:08 PM PDT
Print Name: rWb19'MMhouse
Title: GPSS Engineering Manager, Controls
and Electrical
Role: Business Case Owner
Signed by:
Signature: (�bwt,a Date: Sep-17-2024 I 12:50 PM PDT
Print Name: avl�s oweil
Title: Director, GPSS
Role: Business Case Sponsor
Signature: NA Date:
Print Name: NA
Title: NA
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: January 2023 Page 13 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 109 of 271

Hydro Safety Minor Blanket
EXECUTIVE SUMMARY
Through 18 CFR Section 12.42, the Federal Energy Regulatory Commission (FERC) is given broad
regulatory discretion over the installation, operation and maintenance of hydro public safety devices near
Avista's dams. In addition to regulatory requirements for such devices as lights, sirens, signage and
barriers, Avista is subject to potential liability should the company not maintain safety-related equipment
and associated safety measures. Projects are identified in a variety of ways, including physical
condition/age/function, changing standards in FERC guidance, industry practice, or emergent public safety
needs. All projects are subject to conceptual approval by members of the Dam Safety team and additional
internal Director review and oversight
This work benefits customers by maintaining and enhancing safety, ensuring compliance, and reducing risk.
Customers impacted include all electric customers in Washington and Idaho (service code and jurisdiction
ED/AN). If this business case is not approved, operating costs would increase as Avista would still maintain
safety-regulations to remain in compliance. In the absence of funding,Avista would undertake increased risk
by delaying the activity
VERSION HISTORY
Version Author Description Date
1.0 Carie Mourin Initial draft of original business case 211124
2.0 Carie Mourins Information moved to new 2025-2029 template 511124
BCRT Heide Evans Has been reviewed by BCRT and meets necessary requirements 4129124
Business Case Justification Narrative Template Version: February 2023 Page 1 of 6
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 110 of 271

Hydro Safety Minor Blanket
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2025 $0
2026 $0
2027 $0
2028 $0
2029 $0
Project Life Span 1 year
Requesting Organization/Department H04/ Hydro Safety
Business Case Owner I Sponsor Carie Mourin / Bruce Howard
Sponsor Organization/Department A04 / Environmental Affairs
Phase Execution
Category Program
Driver Mandatory & Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
Avista has an ongoing requirement to maintain existing hydro public safety measures
and to address any emergent hydro public safety needs.
1.2 Discuss the major drivers of the business case.
Investment is driven by compliance with laws,rules, and contractual obligations that are
external to the Company and reduce company risk and liability by improving overall
safety to the public.
Business Case Justification Narrative Template Version: February 2023 Page 2 of 6
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 111 of271

Hydro Safety Minor Blanket
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.
Existing hydro public safety measures are assessed through daily operations, monthly
and annual inspections, etc. As emergent safety issues are identified Avista's Dam
Safety team assesses the need and suggested timeframe for remediation to ensure
public safety and/or compliance with state and federal regulations.
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
Hydro public safety efforts align with Avista's focus on safety within our business,
reliable energy, and overall stewardship.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
N/A
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Significant Hydro Safety issues constituting the need to initiate this business case are
not common and arise on an infrequent basis. By having this business case apporoved
annually it allows the company to have a mechanism in place to fund such safety projects
that arise to meet regulatory commitments.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 6
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 112 of 271

Hydro Safety Minor Blanket
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk 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
18 CFR Section 12.42, the Federal Energy Regulatory Commission (FERC).
eCFR :: 18 CFR Part 12 -- Safety of Water Power Projects and Project Works
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
There are no direct offsets
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
Indirect offsets are difficult to estimate as each identified safety need is unique and
could result in financial impacts in a variety of ways, including but not limited to
regulatory fines, increased requirements, public perception or even lawsuits should
Avista be found to be liable.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 6
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 113 of 271

Hydro Safety Minor Blanket
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:
Once a Hydro Public Safety issue has been vetted by the Dam Safety team and a
proposed solution identified, the Director team will have time to review the proposal.
At that time the solution may be adjusted based on stakeholder input and alternative
solutions suggested;however,leaving the issue unresolved may put the public at a safety
risk and Avista at risk for regulatory scrutiny.
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).
Zero safety incidents occurring at or near our Hydroelectic Facilities is the overarching
target. This, coupled with satisfactory annual FERC safety inspection reports at each
HED is another indicator.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Issues are identified thought daily, monthly, and annual safety inspections. The
timeline for remediation is dependant on the emerging need and postentail risk to the
public and company.
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.
Avista has an ongoing need to maintain existing hydro public safety measures and
to address any emergent hydro public safety needs. The Dam Safety team reviews
these public safety needs to determine a plan and schedule for remediation. The
Dam Safety team meets with the Avista Director team on a monthly basis to review
and discuss Dam Safety issues.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 6
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 114 of 271

Hydro Safety Minor Blanket
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Hydro Safety Minor Blanket 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: CQ_� Date: 05/1/2024
Print Name: Carie Mourin
Title: Manager Hydro Compliance
Role: Business Case Owner
Signature: �2UZO.0_ (,� Date: 5/1/2024
Print Name: Bruce Howard
Title: Sr Dir Environmental Affirs
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 6 of 6
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 115 of 271

Docusign Envelope ID:A30BDBF8-44CA-4EA6-A98D-BAF65D9C7D76
KF 4160 V Station Service
EXECUTIVE SUMMARY
NEEDS ASSESSMENT: All generation facilities require Station Service to provide electric
power to the plant. Station Service components include Motor Control Centers, Load
Centers, Emergency Load Centers, various breakers, transformers and conductors.
Station Service is an elaborate system with multiple built-in redundancies, multiple
voltages designed to protect the plant's electrical system
The plant low voltage 4160 V switch gear has been identified by AIG insurance inspection
as being out of compliance. With aging equipment the plant is experiencing challenges
with service and parts to maintains the breakers. The plant is currently installing new fuel
yard equipment which will require new and upsized power needs in the fuel yard. The
plant fuel yard project team has put in place a temporary work around to power the new
yard, but this solution is not permanent.
The recommendation is to replace the 4160 V station service. This replacement will
correct the insurance deficiency and increase reliability to the plant critical loads. A high-
level cost estimate was received from Columbia Electric and compared to Avista actual
project costs of the from other GPSS locations.
INITIAL ESTIMATED COST: $2,135,000
CURRENT PROJECTED COST: $2,357,000
DOCUMENT SUMMARY:
This project will impact customers in service code Electric Direct jurisdiction Allocated
North serving our electric customers in Washington and Idaho.
RISK: If this project is not funded the plant will have more frequent forced outages due to
electrical equipment failures.
APPROVALS: The recommended solution was reviewed by GPSS Engineering and
Operations and approved by GPSS Management.
Business Case Justification Narrative Template Version: January 2023 Page 1 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 116 of 271

Docusign Envelope ID:A30BDBF8-44CA-4EA6-A98D-BAF65D9C7D76
KF 4160 V Station Service
VERSION HISTORY
Version Author Description Date Notes
Draft GregWiggins Initial draft of original 07/8/2021 Draft
gg business case
Rev. 2 Greg Wiggins Revised schedule, costs and 08/20/2022 Rev. 2
offsets
No substantive
Rev. 3 Jessica Bean Transfer to new BCJN 01/06/2023 changes/edits have been
Template made to the business case
through this transfer
Rev4 Don Sherrill Updated/confirmed following 09/03/2024
annual CPG approval.
GENERAL INFORMATION
Requested Spend Amount $2,357,000
Requested Spend Time Period 3
Requesting Organization/Department GPSS
Business Case Owner Sponsor Greg Wiggins David Howell
Sponsor Organization/Department GPSS
Phase Execution
Category Project
Driver Asset Condition
YEAR PLANNED SPEND PLANNED TRANSFER TO
AMOUNT ($) PLANT ($)
2023 $ 95,000 $ 0
2024 $ 1,540,000 $ 0
2025 $ 722,000 $2,357,000
Business Case Justification Narrative Template Version: January 2023 Page 2 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 117 of 271

Docusign Envelope ID:A30BDBF8-44CA-4EA6-A98D-BAF65D9C7D76
KF 4160 V Station Service
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
In recent years, upgrades and maintenance of the Kettle Falls Station Service
have been performed including 480 V breaker remanufacture, 480 V
transformer replacements, and MCC replacements. The aging 4160 V breakers
were sent to be refurbished through the 2013-2015 timeframe. However, during
the refurbishing processes not all of the old parts were replaced, and parts were
misaligned during reassembly. As a consequence, the plant continues to
replace failing parts. Replacement parts themselves are not readily available
and custom fabricated parts have had a tendency to fail and are expensive. In
order to meet maintenance needs, the plant purchases used breakers to strip
for parts. The pictures below show some examples of damaged parts.
1.2 Discuss the major drivers of the business case (Customer Requested, Customer
Service Quality & Reliability, Mandatory & Compliance, Performance & Capacity, Asset
Condition, or Failed Plant& Operations) and the benefits to the customer
The major drivers for this project are Asset Condition and Mandatory &
Compliance.
The 4160 V gear feeds motors critical to plant operations. Due to the nature of
the supplied loads being motors, the equipment is subject to higher operation
counts than normal breakers, with two breakers having exceeded 1,700
operations. The frequent operations add to wear and increase the risk of failure.
The insurance company for the plant has brought up issues regarding the 4160
V switchgear arrangement as it regards to feeding the Boiler Feed Pumps.
According to Paragraph PG-61.1 of the ASME Boiler and Pressure Vessel
Codes Section I, one such means of feeding the boiler shall not be susceptible
to the same interruption as the other. The concern revolves around the idea that
if one of the Boiler Feed Pumps is interrupted, the second would need to be able
to run and prevent damage to the boiler. Originally, only one Boiler Feed Pump
was electrically driven with the second driven by steam turbine. At some point
Business Case Justification Narrative Template Version: January 2023 Page 3 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 118 of 271

Docusign Envelope ID:A30BDBF8-44CA-4EA6-A98D-BAF65D9C7D76
KF 4160 V Station Service
the steam turbine drive was replaced with an electric motor. To satisfy the
insurance requirements, changes to the 4160 V bus will need to be made in
order to be able to feed the pumps from separate busses. A potential alternative
solution would be to revert the modified boiler feed pump back to being driven
by steam turbine. This solution is being evaluated by the Manager of Thermal
Operations and Maintenance and is not considered further in this plan.
Another significant change at the Kettle Falls plant is the addition of the new
Fuel Handling System/Fuel Yard Processing Building. The planned design has
the power feed for the new system sourced from the local distribution feeder.
This subjects fuel handling operations to disturbances on the distribution
system. To improve the reliability of operations, a feed from the main station
service 4160 V bus to the new fuel yard bus is desired. As the Fuel Yard project
moved into the execution stage there was a cost saving measure to not go with
the new service and to add the feed from the 4160 bus. This is fine but it still
only allows for one source to the Fuel Yard.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The equipment that is energized from 4160 V gear is critical equipment to plant
operations such as the ID fan, FD fan, boiler feed water pumps, circulating water
pumps and the fuel yard hammer hog. The plant cannot run without the ID and
FD fans and there are not redundant fans, so the energy source is just as critical
as the fans themselves. The plant is having trouble sourcing replacement parts
and have recently began purchasing used equipment in decent shape to use as
spare parts
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.
Installing the new gear with a tie breaker and supplying the power from two
separate sources will satisfy the insurance deficiency. The new fuel yard
equipment will need to have this new power supply to be a complete project.
They fuel yard is scheduled to be commissioned in 2023.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
1. 2015 AIG Insurance All Risk Survey Report
2. The 2018 Hydro Generation Condition & Risk Assessments, is referred to as
the "2018 Assessment
Early 2018 GPSS-Hydro department undertook an initiative to revamp their
maintenance programs. This included the 2018 Assessment, which was conducted
in the hydro plants and incorporated both Risk Assessments and Condition
Assessments. The 2018 Hydro Generation Condition & Risk Assessments, is
referred to as the"2018 Assessment'. Teams consisting of representatives from the
Mechanic, PCM Tech, and Electric Shops, as well as Spokane River Hydro, Clark
Fork River Hydro, and Maximo teams were formed and tasked with performing a
Business Case Justification Narrative Template Version: January 2023 Page 4 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 119 of 271

Docusign Envelope ID:A30BDBF8-44CA-4EA6-A98D-BAF65D9C7D76
KF 4160 V Station Service
condition and risk based assessment for assets in all of Avista's hydro facilities.
Additional details may be found in the "2018 Hydro Asset Management Program
Directory". The full reference is provided below:
The Condition Assessments were based on the CEATI hydroAMP 2.0 guide. The
database developed during the 2018 assessment has been used to create business
information tools to identify and analyze equipment strategies to be used by GPSS
for making business decisions.
The purpose of the Risk Assessment was to identify the environmental, financial,
and safety risks associated with each asset and what possible consequences might
result from an asset failure. Consequences were framed within the Avista Business
Risk Matrix. Financial risks might include lost generation during an outage.
Probabilities were then estimated as an answer to the following question: Given an
asset failure, what is the probability that a particular, potential consequence will
actually occur? As an aid to this process, probabilities were selected from a menu
of specified probability levels. Results of the Risk Assessments have been used to
estimate asset risk costs. Risk cost is the product of the Failure Rate, Potential
Consequence of failure. This risk cost is a probable dollar value associated with
Avista's exposure risk of each asset.
The results of the 2018 Assessment have been used to develop Asset Management
Plans (AMPs)and a Risk Based Investment Planning (RBIP)tool. AMPs have been
developed for a number of the asset classes, such as the generators, turbine
runners, GSUs, trash rakes, etc. The AMPs outline capital and maintenance
strategies. A primary purpose of the RBIP tool is to bring a risk-based perspective
to the capital budget process.
Reference - Avista Utilities, "2018 Hydro Asset Management Program Directory",
Avista Utilities GPSS Dept., March 15, 2019
1.5.2 For asset replacement, include graphical or narrative representation of metrics
associated with the current condition of the asset that is proposed for
replacement.
Breaker 2A1 2A2 2A3 2A4 2A5 2A6 2A7 2A8 2A9
Position
Operation 629 887 630 1829 287 204 736 16 1744
Count
Average of 774 operations. Plant technicians did mention that some of the
operation counters were broken for an unknown period of time and later
fixed, so the counts shown are lower than the actuals
Business Case Justification Narrative Template Version: January 2023 Page 5 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 120 of 271

Docusign Envelope ID:A30BDBF8-44CA-4EA6-A98D-BAF65D9C7D76
KF 4160 V Station Service
2. PROPOSAL AND RECOMMENDED SOLUTION
The recommended solution is to replace the existing switchgear with a new Main-Tie-
Main configuration. Replacing the switchgear directly addresses the concerns
regarding the state of wear of the existing breakers. The new gear would also have a
breaker that can be used as a feed to the new fuel yard. This configuration would also
directly address the insurance company's concerns about being able to feed the two
boiler feed pumps from separate busses. All concerns are addressed with this
alternative. An example of the arrangement is shown below.
i
I
i
i
M I
BOILER CIRC WTR FORCED NEW CIRC WTR INDUCED BOILER
FEED Pump DRAFT FUEL PUMP DRAFT FEED
PUMP 2 FAN YARD FAN PUMP 1
Option Capital Cost Start Complete
[Recommended Solution] Replace the 4160 V $2,135,000 05/2023 06/2025
Station Service with Tie
Replace the 4160 V Station Service $2,013,000 05/2023 06/2025
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.
The plant will need to continue purchasing old breakers to salvage for parts or
have custom parts manufactured, maintaining a non-inconsequential O&M
burden. This alternative also does not address the insurance company's
concern regarding the Boiler Feed Pumps or provide a reliable power source to
the new fuel yard
2.2 Discuss how the requested recommended solution 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 or increases to O&M, Depreciation, Amortization or other
related Capital projects as a result of this investment.
Business Case Justification Narrative Template Version: January 2023 Page 6 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-13-25-01
D. Howell,Avista
Schedule 1,Page 121 of271

Docusign Envelope ID:A30BDBF8-44CA-4EA6-A98D-BAF65D9C7D76
KF 4160 V Station Service
Engineering will begin in 2023 followed by procurement in 2024 with the installation
being done during the 2025 annual Spring outage.
A forced outage caused by a failure on the 4160v bus could extend many
months. The estimated daily Power Supply outage cost for this facility is $69,700
(refer to 20220825 Thermal Daily Outage Cost Estimation Tool CONFIDENTIAL.xlsx).
Using an estimated 1 month for an emergency replacement, total Power Supply
outage costs due to a failure is estimated to be: $2,091,000
INCREASES TO BUDGET AND/OR BUDGET
OFFSETS
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 work will be done during the 2025 annual Spring outage. There will be a short
impact and outage to fuel deliveries that will be managed through weekend work
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The recommended alternative is to replace the 4160 V Station Service with Tie.
Alternative 1:
Replace the 4160 V Station Service; The alternatives discussed around
additional costs to mitigate the insurance deficiency and the added costs were
evaluated from Risk Management and a decision was made to install the tie
breaker.
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.
[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).]
Business Case Justification Narrative Template Version: January 2023 Page 7 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 122 of 271

Docusign Envelope ID:A30BDBF8-44CA-4EA6-A98D-BAF65D9C7D76
KF 4160 V Station Service
Year 2023 1 2024 1 2025
Month Aug Sep Oct Nov Dec lian Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Intiation
Planning
Execution
Closing .6 Discuss how the proposed investment aligns with straLU91Uvy5TuTF-, als,
objectives and mission statement of the organization.
This project aligns with supporting a safe and reliable operating unit.
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
An evaluation was completed by GPSS Electrical engineering and Risk
Management. Both groups supported the project as plant reliability and
insurance deficiency will be resolved with the project.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
KF Plant Management
KF Plant Techs
GPSS Electrical Shop Crews
GPSS Electrical Engineering
Risk Management
2.8.2 Identify any related Business Cases
Kettle Falls Fuel Yard Replacement Project
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
GPSS Asset Management
KF Plant Management
GPSS Thermal Operations and Maintenance Manager
Business Case Justification Narrative Template Version: January 2023 Page 8 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 123 of 271

Docusign Envelope ID:A30BDBF8-44CA-4EA6-A98D-BAF65D9C7D76
KF 4160 V Station Service
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 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. There will
also be quarterly status meeting up to construction then weekly meetings.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
Plant management will report changes requests to the GPSS Thermal
Operations and Maintenance manage. Decisions, periodization efforts, and
change requests will be tracked by the Project Manager or the GPSS Thermal
Operations and Maintenance Manager for the project for the duration of project
activities.
Business Case Justification Narrative Template Version: January 2023 Page 9 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 124 of 271

Docusign Envelope ID:A30BDBF8-44CA-4EA6-A98D-BAF65D9C7D76
KF 4160 V Station Service
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the KF 4160 V Station Service
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.
Signed by:
Signature: F (P( -t,S Date: sep-20-2024 1 8:40 AM PDT
Print Name: reg eg iggigglns
Title: GPSS Manager of O&M
Role: Business Case Owner
ed by:
Signature: FT" 4JIV Date: sep-22-2024 6:47 AM PDT
Print Name: 8A3FG6 0 , gaga
Davl owell
Title: Director, GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role:
Business Case Justification Narrative Template Version: January 2023 Page 10 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 125 of 271

Docusign Envelope ID: F1 98D9F8-21 D1-492C-AD9B-50FDB8761 CA3
KF Secondary Superheater
EXECUTIVE SUMMARY
NEEDS ASSESSMENT: The Kettle Falls Generating Station processes nearly 450,000
tons of waste wood annually. During the combustion process the heat generated is
transferred to the boiler internal water and steam systems. Water is heated until it
becomes steam. The steam is conditioned in the drum before entering two sections of
superheater steam pendants. The first section is the primary superheater which takes
high pressure saturated steam from the steam drum and converts it into dry superheated
steam. The secondary superheater conditions the steam to maintain final steaming
conditions at 950 F at 1,550 psi to be used in the steam turbine. The turbine converts the
steam into 53 MW's of green renewable energy.
After a 1997 inspection revealed excessive corrosion caused severe tube wall thinning,
both sections of the superheater were replaced in 1998. The replacement superheater
tube material was upgraded from original design with engineering studies showing
potential of a 20-year life expectancy from the upgrade. Recent testing from Industrial
Inspection and Analysis revealed the secondary superheater has undergone localized
wall thinning from erosion. The analysis indicates the superheater tubes have
experienced significant non-uniform scaling and tube wall loss on the exterior surfaces
up to 54% of the wall thickness.
The recommendation is to replace the secondary superheater. This replacement will
restore plant reliability for Avista's customers.
INITIAL COST ESTIMATE: $2,800,000
CURRENT PROJECTED COST ESTIMATE: $3,390,000
DOCUMENT SUMMARY: This project will impact customers in service code Electric
Direct jurisdiction Allocated North serving our electric customers in Washington and
Idaho.
RISK: If this project is not funded the plant will continue to have more frequent forced
outages due to secondary superheater tube leaks.
APPROVALS: The recommended solution was reviewed by GPSS Operations and
approved by GPSS Management.
Business Case Justification Narrative Template Version: January 2023 Page 1 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 126 of 271

Docusign Envelope ID: F1 98D9F8-21 D1-492C-AD9B-50FDB8761 CA3
KF Secondary Superheater
VERSION HISTORY
Version Author Description Date Notes
Draft Greg Wiggins KF_Secondary 6/22/2021
Su erheater Replace
Rev. 1 Greg Wiggins Revised schedule, costs, and 8/20/2022 Revised schedule and
offsets cost
No substantive
changes/edits have been
Rev. 2 Jessica Bean Transfer to new BCJN Template 01/06/2023 made to the business
case through this
transfer
Rev3 Don Sherrill Update for Annual 05/06/24
review/approval
GENERAL INFORMATION
Original Requested Spend Amount $2,800,000
Current Requested Spend Ammount $3,390,000
Requested Spend Time Period 2 years
Requesting Organization/Department K07/GPSS
Business Case Owner Sponsor Greg Wiggins I David Howell
Sponsor Organization/Department K07/GPSS
Phase Execution
Category Project
Driver Asset Condition
YEAR PLANNED SPEND AMOUNT ($) PLANNED TRANSFER TO PLANT
2024 $ 750,000 $ 0
2025 $ 2,640,000 $ 3,390,000
Business Case Justification Narrative Template Version: January 2023 Page 2 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 127 of 271

Docusign Envelope ID: F1 98D9F8-21 D1-492C-AD9B-50FDB8761 CA3
KF Secondary Superheater
1. BUSINESS PROBLEM
The Kettle Falls Generating Station thermal
plant is a wood fired natural circulation boiler.
The wood is burned on a traveling grate system -
and the heat from the fire is transferred into the
boiler water walls, superheater, generation
section, economizer and air heater. The °I!l
process begins with pumping water through a
series of heat exchangers to add energy to the 1
boiler water. '
The boiler water is heated to steam at 415,000
Ibs/hr of steam flow. The saturated wet steam Secondary
passes through two sections of superheater Saperheate ---=----
tube bundles. The first section is the primary --- -- - °
superheater followed by the secondary
superheater. Steam exits the secondary
superheater at 950 F superheated steam at --
1,550 psi operating pressure to drive the steam =
turbine generator. The steam is then
condensed back into water and is pumped back
through the heating system again.
During the combustion process fly ash is 0
carried in the flue gas stream up the furnace
and through the superheater, generation bank
and economizer. The fly ash is corrosive and abrasive by nature. Over the past 23 years
the fly ash has caused random thinning to the outside of secondary superheater tube
walls.
Business Case Justification Narrative Template Version: January 2023 Page 3 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 128 of 271

Docusign Envelope ID: F198D9F8-21D1-492C-AD913-50FD138761CA3
KF Secondary Superheater
1.1 What is the current or potential problem that is being addressed?
The secondary superheater is reaching the minimum tube wall thickness for safe
and reliable operations of the plant. The thin areas cause tube failure as the
high-pressure steam inside the tube bursts the thin tube wall. The plant must
be taken offline to make the repairs. Depending on the severity of the leak the
unit might need to be taken offline immediately but can sometimes run for a few
weeks until the best economic opportunity allows for the shutdown to be
scheduled. If the unit is left running with a superheater tube leak the steam
blowing from the tube may hit an adjacent tube steam cut through the metal and
create another tube leak. The random thinning and scale make it impossible to
predict when and where the next tube leak will occur.
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 driver for this project is Asset Condition. The superheater is a critical
component of the boiler circuit. Without the superheater the plant is unable to
generate electricity. Restoring the superheater will increase plant reliability.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The plant will continue to experience forced outages due to superheater tube
leaks. Repairs, outage duration and costs vary depending on location of the
leak and the number of tubes that have been impacted. Repair costs vary from
$30k to $125k with outages lasting between 48 hours to a full week.
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.
Business Case Justification Narrative Template Version: January 2023 Page 4 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 129 of 271

Docusign Envelope ID: F1 98D9F8-21 D1-492C-AD9B-50FDB8761 CA3
KF Secondary Superheater
Plant reliability will increase as the unit has been averaging a couple tubes leaks
a year since 2012. Non-destructive testing will be able to monitor tube integrity
with new baseline data which will help predict the when the next replacement
should take place. Previous study from JP Industrial in 1997 expected a 20-
year operating cycle on the previous superheater replacement which was
reached in 2018.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
JP Industrial — Superheater engineering study— Kettle Falls Plant Library
This engineering study was completed in 1997. It included tube analysis
completed by an independent firm McDermott Technology. The study
focused on the superheater tube failures and root causes. The JP
Industrial report suggested a replacement superheater could expect to
have a 20-year operating lifespan under similar operating conditions.
5 Star Non-Destructive Testing Reports — Kettle Falls Outage Files
Annual Outage NDT inspection reports beginning in 1990 continuing
every other year to current year. These inspection record tube thickness
of key areas of the boiler.
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.
SUPERHEATER TUBES
Tubes numbered left to right facing the rear.
GENERATING BANK
A-I Web—spacer I ube IX 03
AEI S I.K#1 S Q #5
u R� P O
B-5'above spacer tube P \ E
E E G R
B—► R H
H
E E I.K#4 #6
A A
T T
E
R I.K#2 R K
C—�
F H jG,H,J,K-Position SA 209T1 A-1.75"OD X 0.149"MWT
.149"8 above-Blue
I
110
100'thru 121'-Plnk
D
099"8 Below-Red
Business Case Justification Narrative Template Version: January 2023 Page 5 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 130 of 271

Docusign Envelope ID: F198D9F8-21D1-492C-AD913-50FD138761CA3
KF Secondary Superheater
The boiler graph above is used during the annual outage to measure key
areas of the boiler. Areas include the water walls, chill tubes, primary and
secondary superheaters, generation bank and economizer tube. A
contractor uses non-destructive testing equipment to accurately measure
the thickness of the tube walls and compare to a new tube. Show in the
chart is the color-coded measurements showing different levels of
concern. Colors blue and green are considered in good condition. Pink
color is concern while Red is must repair. Focus areas of the secondary
superheater are found in the G, H, I, and J. Each tube is measured
roughly in the same spot every two years. Pink areas are indicating issues
while Red indications require repairs to maintain the boiler operating
license from the State.
5 Star Testing is a contractor that has been recording the tube data for the
plant for over 20 years to maintain accurate and consistent inspection
practices and test results. During plant outages, scaffolding is installed to
gain access to key areas of the boiler so these reading can be recorded.
Sometimes scaffolding is not built due to outage duration, so those areas
are recorded as NO ACCESS. Below is the data take over a six-year
interval. In 2014 there were no areas of concern recorded in the
secondary superheater section. In 2016 scaffolding was not installed to
gain access to area I. The 2016 outage revealed several tubes reaching
a measurement of concern. Tube shields were installed to prolong the life
of the tubes recorded in pink. Those tubes are no longer measured, and
some thermal conductivity efficiency is reduced to extend the life of the
tube. In 2018 section in I were also recorded as a warning area.
Business Case Justification Narrative Template Version: January 2023 Page 6 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 131 of 271

Docusign Envelope ID: F1 98D9F8-21 D1-492C-AD9B-50FDB8761 CA3
KF Secondary Superheater
2014 2016 2018
K
0232 016q 0167 N 0154 0.231 1 0151 0155
0.220 0 ' o 0.217 Snead
0 214 U U 162 0.t 58 0 154 0.215 Shad Sh-W
0 174 UA(58 A 0I.aa 01611 0205 OA65 Shaw
C 1 S)taw
U_'_ 0-157 U 165 C 0161 160 OASO Shiew
016, a 1 9hrw
0.164 U 162 S 0.157 >lhiew
0 168 U INS- 0168 01 1 01 1
0.165 0.159 0.163
0220 0.162 U 151 0.157 0.152
0 7" 0 170 0.Il" 0 161t 0 162 1 1 Shrw
0114 0 166 0 164 0.159 0.166 fA e1d
t 1 ghad
0 21)4 0 154 0 165 0.156 171 0.150 Shleld
0 162 0.149 1•7 i S11aw
0159 0 1.110 0.156 �
0 161 0 164 0.165 0 tfib 0.156 Shaw
0161) 0153 0.158 0-160 0165 0./62
0;1a 0166 n161 0,159 0150 '67 0.164 0.156
0163 0.150 0140 0163
0 164 0.157 1 Shaw Shod
0 168 n•flEi 0.1W 0 157
0166 0.162 0149 C 0163 0162
0163 0155 0,149 6-1 0ISO 0157
0 121 O.153 Shoal 0.1 7
0 162 0 162 0.151
0 163 0 1 1 O 156 0 1
0.163 OA56 OA62 , 0160 0156
0170 0.155 0.160 Shad 0 1
0166 0166 0.153 0158 0157
0 166 0.161 0 160
0.150 0 150 0.157
0.164 0.161 Yt Shedd
0 164 U 'to t 1.1 show
0 152 0,162 "b 0.164
0 167 0.163 0.155 0-159 0163 51..*4
0.151 0 140 0.165 0.159
u Itxu 0 ,,1, 0163
0 205 0 169 0 152 0.IM 0.1 0.162
0 1" 0.161 0 160 0.160 Shaw
0 I" 0.1511 OA 54 0.162 0.163
0 199 ':l shield Shoed
0166 0,155 159 0.162
0 T.:•' 0 167 0.164 Shedd
n. 1.1 167 0.166
U 162
snow sl,.dd
U I so 0 161 1 N Shaw Shaw
0166 0161 O 0.1 0 8h.ew
U 168 0 1" 0.161 0.164 gt� Spy
0 2"Cl 0 14a 0150 A shad 811aw
n +7G 0 174 0.166 C Shedd 811eelt]
0 '' 0 164 t n Shaw 91�e0
0 167 0 149 0.1 0 1 1
0172 0166 E 0.150 Sherd
0.161 0.163 1 &+.Md
0 225 1 0,66 0 156 )1 1 1 1
0171 0.160 8 015 Sttield
0 154 0 156 151 0 1
NOTE: No data was collected in 2020 or 2021 due to COVID
Business Case Justification Narrative Template Version: January 2023 Page 7 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 132 of 271

Docusign Envelope ID: F198D9F8-21D1-492C-AD913-50FD138761CA3
KF Secondary Superheater
2. PROPOSAL AND RECOMMENDED SOLUTION
The recommendation is to replace the secondary superheater section. During
the 1998 superheater tube replacement project both sections were replaced. A
decision was made to upgrade the material and tube thickness on both sections
of superheater. The primary superheater was upgraded from a 209 T1 material
with a minimum wall thickness of 0.149" to a 213 T11 material with a minimum
wall thickness of 0.198 wall thickness. These upgrades to have extended the
primary superheater life span based on NDT results and analysis. Currently
there are no indications showing in the Pink. Although there would be some
savings in mobilization and common work and equipment needed to replace
secondary superheater it is unknow how long the primary superheater will
continue to operate without any impact to reliability. The last NDT inspection on
the primary superheater showed some slight thinning on the tube bends only
shown in D area.
2018 Primary Superheater
7wer A a c o SUPERHEATER TUBES
t 0 206 0" 0229
2 0221 0.217 0203 •,
3 0214 0.216 0.206
4 0216 0.217 0.203 tot
5 0219 0.217 0.219 179
6 0.211 0216 0216 1 to1
7 0.211 0212 0206 7191 QVItAW yM
6 0.211 0 212 0.219 182
9 0.225 0217 0.202 If]
10 0.2114 0.210 0204. 177 A.1rrr.�.r.w UI.1
11 0.213 0 213 0.207 ?182
12 0.216 0.216 0.2081 AEI {KM 1
13 0.213 0.212 -0-Ti_3 ]1 Y • •
14 0211 0213 0216 :175 6.14w t�rrle / e
15 0 210 0200. 0 223 173 0. 0 t "
16 0.211 0.213 0. 0 6
17 021A 0.217 0.223 i]175 � ~
E + •
16 0200 0212 0.20 '!19 1
7 1 Q
to 0.214 0.209 0.211 ills E ,KQ "
20 0.2t4 0.206 0.217 E '
21 0215 0.213 0.225
22 0.213 0.216 0.
23 0.215 0.215 0.213 "
74 0.173 0221 0.210 - O.H.1"-Wru1A2t11A-176'00Ic0,4Pwrt
25 0204 0.216 0.218
26 0220 0.223 0.214 .,.
2 7 0.219 0207. 0206
26 D 220 0 210 0201 0.196
Option Capital Cost
[Recommended Solution]Replace the Secondary $2,800,000
Superheater
Replace Primary and Secondary Superheater $4,000,000
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The first superheater was replaced after 16 years of service. The material of
the tubes was changed from original design. The 1998 JP Industrial project
report suggested the upgraded materials would possibly provide 20 years of
service. The plant performs non-destructive testing to monitor the superheater
Business Case Justification Narrative Template Version: January 2023 Page 8 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 133 of 271

Docusign Envelope ID: F1 98D9F8-21 D1-492C-AD9B-50FDB8761 CA3
KF Secondary Superheater
tube thickness. These readings are
performed every two years and small repairs
and preventive measures have been taken
such as tube shielding to ensure maximum
service is reached from the tubes. Below is
a photo of an area that was replace and
shielded. These repairs are scheduled and
managed during the annual outage to
minimize plant down time. Through
consistent non-destructive testing a long
data set has been collected on the entire unit
and the secondary superheater is showing '
significant tube thinning. Nearly 80% of the
tube leaks in the past 15 years have been
located within the secondary superheater.
About 60% of those leaks have caused '
forced down time on the unit while the other
40% were discovered during scheduled outages. The secondary superheater
has operated longer than expected and has thinning throughout the entire
pendant. Data shows ongoing maintenance of sections will no longer be a
viable option as much of the pendant has reached the Pink measurement.
2.2 Discuss how the requested recommended solution 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 or increases to O&M, Depreciation, Amortization or other
related Capital projects as a result of this investment.
The secondary superheater replacement project will consist of a multi-year
project with the first year being the procurement of the superheater tubes. Year
two will be the installation of the superheater as part of the annual Spring
outage. The benefits to completion of this project will be increased reliability to
the plant.
INCREASES TO BUDGET AND/OR BUDGET
OFFSETS
Business Case Justification Narrative Template Version: January 2023 Page 9 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 134 of 271

Docusign Envelope ID: F198D9F8-21D1-492C-AD9B-50FDB8761CA3
KF Secondary Superheater
Some O&M savings will be recognized in scaffolding costs, material and repair
services.
A forced outage caused by a failed superheater tubes could extend many
weeks. The estimated daily Power Supply outage cost for this facility is $69,700
(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.
This project will be managed within the normal Spring annual outage and will
not have any additional impacts to Power Supply
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
The recommended alternative is to replace the secondary superheater section.
Mitigation strategies have been in place for the past 5 years and will continue
with smaller O&M projects and repairs. The NDT data is suggesting full tube
replacement is now needed instead of isolated small sections of tube
replacement or shielding. Due to COVID contractor restrictions no data was
collected in 2020 or 2021. With historical data it the plant can expect to see
more tubes in all three sections of the secondary superheater to reach the Pink
status and most likely some Red tube repairs will need to be made before this
project is completed.
Alternative 1:
The entire superheater section could be replaced; this would not be as cost
effective as replacing the secondary superheater section only.
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.
Business Case Justification Narrative Template Version: January 2023 Pape 10 of 13
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 135 of 271

Docusign Envelope ID: F198D9F8-21D1-492C-AD913-50FD138761CA3
KF Secondary Superheater
Depending on material supply, procurement process will begin 6 — 12 months prior to the
installation of the superheater tubes. A recent project that was completed at the
plant with the economizer tube replacement had a similar approach. The
economizer tubes were sources out of South Korea then shipped to Mexico for
fabrication. The tube bundles were shipped to the plant a month prior to installation.
CH Murphy was selected to install the economizer and work began two weeks prior
to the beginning of the annual Spring outage and was complete in 4 weeks. This
project will transfer to plant upon project completion.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This project aligns with providing safe and reliable renewable energy for our
customers.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
This project will invest into a base load renewable facility that will increase plant
reliability. The initial superheater was replaced after 16 years of service. The
current secondary superheater has been in service for 23 years and will be at
26 years of service at the time of replacement. The plant cannot operate without
the superheater and data shows most of the tubes have reached a critical point
needing to be replaced. Once replaced NDT testing will continue tracking the
new tubes as before to ensure proper maintenance and planning is documented
for future replacement.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Thermal Operations and Maintenance Manager
Plant Manager
Thermal Engineer
Kettle Falls Specialist
Supply Chain
2.8.2 Identify any related Business Cases
None
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Thermal and Operations Maintenance Manager
Plant Manager
Business Case Justification Narrative Template Version: January 2023 Pape 11 of 13
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 136 of 271

Docusign Envelope ID: F198D9F8-21D1-492C-AD913-50FD138761CA3
KF Secondary Superheater
GPSS Thermal Engineer
3.2 Provide and discuss the governance processes and people that will
provide oversight
This project will be managed similarly past project such as the recent
economizer replacement project. The Plant Manager will work closely with the
Thermal Engineer and/or Project Contract Engineering to manage the
procurement, fabrication and installation of the secondary superheater. Status
reports and monthly update meetings will be made to the Thermal Operations
and Maintenance Manager up until the installation process begins then weekly
progress meetings will be used to keep the group informed.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
This project will utilize Corporate Supply Chain Contract Change Order process
for any changes to scope, schedule and budget changes. The project will follow
the GPSS Department Project Delivery process. Issues or concerns will be
brought to the GPSS Thermal Operations and Maintenance Manager for
guidance and approval.
Business Case Justification Narrative Template Version: January 2023 Pape 12 of 13
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 137 of 271

Docusign Envelope ID: F1 98D9F8-21 D1-492C-AD9B-50FDB8761 CA3
KF Secondary Superheater
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Kettle Falls Secondary
Superheater Replacement Project 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.
Signed by:
Signature: F(-f-"4 (� wws Date: sep-17-zoz4 I 4:39 AM PDT
Print Name: "2CE3 CC64F9..
Greg iggins
Title: Plant Manager
Role: Business Case Owner
Signed by:
Signature: rvm'� t�dWta Date: sep-17-2024 112:13 PM PDT
Print Name: avic�s owell
Title: Director, GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role:
Business Case Justification Narrative Template Version: January 2023 Page 13 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 138 of 271

Docusign Envelope ID:30DODA7E-D69E-4E57-8A8F-6DBDF1FE79A6
Kettle Falls Ash Landfill Expansion
EXECUTIVE SUMMARY
PROJECT NEED: Kettle Falls Generation Station burns on average of 450,000 green
tons of wood waste annually. This combustion process creates roughly 30,000 cubic
yards of ash that is trucked and stored at the 177-acre parcel south of the plant site. The
landfill area is approximately 15 acres nested inside of a 42-acre fenced parcel
designated for landfill operations and development. The current ash landfill is reaching its
full capacity and is expected to be completely filled between 2025 to 2028 depending on
plant dispatch and ash production.
RECOMMENDED SOLUTION: The proposed solution to construct a new Phase 4 lined
landfill built to current standards will incorporate the closure costs of Phase 3 as part of
the construction of new disposal area.
ALTERNATIVES CONSIDERED:
• Phase 4 Concept 1
• Close Landfill and Dispose at Area Landfill
• Cancel Project due to Rerate Project
INITIAL COST ESTIMATE OF RECOMMENDED SOLUTION: $10,850,000
CURRENT COST ESTIMATE: $ 9,495,500
ADDITIONAL INFO: The Phase 3 Overlay / Phase 4 landfill is the lowest cost impact to
customers for disposal of ash as compared to disposal into the nearest acceptable landfill.
Disposal costs would exceed 2 million per year of O&M expense if Phase 4 is not
constructed. In addition, there is long-term operational risk if Avista does not control its
ash disposal mechanism. If the business case is not funded, it is estimated that the landfill
will exhaust its current capacity in 2026 and Avista would have nowhere to dispose of its
ash, jeopardizing operation of KFGS.
Business Case Justification Narrative Template Version: January 2023 Page 1 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 139 of 271

Docusign Envelope ID:30DODA7E-D69E-4E57-8A8F-6DBDF1FE79A6
Kettle Falls Ash Landfill Expansion
VERSION HISTORY
Version Author Description Date Notes
Draft Greg Wiggins GPSS_KF_Ash Landfill 07/9/2020 Reference Master
Ex ansion Landfill Plan
No substantive
1.0 Jessica Bean Transfer to new BCJN 01/06/2023 changes/edits have been
Template made to the business
case through this transfer
2.0 Greg Annual update 05/11/2023
Crossman
3.0 Don Sherrill Updated/confirmed following 09/03/2024
annual CPG approval.
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT($)
2024 $ 250,000 $ 0
2025 $ 6,020,000 $ 0
2026 $ 3,225,500 $ 9,495,500
Project Life Span 3 years
Requesting Organization/Department GPSS
Business Case Owner Sponsor Greg Wiggins David Howell
Sponsor Organization/Department GPSS
Phase Execution
Category Project
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 2 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 140 of 271

Docusign Envelope ID:30DODA7E-D69E-4E57-8A8F-6DBDF1 FE79A6
Kettle Falls Ash Landfill Expansion
1. BUSINESS PROBLEM- This section must provide the overall business case
information conveying the benefit to the customer, what the project will do and current
problem statement.
1.1 What is the current or potential problem that is being addressed?
The Kettle Falls Generation Station is a renewable resource for Avista that uses
biomass for its primary fuel source. The combustion process burning wood
creates ash in the volume of 30,000 cubic yards annually depending on plant
dispatch.
The current ash landfill is reaching its full capacity and is expected to be
completely filled between 2025 to 2028 depending on plant dispatch and ash
production.
1.2 Discuss the major drivers of the business case
Major drivers to this project include Mandatory & Compliance, Performance &
Capacity and Asset Condition. They Phase 3 landfill will require mandatory
proper closure following the Department of Ecology guidelines for retiring
landfills. Without having a disposal site for the ash, the plant would be forced to
close or operate as a natural gas fire unit which would lose 53 MW's of
renewable resources from Avista's portfolio. Estimated costs associated to haul
the ash to an area landfill exceed 2 million O&M expense annually. By
constructing the new expansion operating costs will significantly less.
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 landfill is nearing capacity. With permitting, engineering and construction
as part of the project, this project to finish construction within the expected life
of the current Phase 3 disposal area.
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
Kettle Falls Generating Station is a valuable resource for Avista. The plant
generates up to 53 MW's of base loaded renewable power to help meet Avista
vision of being 100% carbon neutral and a renewable. This project address
addresses the Trustworthy characteristic of our Company's values because
properly disposing of the ash is the right thing to do.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
Please 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 3 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 141 of271

Docusign Envelope ID:30DODA7E-D69E-4E57-8A8F-6DBDF1FE79A6
Kettle Falls Ash Landfill Expansion
Work has been ongoing since 2019 with third party Landfill consultants EIL
(Environmental Information Logistics) and Schwyn Environmental. Avista
Environmental support and plant staff have been modeling and tracking current
fill rates for 20+ years and have data to model the time in which the landfill will
reach full capacity. EIL has developed a Master Landfill Plan for the closure of
Phase 3 and the development of Phase 4 and ongoing associated operating
costs with the new landfill.
Ash has been generated from the plant and stored at the area landfill since 1986
consisting of three engineered cells (Phase 1-3). Phases 1 and 2 were closed
and covered in 2003 in accordance with WAC regulations. In February 2020 a
permit modification request was submitted with the Department of Ecology to
increase the slope of Phase 3 from a 4:1 to a 3:1. This request would increase
the capacity of the current Phase 3 by 110,000 cubic yards. On May 5th, 2020,
the Department of Ecology approved the request to increase the Phase 3 slope.
Calculations with the newly approved slope and existing air space revealed
Phase 3 reaching full capacity in 2025.
EIL and Schwyn Environmental Services was hired to assist in the planning and
budgeting efforts to create a Landfill Master Plan for current operations, closure
of Phase 3 and engineering and design of Phase 4. The creation of the new
Phase 4 landfill area creates space for ash disposal at the current rate of nearly
40-50 years of disposal.
Business Case Justification Narrative Template Version: January 2023 Page 4 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 142 of 271

Docusign Envelope ID:30DODA7E-D69E-4E57-8A8F-6DBDF1 FE79A6
Kettle Falls Ash Landfill Expansion
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: The recommended solution is to construct a new
Phase 4 lined landfill built to current standards that will incorporate the closure
costs of Phase 3 as part of the construction of the new disposal area.
Referenced in the Kettle Falls Master Landfill Plan as Concept 2A is to construct
Phase 4 utilizing the air space between the two cells. In this option some of the
Phase 3 closure costs are absorbed into the additional space created between
the two independent cells. The overlay of Phase 3 becomes part of the Ieachate
collection system for Phase 4 and increases total disposal capacity.
This solution is the best value and provides an estimated 40 to 50 years of
additional ash disposal capacity to Avista. As compared to Concept 1, this option
provides approximately 15 years of additional capacity by utilizing the
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2-CC ]•0) 4-CO 5.00 6-30 7,00 8-W 9.00 I-.00 12.00 t2•85
SECTION A-A' - CONCEPT 2A- PHASE 3 OVERLAY
ON PHASE 3 PERMITTED FINAL GRADES
intermediate space between the existing Phase 3 and future Phase 4 and only
minimally increases the project cost to do so. In addition, this option incorporates
Phase 3 closure costs, which provides additional value at nearly the same cost
as Concept 1.
In Scope: permitting, engineering and construction of new expansion phases,
plus new monitoring wells, Ieachate collection system, and ash handling
equipment.
Out of Scope: N/A
Assumptions: Due to new regulations regarding landfill design the proposed
solution will be a lined landfill with will generate Ieachate collected in the bottom
of the landfill which will need to be processed.
Business Case Justification Narrative Template Version: January 2023 Page 5 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 143 of 271

Docusign Envelope ID:30DODA7E-D69E-4E57-8A8F-6DBDF1FE79A6
Kettle Falls Ash Landfill Expansion
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
• EIL Kettle Falls Master Landfill Plan has been completed with input from
Avista Environmental Team and Plant historical data.
• Drone data was used to calculate the remaining air space of the current
landfill area. That data was used to set a timeline until the current Phase 3
will reach its maximum fill capacity date based on current operating data.
With an end date determined and the EIL Master Landfill Plan a schedule of
projects have been lined out to meet the need of having area to dispose of
the plant ash without disrupting the operations and output of the plant or
incurring significant disposal fees to area landfills.
• CARS (Capital Additions and Retirement) form which documents added and
removed assets associated with Avista's facilities. This document helps
Avista maintain accurate continuing property records.
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 $-
O&M N/A $-
Current studies are ongoing on the actual system or process that will be used
to process the wastewater which may create an O&M increase. Generally
speaking, there are no direct capital or O&M offsets that will result from this
project.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
s Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: January 2023 Page 6 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 144 of 271

Docusign Envelope ID:30DODA7E-D69E-4E57-8A8F-6DBDF1FE79A6
Kettle Falls Ash Landfill Expansion
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital N/A $-
O&M N/A $-
No indirect offsets have been identified associated with this project.
2.5 Describe in detail the alternatives, including proposed cost for each
alternative, that were considered, and why those alternatives did not
provide the same benefit as the chosen solution. Include those additional
risks to Avista that may occur if an alternative is selected.
RECOMMENDED ALTERNATIVE: Construct Phase 4 Concept 2A KF Ash
Landfill. The proposed solution will be a lined landfill with will generate leachate
collected in the bottom of the landfill which will need to be processed.
Alternative 1: Construct Phase 4 Concept 1 KF Ash Landfill; $10M
Concept 1 Phase 4 stand-alone cell WESTT
located to the east of Phase 3. This
design would create and entirely
separate landfill which will follow new
Limited Purpose Landfill regulations
that require an engineered base liner ------ " '°
and leachate collection system. Phase
3 shown in green will continue to be in
o.os swo .-os sws e.os Iwo e.ao u.ss io.as Tres
operations as Phase 4 shown in yellow SECTIONA-A'-CONCEPTI-STAND ALONE PHASE 4
is developed. Phase 3 will be closed
after operations shift to Phase 4. As compared to the selected alternative, this
alternative provides less capacity and greater overall site impact for almost the
same capital investment, so it was not selected.
Alternative 2: Close Phase 3 & begin Hauling Ash to Area Landfill; $2M
This alternative consisted of closure of the Phase 3 landfill area and then
disposing ash at an area landfill which would require an increase in O&M
expense near 2 million annually. This alternative does not provide a long-term
solution to Avista, and instead relies on a third-party being able to accept the
ash year after year, which may not be guaranteed. This presents undue risk to
Avista since its ability to continue operating would be dependent on third-party
ash acceptance.
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 7 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 145 of 271

Docusign Envelope ID:30DODA7E-D69E-4E57-8A8F-6DBDF1 FE79A6
Kettle Falls Ash Landfill Expansion
Alternative 3: Cancel Project because of future Kettle Falls Rerate Project;
$0 Capital Cost
Alternative 3 remains in consideration pending development of the Rerate
project and associated third-party Carbon Reduction Facility construction. The
third party developing the CRF is also developing alternate markets for the
existing KFGS ash stream that if realized would significantly reduce the volume
of ash needing to be disposed of at the landfill. Because this alternative is
contingent on a different project, it could not be selected on its own and therefore
the next best landfill expansion alternative (Phase 4 Concept 2A) is still being
pursued to provide the additional capacity should it be needed. However, in the
course of both projects this alternative will continue to be evaluated and will be
exercised if and when it is prudent for Avista to do so. As currently defined, this
alternative presents significant upside to Avista and in fact reduces cost and
risk, however it is not an at-will alternative because of its dependency on other
projects and markets.
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).
Work has been ongoing since 2019 with third party Landfill consultants EIL and
Schwyn Environmental. Avista Environmental support and plant staff have been
modeling and tracking current fill rates for 20+ years and have data to model the
time in which the landfill will reach full capacity. EIL has developed a Master
Landfill Plan for the closure of Phase 3 and the development of Phase 4 and
ongoing associated operating costs with the new landfill.
2.7 Include a timeline of when this work is scheduled to commence and
complete, if known.
❑x Timeline is Known
• Start Date: 2021
• End Date: 2027
❑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
Steering committee will include both GPSS and Environmental Senior
Leadership.
Business Case Justification Narrative Template Version: January 2023 Page 8 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 146 of 271

Docusign Envelope ID:30DODA7E-D69E-4E57-8A8F-6DBDF1FE79A6
Kettle Falls Ash Landfill Expansion
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
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 147 of 271

Docusign Envelope ID:30DODA7E-D69E-4E57-8A8F-6DBDF1FE79A6
Kettle Falls Ash Landfill Expansion
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Kettle Falls Ash Landfill
Expansion 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.
Signed by:
Signature: (P( -t,S Date: Sep-17-2024 1 4:47 AM PDT
Print Name: GzregB iggins
Title: GPSS Manager of O&M
Role: Business Case Owner
Signed by:
Signature: 5m,4 (�bWt,(.(, Date: Sep-17-2024 1 10:s1 AM PDT
Print Name:
�avic�' owell
Title: Director, GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: January 2023 Page 10 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 148 of 271

KF - 2022 ID Fan & Motor Replacement
EXECUTIVE SUMMARY
The induced draft (ID) fan at Kettle Falls Generating Station is a critical component in the
combustion process. The ID fan pulls a draft on the combustion fire box and discharges
the flue gas through the electrostatic precipitator and out the stack. The ID fan is
considered a "dirty" fan in which it is operating with fly ash in the flue gas. The fly ash is
abrasive on the internal components of the boiler. The fan shroud, case, cage and
dampers are requiring significant annual maintenance each year to build up the worn
area. The fan motor reaches max amperage during wet wood combustion and often hits
the max fan damper position.
The proposed solution involves replacing the ID fan and motor to appropriately
accommodate the needs of the plant. The proposed solution includes implementing a
variable frequency drive (VFD) which addresses fluctuations in loads expected from fuel
moisture and the ability to operate in a flexible EIM market. The VFD also improves fan
and motor efficiency during operations minimizing the wear that has become an annual
maintenance concern. The change in equipment will precipitate ducting changes and
potential foundation modifications. This solution has been the result of a collaboration
between plant management (Greg Wiggins and Patrick Lutskas) and plant technical staff.
Project scope has also been reviewed and approved by the program manager (Thomas
Dempsey). The proposed solution is budgeted to cost $1,650,000. The investment of the
ID fan and motor replacement (along with a VFD) will eliminate the costly repairs which
have only allowed the unit to limp from year to year. This is not only necessary to ensure
the plant is able to operate under full load with the expected range of fuel quality. All of
this adds value to the customer through improved operations and minimized maintenance
costs. There has been significant work with Air Stream, a fan manufacturer, in the testing,
sizing and cost estimating for this project. Options and recommendations have been
captured and this project has been well scoped and estimated.
VERSION HISTORY
Version Author Description I Date Notes
Draft Derek Babine Initial draft of original business case 05/24/2022 Executive Summary Only
1.0 Derek Babine Updated to include pro'ect'ustification 1 08/24/2022 Full business case
Business Case Justification Narrative Template Version: 04.21.2022 Page 1 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 149 of 271

KF - 2022 ID Fan & Motor Replacement
GENERAL INFORMATION
Requested Spend Amount $1,650,000
Requested Spend Time Period 2 years
Requesting Organization/Department K07/GPSS
Business Case Owner I Sponsor Derek Babine I Alexis Alexander
Sponsor Organization/Department K07/GPSS
Phase Initiation
Category Project
Driver Asset Condition
1. BUSINESS PROBLEM
The induced draft (ID) fan at Kettle Falls is a part of the flue gas system which pulls
a draft on the combustion fire box and discharges the flue gas through the
electrostatic precipitator and out the stack. The ash in the fuel gas is abrasive which
has caused significant wear to all of the fan components and case. The motor driving
the fan is also suffering from being overworked during times of poor fuel quality and
high demand on the system at full load. This sometimes results in a need to limit the
plant's output because the motor cannot keep up with the material that the fan is
processing. Currently, the plant uses inlet guide vanes (or dampers) to regulate the
flue gas entering the fan chamber. This ensures that the fan does not get
overloaded. These dampers are only able to aid the process of the flue gas so much
before the motor is maxed out and the plant is forced to drop megawatts.
In short, the mounting maintenance costs for the fan and the inability for the motor
to keep up with the volume and quality of flue gas led to higher costs and lost
generation.
Business Case Justification Narrative Template Version: 04.21.2022 Page 2 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 150 of 271

KF - 2022 /D Fan & Motor Replacement
1.1 What is the current or potential problem that is being addressed?
The induced draft fan faces significant maintenance nearly every annual outage
as a result of fan blades wearing down from fly ash abrasion. Usually, these
repairs come in the form of welding additional material on the blades and
grinding it down to maintain the effectiveness of the fan. This is costly and
difficult work which does not address the root problem, that the fan is nearing
the end of life. The motor also maxes out in amperage and is unable to
accommodate the flue gas flow under certain conditions.
1.2 Discuss the major drivers of the business case
The main driver of the business case is certainly asset condition but there is
also a performance and capacity issue as the fan and motor age, they are no
longer able to process flue gas to the degree necessary under certain operating
conditions which can limit the capacity of the plant.
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The fan and motor limp along each year thanks to extensive maintenance but
the effective longevity of this strategy is unknown. If the fan has severe enough
wear, the plant would be forced to come offline due to an inability to process flue
gas. While the repair costs continue to build, there is also the possibility of
unplanned plant downtime if the fan or motor needs to be replaced in the case
of equipment failure. Additionally, this project has already been deferred for
several years.
1.4 Identify any measures that can be used to determine whether the
investment would successfully deliver on the objectives and address the
need listed above.
As a result of the proposed project, the plant will see a large reduction in annual
maintenance to the fan for the next 10-20 years. Any repairs will be minimal by
comparison. Also, the plant's efficiency and increased productivity will be shown
by amperage numbers which do not max out on the motor and steadier plant
output even during times of poor fuel quality.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the problem
N/A
Business Case Justification Narrative Template Version: 04.21.2022 Page 3 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 151 of 271

KF - 2022 ID Fan & Motor Replacement
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 graph above shows a typical instance of the plant ramping up to nearly full
load (MWs shown in purple) with the damper position maxing out (orange trend)
as the motor tops out in amperage (shown in blue). Once the amps on the motor
plateau around 105 amps, the other parameters are forced to plateau as well.
This shows how the motor can be a limiting factor in the plant's MW output.
SEEMS&;
The photos above show the kind of repairs that were necessary during the
spring outage of 2021 . There are extensive weld repairs on large sections of the
fan blades and plate metal additions to replace material that has been eroded
during the life of the fan. This kind of repair has been routine over the last several
years and is costly as it is very time-intensive work. The blades and periphery
Business Case Justification Narrative Template Version: 04.21.2022 Page 4 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 152 of 271

KF - 2022 ID Fan & Motor Replacement
continue to see deterioration each year. Ideally another major repair job (as
shown above) can be avoided before the fan is replaced.
2. PROPOSAL AND RECOMMENDED SOLUTION
The proposed solution involves replacing the ID fan and motor to appropriately
accommodate the needs of the plant. The proposed solution includes implementing
a variable frequency drive (VFD)which addresses fluctuations in loads expected from
fuel moisture and the ability to operate in a flexible EIM market as well as being able
to pick up generation gaps which could result from the proposed plant addition. The
VFD also improves fan and motor efficiency during operations minimizing the wear
that has become an annual maintenance concern. Power consumption of the fan
motor will be minimized by having the VFD adjust the motor's output. The change in
equipment will precipitate ducting changes and potential foundation modifications.
Option Capital Cost Start Complete
Replace the ID fan, motor and add VFD $1,650,000 10/2022 06/2024
Replace the ID fan and motor(no VFD) $1,150,000 10/2022 06/2024
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
The main data points which were considered in preparation of this capital
request are the limitations to plant performance and output which have been
manifested in PI data and control room rounds sheets over the past several
years. This data will also allow tracking of improvement once the solution is
implemented. Although the problems have exhibited themselves for many more
years, this most recent data shows the immediacy of the issue and regularity of
limited operation. Maintenance and repair costs alone have pushed the need for
these components to be replaced into the foreground. Both the concerns for
hampered generation and the concern about potential downtime due to asset
conditions have also been considered. In regard to determining whether to
implement a VFD into the system, the power savings achieved by replacing
dampers with a new drive and the pay-back period for this option make this
solution desirable. Additionally, the VFD will be able to provide improved ability
to make up for potential losses in generation related to the plant upgrade and
flexibility of operation in unideal fuel conditions which provide additional power
consumption cost savings.
Business Case Justification Narrative Template Version: 04.21.2022 Page 5 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 153 of 271

KF - 2022 ID Fan & Motor Replacement
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 ID fan and motor replacement project will consist of a multi-year project with
the first year being the procurement of the fan, motor and VFD. Year two will
be the installation of these components as part of the annual Spring outage. The
year that these components are installed there will be no need for fan repair
which will be reflected in reduced O&M costs.
A complete failure of the ID Fan could extend many weeks. The estimated
daily Power Supply outage cost for this facility is $69,700 (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.
This project will be managed within the normal spring annual outage. The VFD
will save on station power which will increase power out to our customers.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
One alternative is to let the assets run to failure. This is a risky option for several
reasons most notably the potential for unplanned plant downtime. It also would
result in increasing O&M costs in the coming years with the replacement still
required at the point of failure.
Another alternative is to not implement a VFD into the system and essentially
just replace the components in kind with what is currently installed. This
alternative is viable but could present the plant with some of the issues which
are currently problematic such as limitations during poor fuel quality and wasted
energy consumption when dampers are heavily utilized. The VFD addresses
these issues making it a more desirable solution.
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.
Procurement of components for this project will begin in mid-summer of 2023
due to long lead times on items such as the VFD and ID fan. Design
considerations and consulting have already begun with the fan and VFD
supplier and these will continue up and through the point of purchase. The ID
fan, motor and VFD will all be installed during the annual spring outage
timeframe in 2024 and will be used and useful upon completion when the plant
comes back online following the outage.
Business Case Justification Narrative Template Version: 04.21.2022 Page 6 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 154 of 271

KF - 2022 /D Fan & Motor Replacement
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
This project aligns with providing safe and reliable renewable energy for our
customers.
2.7 Include why the requested amount above is considered a prudent
investment, providing or attaching any supporting documentation. In
addition, please explain how the investment prudency will be reviewed
and re-evaluated throughout the project
This project invests into the long-term life of the plant and takes into
consideration modifications related to plant expansion. This solution resets the
clock on extensive fan repairs and increases the efficiency of the plant by
implementing new technology which will allow the plant to be more adaptable to
varying fuel quality and generation setpoints. Although the plant has been able
to get along in the current state, it is not a sustainable solution and this work will
not only improve performance but provide minimize maintenance on these
components for decades due to technological advances in fan and drive design.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface with the business case
Thermal Operations and Maintenance Manager
Plant Manager
Thermal Engineer
Kettle Falls Specialist
Supply Chain
2.8.2 Identify any related Business Cases
N/A
3. MONITOR AND CONTROL
3.1 Steering Committee or Advisory Group Information
Thermal and Operations Maintenance Manager
Plant Manager
GPSS Thermal Engineer
Business Case Justification Narrative Template Version: 04.21.2022 Page 7 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 155 of 271

KF - 2022 ID Fan & Motor Replacement
3.2 Provide and discuss the governance processes and people that will
provide oversight
The Plant Manager will work with the Thermal Engineer and/or Project Contract
Engineering to manage the procurement, fabrication and installation of the ID
fan, motor and VFD. Status reports and monthly update meetings will be made
to the Thermal Operations and Maintenance Manager up until the installation
process begins then weekly progress meetings will be used to keep the group
informed.
3.3 How will decision-making, prioritization, and change requests be
documented and monitored
This project will utilize Corporate Supply Chain Contract Change Order process
for any changes to scope, schedule and budget changes. The project will follow
the GPSS Department Project Delivery process. Issues or concerns will be
brought to the GPSS Thermal Operations and Maintenance Manager for
guidance and approval.
4. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Kettle Falls ID Fan & Motor
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: Date: 8/24/2022
Print Name: Derek Babine
Title: Mechanical Engineer
Role: Business Case Owner
Digitally signed by Alexis
Signature: Alexis Alexander nder
pate 2022.09.05 10:39:26-07'00' Date:
Print Name: Alexis Alexander
Title: Director of GPSS
Role: Business Case Sponsor
Thomas C Digitally signed by Thomas C
Signature: Dempsey Date: 08/31/2022
Dempsey Date:2022.08.31 11:04:59-07'00'
Print Name: Thomas Dempsey
Business Case Justification Narrative Template Version: 04.21.2022 Page 8 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 156 of 271

KF - 2022 ID Fan & Motor Replacement
Title: GPSS Thermal Ops & Maint. Mgr.
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: 04.21.2022 Page 9 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 157 of 271

DocuSign Envelope ID:84285D87-DDBO-4022-A678-14C386E1992D
Little Falls Plant Upgrade
EXECUTIVE SUM M ARY
The Little Falls Plant Upgrade Program began in 2012 and in 2020, is in the final phases of im oem entation.
With three project com ponents left (Plant Sum I, Drain Field, and Panel Room Roof/Enclosure for the new
controls equipm ent) the vast m ajority of the project scope has been com Oeted and risks m tigated. The
rem aning work has very little risk exposure and m him al im pact on the plant's current operations.
Driven initially by the age of the infrastructure at the plant, Alternative 3, a full replacement of all four
generatring units and all obsolete supporting equipment, was selected, im piem ented, and put in service.
G i en as how the program is nearly com Oete and decisions have already been m ade in regards to the
following, no additional details regarding solution recom m eldations, risk of failure to im piem Ent, schedule
significance or benefit to custom ers are provided at this tim e
The rem aning programmed work is being scheduled into 2021 as a response to internal resource
constraints, and therefore, this business case and its rem aning activities are subject to this Business Case
Refresh exercise.
VERSIO N HISTO R(
Version Author D escription D ate N otes
1.0 Brian Vandenburg I nitial draft of original business case 2 .14.17 S i ned/approved
1.1 Kara Heatherly C onversion to new format 6 .20.20 I ncludes budget update
G BVERAL INFO IN ATIO N
Requested Spend Amount $ 56,100,000
Requested Spend Time Period 1 0 years
Requesting O iganization/Departm@nt G SS
Business Case O w ear I Sponsor Brian Vandenburg Andy Vickers
Sponsor O iganization/DeparFm ent G SS
Phase E xecution
Category P roject
Driver A sset Condition
Business Case Justification Narrative P age 1 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 158 of 271

DocuSign Envelope ID:84285D87-DDBO-4022-A678-14C386E1992D
Little Falls Plant Upgrade
1. BUSINESS PRO ELEM
1.1 What is the current or potential problem that is being addressed?
The existing Little Falls equipm Ent ranges in age from 60 to m cre than 100 years old. Little Falls
experienced an increase in forced outages over the past six years, increasing from about 20 hours
in 2004 to several hundred hours in the past several years, due to equipm Ent failures on a num ber
of different pieces of equipment.
Once the business case is com plete, a study of forced outages at the plant over a 5 year period could
be taken and m easured against the pre-construction outage num bers to determ he if plant availability
has increased and the business case objective m et.
1.2 Discuss the major drivers of the business case and the benefits to the
customer
The m 4or drivers for the Little Falls Plant Upgrade are available and reliability. See the graph below
that illustrates the trend line for availability at Little Falls.
Plant Availability
1
0.95
0.9 Trend Line
0.85
0.8
2001 2 002 2 003 2 004 2 005 2 006 2 007 2 008 2 009 2 010
1.3 Identify w by this w crk is needed now and w hat risks there are if not
approved or is deferred
See alternatives analysis narrative conducted at project onset in section 2.1 for additional
details.
1.4 Identify any measures that can be used to determine whether the
investment w auld successfully deliver on the objectives and address the
need listed above.
See alternatives analysis narrative conducted at project onset in section 2.1 for additional
details.
O ption Capital Cost O 81M Cost Start Complete
Business Case Justification Narrative P age 2 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 159 of 271

DocuSign Envelope ID:84285D87-DDBO-4022-A678-14C386E1992D
Little Falls Plant Upgrade
Alternative 3: Preferred $ 56,100,000 $ 0 2 012 2 021
Status Q w $ 0 $ 150,000/yr
Alternative 1 $ 5,000,000 $ 20,000/yr
Alternative 2 $ 83,000,000 $ 0
2.1 Describe w hat metrics, data, analysis or information was considered w hen
preparing this capital request.
Sum m ay of alternatives:
Status Q uD: Forced outages and emergency repairs would continue to increase, reducing the
reliability of the plant. Each tim ea generator goes down for an em Ergency repair, Avista is forced to
replace this energy from the open m arket which leads to higher energy costs.
It is expected that the O 8M costs would continue to clim b as m are failures occurred. This m ay also
require personnel to be placed back in the plant to m an the plant 24/7 in order to respond to failures.
Again, increasing expenses for the project with no benefit in perform ance.
Alternative 1: Replace Switchgear and Exciter: This would replace the two items that are currently
responsible for the m ajority of the forced outages,and then continue to use the rem aning equipm ent.
This alternative is a temporary fix. O re of the generators has a splice and is expected to fail in the
next few years. If this generator fails before a new generator is ordered, this generator will be out of
service for 2 years. The control system is a vintage system and is on the verge of a total failure and
spare parts are not available (a few m hor system failures occurred in the past 2 years). If a total
system failure is encountered, it is expected the plant to be down for a year as the control system is
designed, procured and installed.
Alternative 2: Replace all generating units with larger, vertical units capable of additional output.
Avista's Power Supply group evaluated the present value of larger, vertical units at Little Falls. The
increase in present value from larger units was $20M over a 30 year analysis. The capital
construction cost increase from in-kind replacement to vertical units was $27M.
This present value calculation of benefit did not include risk. Installing new vertical units would require
modification of the powerhouse foundation and presents serious construction risk. Due to the high
construction costs, high risk, and low payoff NPV, this alternative was abandoned.
Alternative 3 and Proposed Alternative: Replace nearly all of the older and less reliable equipm ent
with new equipment. This includes replacing two of the turbines, all four generators, all generator
breakers, three of the four governors, all of the AVR's, rem wing all four generator exciters, replacing
the unit controls, replacing the unit protection system,and replacing and modernizing the station
service. All m ajor equipm Ent would be procured through a competitive bid process to help keep
construction costs low. Equipment would also be purchased for all four units at once to help keep
costs down.
Additional Justification for Proposed Alternative:
Because of the age and condition of all of the equipm ent at the plant, all of the equipm Ent has been
qualified as obsolete in accordance with the obsolescence criteria tool. The Asset M anagem ent tool
has been applied to Little Falls and also supports this project. The Asset Management studies that
have been done to date are still subject to further refinements, but the general conclusions support
this project. There are many item s in this 100 year old facility which do not m eet m odern design
standards, codes, and expectations. This project will bring Little Falls to a place where it can be
relied on for another 50 to 100 years. Finally, this project will need to be worked in coordination with
our Indian Relations group as the Little Falls project is part of a settlement agreement with the
Spokane Tribe.
Strategic Alignm Ent:
Business Case Justification Narrative P age 3 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 160 of 271

DocuSign Envelope ID:84285D87-DDBO-4022-A678-14C386E1992D
Little Falls Plant Upgrade
The Little Falls Plant Upgrade aligns with the Safe and Reliable Infrastructure com pany strategy.The
program will address safety and reliability issues while looking for innovative, econom cal ways to
deliver the projects.
2.2 Discuss how the requested capital cost am ount w it 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 know nor estimated reductions to O 8M as a result of this investment.
In accordance with the detailed project schedule, annual projected capital expenditures for
rem aning scope are in accordance with the 5-year CPG budget table below.
Year Requested Amount CPG Approved Amount
(Adm n use only)
2021 $800,000
2022 $0
2023 $0
2024 $0
2025 $0
2.3 O aline any business functions and processes that may be impacted (and
how)by the business case for it to be successfully implemented.
No direct relationship exists between the other parts of the business and the com Oetion of the
rem aning Little Falls program work.All integral connection points with other business units have
already been made. Equipm ant upgrades have been performed to support other corporate
priorities (such as EIM and HM I) and plant processes that are im pacted by the rem aning work
are directly and appropriately involved in the planning and scheduling of that work in order to
insure seem less integration with the plant.
2.4 Discuss the alternatives that w cre considered and any tangible risks and
m itigation strategies for each alternative.
See alternatives analysis narrative conducted at project onset in section 2.1 for additional
details. This project is in the closeout phase and budget is being adjusted into future years to
respond to resource availability. Any remaining project risks will be m tigated at the project
steering com mitee level for the rem aning active program com ponents.
2.5 Include a timeline of when this w crk will be started and completed.
Describe w hen the investments become used and useful to the customer.
spend, and transfers to plant by year.
M iestone Schedule (reflective of original business case m iestones):
January 2010 P rogram Begins
Business Case Justification Narrative P age 4 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 161 of271

DocuSign Envelope ID:84285D87-DDBO-4022-A678-14C386E1992D
Little Falls Plant Upgrade
March 2012 E xciter& G anerator Breaker Replacem ent Com Mete
January 2014 W rehouse Construction Com Mete
January 2014 B ridge Crane O%erhaul Com Pete
February 2015 S tation Service Replacement Complete
February 2016 U nit 3 M odernization Complete
April 2017 U nit 1 Modernization Complete
O dober 2017 B ackup G alerator Install Complete
May 2018 U nit 2 M odernization Complete
May 2019 U nit 4 M odernization Complete
O dober 2019 H eadgate Replacem ent Complete
Yearly Transfer to Plant:
2 013 $ 3,100,000
2014 $ 2,000,000
2 015 $ 4,000,000
2 016 $ 16,300,000
2 017 $ 10,400,000
2 018 $ 9,000,000
2 019 $ 13,000,000
T otal $ 57,800,000
2.6 Discuss how the proposed investment aligns w th strategic vision, goals,
objectives and mission statement of the organization.
Mission: This project safely, responsibility and affordably improves the level of service we
provide to our custom ers by m him Bing our exposure to potential, prolonged breaks in
service.
Strategic Initiatives: 1. Safe and Reliable Infastructure, 2. Responsible Resources.
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 w it be reviewed
and re-evaluated throughout the project
Prudency considers not only the likelihood of risk but the severity of the outcom a in the event
of failure. Prior to their upgrade, failure of these sytem scould have been nearly im m adiately
catastrophic. M him Bing the severity of non-preventable failure is the prudent and
responsible thing to do.
2.8 Supplemental Information
2.8.1 Identify customers and stakeholders that interface w kh the business case
Custom ers and Stakeholders:
Business Case Justification Narrative P age 5 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 162 of 271

DocuSign Envelope ID:84285D87-DDBO-4022-A678-14C386E1992D
Little Falls Plant Upgrade
M he M agruder M nager, Hydro O perations and M antenance
AlexisaAlexander M nager, Spokane River Hydro Operations
Kevin Powell C hief Operator, Long Lake and Little Falls HED
3.1 Steering Com m ttee or Advisory G pup Information
This program is com prised of two layers of Steering Com mitee O\ersight.O re layer of oversight
is at the program level and the other layer is at the project level.
3.2 Provide and discuss the governance processes and people that w it
provide oversight
The Program Steering Com mitee is responsible for vetting and approving the objective, scope
and priority of the program.The deliverables for the program are then reviewed with the Program
Steering Com mtitee on a sera annual basis. Any significant changes to the program' scope,
budget or schedule will be approved by the Program Steering Com mitee.The Program Steering
Com mitee is composed of the Director of G PSS and the Director of Power Supply. This
corn mitee m eets sera annually or as m ajor events create a change order request.
The Project Steering Com mitee oversees the deliverables of the individual projects. Each
m ern bar of the steering corn mitee represents a m ajor stakeholder in the project. The m ambers
are dependent on the respective project but will include representatives from hydro operations,
central shops and engineering. The Project Steering Com mitee will approve any changes to
the schedule,scope and budget of the individual project.They also are responsible for approving
the necessary personnel for the corn pletion of the project. This group is engaged on a quarterly
basis.
M are detailed project governance protocols will be established during the project chartering
process vehereby he Steering Com mitee Wll allocate appropriate resources b tie
m anagem ant of all project activities, once better defined.
3.3 How W1 decision-making, prioritization, and change requests be
documented and monitored
Project decisions will be m ade at the PM level where appropriate and escalated to the
Project/Program Steering Com mtitee when and if determ hed to be necessary by the
definitions above. Regular updates will be provided to the Steering Com mitee by the PM team
as project scope, schedule and budget are defined, and through the course of the project
execution, change.
The undersigned acknowledge they have reviewed the HM I Control Software 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.
Docusignedby: 70-10-2020 1 8:14 AM PDT
Signature: ate:
Print Nam a o304eee6iii p anden urg
Title: M anager, Hydro O perations
Role: Business Case O vuner
DocuSigned by:
Signature: ate: Jul-10-2020 1 8:30 AM PDT
91A 144 4(tom,Y 3
Business Case Justification Narrative P age 6 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 163 of 271

DocuSign Envelope ID:84285D87-DDBO-4022-A678-14C386E1992D
Little Falls Plant Upgrade
Print Nam a Andy Vickers
Title: Director of G PSS
Role: Business Case Sponsor
DocuSigned by:
Signature: 1I ate: Jul-13-2020 1 5:56 AM PDT
Print Name sooa,e,saa� t Kinney
Title: Director of Power Supply
Role: Steering/Advisory Com mitee Review
Template Version: 05/28/2020
Business Case Justification Narrative P age 7 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 164 of 271

DocuSign Envelope ID:4D20580E-098B-479C-B578-D95COB854F1 D
Long Lake Plant Upgrade
EXECUTIVE SUMMARY
PROJECT NEED: The equipment needs to be upgraded for continued reliability as soon
as possible. The existing equipment ranges in age from 20 to more than 100 years old.
We have experienced an increase in forced outages at Long Lake over the past several
years, almost zero in 2011 and increasing every year since then. This is caused by
equipment failures on several different pieces of equipment. The other major driver for the
program is safety. The switching procedure for moving station service from one generator
to the other resulted in a lost time accident and a near miss in the past 5 years. In addition,
the station service disconnects represent the greatest arc-flash potential in the company.
This area is roped off and substantial safety equipment is required to operate the
disconnects. This project will reconfigure this system to eliminate requiring personnel to
perform this operation and avoid the arc-flash potential area.
RECOMMENDED SOLUTION: The recommended solution is Alternative 4, replace Units
In-Kind. The Long Lake Plant Upgrade is a series of several capital project improvements
built into a larger Capital Program.
The program includes a full plant condition assessment, replacement of all Generating
Units, Generator Step-up Transformers (GSUs), Station Service, and many of the
mechanical, electrical, and controls systems and equipment have met their end of useful
life.
ALTERNATIVES CONSIDERED:
• Alternative 1: Install four new 60MW vertical units
• Alternative 2: Construct one unit powerhouse
• Alternative 3: Construct two-unit powerhouse
• Alternative 4: Do Nothing
COST OF RECOMMENDED SOLUTION: An anticipated program budget of $145M has
been developed.
ADDITIONAL INFO: This equipment needs to be replaced in order to continue to operate
efficiently. Upgrading our Long Lake Plant will enable our generation fleet to continue to
provide safe and reliable power to our customers.
Long Lake serves Avista's allocated north electric district providing power to our
transmission grid and local distribution power sources. The primary drivers for the Long
Lake Plant Upgrade are Performance & Capacity, Asset Condition, and Failed Plant &
Operations.
If not approved, The Long Lake powerhouse would continue to operate as it has for the
past 10 years. O&M costs would continue to rise. Due to the condition of the generators,
it is likely that one of the generators or another piece of major equipment will fail and
permaM)nently disable equipment, increasing forced outage numbers. For example, in
December of 2021 GSU 4 was replaced due to its dangerously high gas levels. This was
Business Case Justification Narrative Template Version: January 2023 Page 1 of 15
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 165 of 271

DocuSign Envelope ID:4D20580E-098B-479C-B578-D95COB854F1 D
Long Lake Plant Upgrade
a cost of $280k, and fortunately we had a spare otherwise the unit would still be out of
service.
The Plant Upgrade began in 2017 and will continue until estimated completion in
December 2029.
Business Case Justification Narrative Template Version: January 2023 Page 2 of 15
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 166 of 271

DocuSign Envelope ID:4D20580E-098B-479C-B578-D95COB854F1 D
Long Lake Plant Upgrade
VERSION HISTORY
Version Author Description Date Notes
1.0 Steve Wenke Initial Request 04/10/2017 This was on the old
template
2.0 Mac Mikkelsen Revised 09/02/2022 Transferred to new
version
No substantive
3.0 Jessica Bean Transfer to new BCJN Template 01/06/2023 changes/edits have been
made to the business
case through this transfer
James
4.0 Edwards/Mac Update for 2023 submission 05/10/2023
Mikkelsen
BCRT Team Has been reviewed by BCRT
BCRT Member and meets necessary
requirements
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2024 $ 19,800,000 $ 500K
2025 $ 17,500,000 $ 1.5 Million
2026 $ 16,700,000 $45 Million
2027 $ 16,500,000 $ 20 Million
2028 $ 15,900,000 $ 30 Million
Project Life Span 14 years
Requesting Organization/Department GPSS
Business Case Owner I Sponsor Michael Truex Alexis Alexander
Sponsor Organization/Department GPSS
Phase Execution
Category Program
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's
site see link.
Investment Drivers
Business Case Justification Narrative Template Version: January 2023 Page 3 of 15
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 167 of 271

DocuSign Envelope ID:4D20580E-098B-479C-B578-D95COB854F1 D
Long Lake Plant Upgrade
1. BUSINESS PROBLEM- This section must provide the overall business case
information conveying the benefit to the customer, what the project will do and current
problem statement.
1.1 What is the current or potential problem that is being addressed?
The existing equipment ranges in age from 20 to more than 100 years old.
We have experienced an increase in forced outages at Long Lake over the
past several years, almost zero in 2011 and increasing every year since
then. This is caused by equipment failures on several different pieces of
equipment. Specifically, the turbines are thrusting too much (a sign of
significant wear), including a failure in 2015. The 1990 vintage control system
is failing, and only secondary markets can support this equipment.
The original generators consist of a stator frame, stator core, stator winding,
and rotor field poles. They were originally rated at 12 MW's. In the late
1940's, the height of the dam was raised 16 feet which resulted in more
operating head for the generating units. A forced air-cooling system for the
generators was added to the plant at that time to accommodate the increase
in output from 12 to 17 MW's due to the increased head. In the 1960's, the
stator windings on all the units were replaced and the rating of the
generators, along with the forced air system allowed for the units to operate
at the higher 17 MW output.
In the 1990's, the original turbine runners were replaced and upgraded. The
improvement in turbine runner efficiency resulted in still another increase in
unit output. Since the mid-1990's, the generators have been operating with a
maximum output of 22 to 24 MW's. The generators are currently operated at
their maximum temperature which stresses the life cycle of the already
+50-year-old winding.
Inspections of other components of the generator show the stator core is
"wavy". The core lamination steel should be in straight. The "wave" pattern is
a strong indication of higher-than-expected losses occurring in the generator.
Finally, maintenance reports have identified that the field poles on the rotor
have shifted very slightly from their designed position over the years. While
there can be several causes of this movement, it is speculated that it is due
to the high operating temperatures of the generator. This highlights the first
driver for the program, reliability.
With the increase in generator output, the output of the GSU has also
increased to its rating. These GSU's are now running at the high 650 C
temperature which is a concern. As these GSU's are more than 30 years old
and operating at the high end of their design temperature, these are now
approaching their end of useful life and need to be replaced proactively rather
than waiting for a failure.
Business Case Justification Narrative Template Version: January 2023 Page 4 of 15
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 168 of 271

DocuSign Envelope ID:4D20580E-098B-479C-B578-D95COB854F1 D
Long Lake Plant Upgrade
1.2 Discuss the major drivers of the business case
Asset Condition: Much of the plant and its components are aged to the point of
failure and/or have become obsolete. The Long Lake HIED is a critical asset
needed for generation of clean renewable energy. The consistent and reliable
operation of the generating units and related equipment is needed to be able to
confirm generation, distribution, and transmission of electricity to our customers.
The equipment is also essential to recreation, environmental protection, dam,
and public safety. These all benefit the customer by increasing efficiency and
safety in performance.
The other major driver for the program is safety. The switching procedure for
moving station service from one generator to the other resulted in a lost time
accident and a near miss in the past 5 years. In addition, the station service
disconnects represent the greatest arc-flash potential in the company. This area
is roped off and substantial safety equipment is required to operate the
disconnects. This project will reconfigure this system to eliminate requiring
personnel to perform this operation and avoid the arc-flash potential area.
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 equipment needs to be upgraded for continued reliability as soon as
possible. The risks of deferment may result in the lack of the ability to generate
hydroelectricity and provide our commitment to the BES, and EIM. Deferment
will also lead to increased O&M costs. The Long Lake powerhouse would
continue to operate as it has for the past 10 years. O&M costs would continue
to rise. In an additional 10 years, if the trend continues, average O&M costs will
rise from $285k in 2005 to $590k in 2014 and projected to be $900k in 2024.
Due to the condition of the generators, it is likely that one of the generators or
another piece of major equipment will fail and permanently disable equipment,
increasing forced outage numbers.
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 Long Lake Plant Upgrade aligns with the Safe and Reliable Infrastructure
company strategy. The program will address safety and reliability issues while
looking for innovative, economical ways to deliver the projects.
Business Case Justification Narrative Template Version: January 2023 Page 5 of 15
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 169 of 271

DocuSign Envelope ID:4D20580E-098B-479C-B578-D95COB854F1 D
Long Lake Plant Upgrade
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.'
• Relevant data is comprised of Long Lake HED historical data, maintenance
logs, asset condition, third party analysis, and lessons learned from similar
work performed at Little Falls HED
• Summary of Investment Considerations for Long Lake Modernization
Program
• Spokane River Assessment (Oct 2014) Phase II Reconnaissance Study —
Long Lake HED — URS
• Long Lake Dam Generator Voltage Study & Life Cycle Analysis (June 2020)
- Stantec
• Long Lake Modernization Basis of Design Index was developed to determine
what systems and subsystems were in scope for the Modernization effort.
• Below is a graph of Forced Outage Factor for Long Lake HED from Avista's
Asset Management Plan.
Long Lake HED Forced Outage Factor
--*—Long Lake HED Unit 1 +Long Lake HED Unit 2
Long Lake HED Unit 3 Long Lake HED Unit 4
35%
30%
25% —
20%
15%
10% 0.0522 GADSbenchmark or
29MW&smaller hydro units
5%
0% 3 .. - ~�
2009 2010 2011 2012 2013 2014 2015
The below graph shows the O&M cost at Long Lake for years 2005-2015.The trendline
is increasing due to increasing repairs to aging equipment.
Business Case Justification Narrative Template Version: January 2023 Page 6 of 15
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 170 of 271

DocuSign Envelope ID:4D20580E-098B-479C-B578-D95COB854F1 D
Long Lake Plant Upgrade
O&M Cost at Long Lake
1,000,000
900,000
800,000
700,000
600,000
500,000
400,000 --
300,000
200,000
100,000
0
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015
' 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 7 of 15
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 171 of271

DocuSign Envelope ID:4D20580E-098B-479C-B578-D95COB854F1D
Long Lake Plant Upgrade
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: Replace Units In-Kind: replace the existing major unit
equipment (generator, field poles, governors, exciters, generator breakers) with
new equipment. The equipment needs to be upgraded for continued reliability
as soon as possible. The risks of deferment may result in the lack of the ability
to generate hydroelectricity and provide our commitment to the BES, and EIM.
Deferment will also lead to increased O&M costs.
In Scope: Replace units (generator, field poles, governors, exciters, generator
breakers) with new equipment. Disassembly and disposal of original equipment
mentioned above. Demolition, Removal and Replace existing Station Service
and GSUs. Location of current GSUs will be used for new exciter equipment.
New GSUs will be placed on structural pads in the upper parking lot. A tailrace
bulkhead has been designed and fabricated to mitigate high water levels during
the unit replacement. Asbestos and lead abatement to allow for removal of
existing East Mezzanine cubicles. Build new relay/communication room where
East Mezzanine cubicles were located. New relay and communication
equipment. Removal and disposal of existing emergency generator and
purchase/installation of new EG outside of powerhouse. Design/build new
battery room on breaker floor. Build new battery room on breaker floor.
Purchase and install new battery bank and UPS. Completed work includes a
sewer system overhaul, access road overhaul, bridge crane replacement,
facilities upgrade (including new break and conference rooms), and a new
forklift.
Out of Scope: This project will not include the design and installation of a
substation outside of the powerhouse. Control Room will be upgraded but not
moved. Parking lot improvements are being designed and implemented as part
of Regulating Hydro and are not included in this effort. The roll up bulkhead door
was completed in 2022 as part of Regulating Hydro. No work associated with
the forebay, headgates, spillgates or crescent dam is included. Incline elevator
assessment and replacement is not included. Assessment or refurbishment of
penstocks is not included.
Assumptions:
Projects completed
• May 2017 — Project Kickoff
• September 2018 — Bridge Crane Replacement - Complete
• September 2018 — Sewer System Overhaul - Complete
• September 2018 —Access Road Overhaul - Complete
• January 2020 — Facilities Upgrades Phase 1 - Complete
• September 2021 —Tailrace Bulkhead - Complete
Business Case Justification Narrative Template Version: January 2023 Page 8 of 15
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 172 of 271

DocuSign Envelope ID:4D20580E-098B-479C-B578-D95COB854F1 D
Long Lake Plant Upgrade
Projects planned execution to begin
• June 2024 — Man Door Bulkhead
• June 2024 — Plant Air System
• October 2024 - Station Service Replacement 1
• October 2024—GSU Upgrade Phase 1
• October 2024— First Unit Upgrade
• March 2025— Battery Room / UPS
• November 2025—Control Room Upgrade
• September 2026—Second Unit Upgrade
• November 2027 - Station Service Replacement 2
• November 2027 —GSU Upgrade Phase 2
• November 2027 —Third Unit Upgrade
• November 2027 — Plant Sump System
• November 2028 — Fourth Unit Upgrade
• February 2026 — Facilities Upgrade Phase 2
Project# Project Start Finish LTD $
20305098 Station Service 2 03/2017 - 1,606,506
20305099 Bridge Crane Upgrade 04/2017 12/2019 2,354,027
20305105 Access Road Paving 01/2018 09/2018 1,128,036
20305106 Sewer System Upgrade 01/2018 01/2019 207,855
20305121 Unit 3 Modernization 02/2019 - 6,627,661
20305122 Unit 3 Upgrade ET 02/2019 - 36,950
20305123 Facilities Upgrade— Ph1 07/2019 01/2020 557,641
20305128 Facilities Upgrade ET 07/2019 06/2020 181,797
20305139 Tailrace Bulkhead Unit Mod 04/2020 03/2022 1,291,377
20305142 Forklift 10/2020 12/2020 124,752
02807019 6.9kV Substation 05/2022 123,752
20305177 GSU 4 Removal 03/2023 480
$14,240,354
$5,845,485 has been transferred to plant through the completed projects above.
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
• Long Lake Dam Generator Voltage Study & Life Cycle Analysis (June 2020)
- Stantec
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 9 of 15
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 173 of 271

DocuSign Envelope ID:4D20580E-098B-479C-B578-D95COB854F1 D
Long Lake Plant Upgrade
• Long Lake Modernization Basis of Design Index was developed to determine
what systems and subsystems were in scope for the Modernization effort.
• Class 5 Estimate from Stantec
• The 2018 Hydro Generation Condition & Risk Assessments is referred to as
the "2018 Assessment. Early 2018 GPSS-Hydro department undertook an
initiative to revamp their maintenance programs. This included the 2018
Assessment, which was conducted in the hydro plants and incorporated
both Risk Assessments and Condition Assessments. Teams consisting of
representatives from the Mechanic, PCM Tech, and Electric Shops, as well
as Spokane River Hydro, Clark Fork River Hydro, and Maximo teams were
formed and tasked with performing a condition and risk based assessment
for assets in all of Avista's hydro facilities. Additional details may be found
in the "2018 Hydro Asset Management Program Directory". The full
reference is provided below:
The Condition Assessments were based on the CEATI hydroAMP 2.0 guide.
The database developed during the 2018 assessment has been used to
create business information tools to identify and analyze equipment
strategies to be used by GPSS for making business decisions.
The purpose of the Risk Assessment was to identify the environmental,
financial, and safety risks associated with each asset and what possible
consequences might result from an asset failure. Consequences were
framed within the Avista Business Risk Matrix. Financial risks might include
lost generation during an outage. Probabilities were then estimated as an
answer to the following question: Given an asset failure, what is the
probability that a particular, potential consequence will actually occur? As
an aid to this process, probabilities were selected from a menu of specified
probability levels. Results of the Risk Assessments have been used to
estimate asset risk costs. Risk cost is the product of the Failure Rate,
Potential Consequence of failure. This risk cost is a probable dollar value
associated with Avista's exposure risk of each asset.
The results of the 2018 Assessment have been used to develop Asset
Management Plans (AMPS) and a Risk Based Investment Planning (RBIP)
tool. AMPs have been developed for a number of the asset classes, such
as the generators, turbine runners, GSUs, trash rakes, etc. The AMPs outline
capital and maintenance strategies. A primary purpose of the RBIP tool is
to bring a risk-based perspective to the capital budget process.
Reference - Avista Utilities, "2018 Hydro Asset Management Program
Directory", Avista Utilities GPSS Dept., March 15, 2019
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 I Offset Description 1 2024 1 2025 1 2026 1 2027 1 2028
Business Case Justification Narrative Template Version: January 2023 Pape 10 of 15
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 174 of 271

DocuSign Envelope ID:4D20580E-098B-479C-B578-D95COB854F1 D
Long Lake Plant Upgrade
Capital Increase in production $0 $50K $100K $150K $200K
O&M Reduction in labor and $0 $50K $100K $150K $225K
equipment for unplanned
maintenance and
breakdowns
Over the past 11 years, the average O&M spend at Long Lake was $470k, with
the low being $262k and the high year being $944k. In addition, the O&M cost
is trending upward. After the upgrade, the expected O&M cost is $200k/year, an
average reduction of$270k/year.
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 Reduction in forced $OK $250K $750M $1.25M $1.75M
outages that reduce
generation
O&M Less risk of outages $100K $150K $200K $250K $300K
leading to greater ability to
plan employees work
rather than reacting to
breakdowns and failures
Indirect offsets are a result of fewer expected forced outages. This will lead to
an increase in capital production, described above as a reduction missed
capital. This is based on an assumption of$50k/day of generation per unit.
The O&M offsets are based on fewer outages leading to employees being able
to remain allocated to current project and operation work. People are not
reserved for outage work so when outages occur, they are pulled from their
normally assigned tasks.
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.
a Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: January 2023 Pape 11 of 15
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 175 of 271

DocuSign Envelope ID:4D20580E-098B-479C-B578-D95COB854F1D
Long Lake Plant Upgrade
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: The recommended solution is to replace
Units In-Kind.
Alternative 1: Install four new 60MW vertical units; $173M
This alternative would be to replace the four existing units in the powerhouse
with four new 30 MW Kaplan units. Significant civil, electrical, and mechanical
work would be required, in addition to powerhouse access.
The increased yearly generation would be 114,000MWh. Using $30/MWh
(extremely conservative number) the rough yearly benefit to Avista is $3.4M.
The payoff period is greater than 30 years and therefore this alternative was
abandoned.
Alternative 2: Construct one unit powerhouse; $144M
Instead of upgrading the current powerhouse, this alternative is to construct a
new powerhouse with a single, 68MW next to the existing powerhouse, using
the saddle dam (also referred to as the "arch dam") as an intake. This alternative
would only use the old powerhouse during high flows, when flows exceeded the
new unit's capacity. Additional funds would be required to upgrade, even at a
minimum level, to address some of the failing components.
The increased yearly generation would be 170,000MWh. Again, using $30/MWh
the rough yearly benefit to Avista is $5.1 M. The payoff for this is 30 years. Again,
since this cost does not include the additional work required in the plant and the
cost of the risk associated with modifying the saddle dam, this alternative was
abandoned.
Alternative 3: Construct two-unit powerhouse; $276M
Another option to build a new powerhouse is to construct a new powerhouse
with two, 76MW units next to the existing powerhouse. This alternative would
also use the saddle dam as an intake. This alternative would only use the old
powerhouse during extreme high flows, minimizing the need to perform any
upgrades to the old plant.
The increased yearly generation would be 258,000MWh. Using $30MWh, the
rough yearly benefit to Avista is $7.7M. The payoff would be greater than 30
years and therefore the alternative was abandoned.
Business Case Justification Narrative Template Version: January 2023 Page 12 of 15
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 176 of 271

DocuSign Envelope ID:4D20580E-098B-479C-B578-D95COB854F1 D
Long Lake Plant Upgrade
Alternative 4: Do Nothing; $OM
The Long Lake powerhouse would continue to operate as it has for the past 10
years. O&M costs would continue to rise. In an additional 10 years, if the trend
continues, average O&M costs will rise from $285k in 2005 to $590 in 2014 and
projected to be $900k in 2024. Due to the condition of the generators, it is likely
that one of the generators or another piece of major equipment will fail and
permanently disable equipment, increasing forced outage numbers.
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 LLPU project team will be utilizing data from GPSS asset condition
information, trending plant data, as well as third party engineering experts to
assist in alternative analysis and engineering recommendations for upgrades.
Third party studies have helped identify large scale options for the plant
upgrade, and internal Avista engineering in partnership with third party
consultants have added additional alternatives for consideration. Alternative
analysis options are considering upfront costs, construction costs, life cycle
costs, return of investment, and sustained maintenance costs, along with future
capacity options.
2.7 Include a timeline of when this work is scheduled to commence and
complete, if known.
❑x Timeline is Known
• Start Date: 2017
• End Date: 2031
❑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
This program is comprised of two layers of Steering Committee Oversight. One layer
of oversight is at the program level and the other layer is at the project level.
The Program Steering Committee is responsible for vetting and approving the objective,
scope, and priority of the program. The deliverables for the program are then reviewed
with the Program Steering Committee on a semi-annual basis. Any significant changes
to the program's scope, budget or schedule will be approved by the Program Steering
Committee. The Program Steering Committee is composed of the Director of GPSS,
Director of Environmental Affairs, and the Director of Power Supply. This committee
meets semi-annually, or as major events create a change order request.
Business Case Justification Narrative Template Version: January 2023 Pape 13 of 15
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 177 of 271

DocuSign Envelope ID:4D20580E-098B-479C-B578-D95COB854F1 D
Long Lake Plant Upgrade
The Project Steering Committee oversees the deliverables of the individual projects.
Each member of the steering committee represents a major stakeholder in the project.
The members are dependent on the respective project but will include representatives
from hydro operations, central shops, and engineering. The Project Steering
Committee will approve and changes to the schedule, scope, and budget of the
individual project. They also are responsible for approving the necessary personnel for
the completion of the project. This group is engaged on a quarterly basis.
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 Pape 14 of 15
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 178 of 271

DocuSign Envelope ID:4D20580E-098B-479C-B578-D95COB854F1 D
Long Lake Plant Upgrade
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Long Lake Plant Upgrade
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: Nl,i(,6t,(, fihxt Date: Au9-08-2023 111:08 AM PDT
Print Name: Michael Truex
Title: GPSS Manager of Project
Management
Role: Business Case Owner
DocuSigned by:
Signature: Fa(011S &)- AJW Date: AU9-26-2023 I 1:31 AM PDT
Print Name: Alexis Alexander
Title: Director, GPSS
Role: Business Case Sponsor
Signature: NA Date:
Print Name: NA; Alexis Alexander is currently
on the project Advisory Committee
Title: NA
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: January 2023 Pape 15 of 15
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 179 of 271

DocuSign Envelope ID: C6A78F7D-DOA6-496E-B7D1-33B84D21OD99
Nine Mile Unit 3 Mechanical Overhaul
EXECUTIVE SUMMARY
PROJECT NEED: There are a multitude of mechanical issues with Nine Mile Unit 3. The
original Unit 3 was replaced with a new American Hydro unit in 1995. Unit 3 experienced
cracked buckets on the runners in 2010. This was found to be due to heavy wear due to
erosion from sediment and cavitation damage. The cracks were repaired; however, the
sediment wear has continued, and bucket failure is anticipated. The installed roller guide
bearing also does not provide the thrust bearing support it was designed to, causing the
upstream generator guide bearing to take the entire thrust loading of the machine. This
condition puts increased stress and wear on the generator bearings and increases the
risk of failure. During the 2018 Maintenance Assessment, this bearing was identified as
high risk due to its current condition.
RECOMMENDED SOLUTION: The recommended solution is to mechanical overhaul the
Unit including installing new Francis Runners, new downstream water lubricated bearing
and pedestal, new combination thrust/guide bearing with thrust shaft, and refurbishment
of the wicket gate stems and all operating components
ALTERNATIVES CONSIDERED:
• Alternative 1: Do-nothing and continue to repair the current system under O&M.
COST OF RECOMMENDED SOLUTION: The estimated cost of the project is $6,500,000
ADDITIONAL INFO: 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). This alternative would provide a lasting solution to the problems
outlined above and avoid a costly unanticipated failure. If left unaddressed, the Unit is
likely to experience bucket or bearing failure.
Business Case Justification Narrative Template Version: January 2023 Page 1 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 180 of 271

DocuSign Envelope ID: C6A78F7D-DOA6-496E-B7D1-33B84D21OD99
Nine Mile Unit 3 Mechanical Overhaul
VERSION HISTORY
Version Author Description Date Notes
Draft Ryan Bean Initial draft of original business 6/21/2019
case
1.0 Ran Bean Updated Approval Status 7/2/2019 Full amount approved
2.0 Ryan Bean 5 Year Planning 2020 & New 7/8/2020
Form
3.0 Ran Bean 5 Year Planning 2021 7/2/2021
4.0 Ran Bean Annual Update 7/29/2022 No Changes
BCRT Team Has been reviewed by BCRT
BCRT Member and meets necessary
requirements
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2024 $ 2,007,261 $ 5,346,757
2025 $ 0 $ 0
2026 $ 0 $ 0
2027 $ 0 $ 0
2028 $ 0 $ 0
Project Life Span 3 years
Requesting Organization/Department GPSS
Business Case Owner I Sponsor Michael Truex Alexis Alexander
Sponsor Organization/Department GPSS
Phase Initiation
Category Project
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's
site see link.
Investment Drivers
Business Case Justification Narrative Template Version: January 2023 Page 2 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 181 of271

DocuSign Envelope ID: C6A78F7D-DOA6-496E-B7D1-33B84D21OD99
Nine Mile Unit 3 Mechanical Overhaul
1. BUSINESS PROBLEM- This section must provide the overall business case
information conveying the benefit to the customer, what the project will do and current
problem statement.
1.1 What is the current or potential problem that is being addressed?
The runners, as well as other critical mechanical components, including
buckets, are not performing and are approaching end of life.
1.2 Discuss the major drivers of the business case
The driver for this business case is Asset Condition. Several critical
components of the unit are at or approaching end of life. Nine Mile supplies
year-round base load hydroelectric power to Avista's portfolio.
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.
If the condition of this Unit is left unaddressed, the Unit is likely to experience
bucket or bearing failure resulting in extended down time and lost generation.
In the event of an unanticipated failure, procuring new replacement runners
would likely take at least 8-12 months to procure, resulting in substantial loss of
power generation.
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
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).
1.5 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 metric supporting the overhaul of the current system is that it is at or
approaching end of life. In addition to worn runners, the installed F.A.G. roller
guide bearing also does not provide the thrust bearing support it was designed
to, causing the upstream generator guide bearing to take the entire thrust
loading of the machine. The bearing supports the full thrust loading on a small
thrust collar that was not designed for it, resulting in additional wear and heating.
This condition puts increased stress and wear on the generator bearings and
increases the risk of failure.
' 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 3 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 182 of 271

DocuSign Envelope ID: C6A78F7D-DOA6-496E-B7D1-33B84D21OD99
Nine Mile Unit 3 Mechanical Overhaul
During the 2018 Maintenance Assessment, this bearing was identified as high
risk due to its current condition. The table below is an excerpt from the 2018
Maintenance Assessment. The condition indicators are dimensionless scores.
A 3 is rating of good. On the bottom end, a 0 is poor. 2 and 1 are fair and
marginal, respectively.
1 Net Condition Index& Rating Summary
2 Units
Condition
3 Nine Mile Falls HED Asset Group Rating IN
29 Turbine Bearings, Unit 3 Oil Lube 1.333
Business Case Justification Narrative Template Version: January 2023 Page 4 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 183 of 271

DocuSign Envelope ID: C6A78F7D-DOA6-496E-B7D1-33B84D21OD99
Nine Mile Unit 3 Mechanical Overhaul
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: The recommended solution is to mechanical overhaul
the Unit including installing new Francis Runners, new downstream water
lubricated bearing and pedestal, new combination thrust/guide bearing with
thrust shaft, and refurbishment of the wicket gate stems and all operating
components. If the condition of this Unit is left unaddressed, the Unit is likely to
experience bucket or bearing failure resulting in extended down time and lost
generation. In the event of an unanticipated failure, procuring new replacement
runners would likely take at least 8-12 months to procure, resulting in substantial
loss of power generation. This solution replaces the mechanical components
that are near failure/at end-of-life.
In Scope: In kind replacement of Francis Runners (4), new downstream water
lubricated bearing and pedestal, new combination thrust/guide bearing with
thrust shaft, and refurbishment of the wicket gate stems (2 stems on each wicket
gate, 64 wicket gates total) and all operating components (including shift ring,
operating rods, and mechanical linkages (shafts and bearings)); cooling water
work (?)
Out of Scope: Work will not be replacing any primary shafts; design work;
cooling water work
Assumptions: New equipment will be purchased new, AVA crafts will be
installing, Servos will be replaced under a different project, no crane work will
be required; primarily Avista labor; adding bearing to system; full set of bearing
pads; major components to be refurbished will be sent out for contract
refurbishment. No design work, scope is equivalent to work completed on Unit
4 (2014)
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
• See 2010 Unit 3 Bucket Repair documentation and Unit 4 Mechanical
Overhaul Project documentation.
• CARS (Capital Additions and Retirement)form which documents added and
removed assets associated with Avista's facilities. This document helps
Avista maintain accurate continuing property records.
Business Case Justification Narrative Template Version: January 2023 Page 5 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 184 of 271

DocuSign Envelope ID: C6A78F7D-DOA6-496E-B7D1-33B84D210D99
Nine Mile Unit 3 Mechanical Overhaul
• In early 2018, the GPSS-Hydro department undertook an initiative to revamp
their maintenance programs. This initiative included an overall assessment
of all hydro plants in Avista's fleet. The program included both Risk
Assessments and Condition Assessments. The 2018 Hydro Generation
Condition & Risk Assessments, is referred to as the "2018 Assessment."
Teams consisting of representatives from the Mechanic, PCM Tech, and
Electric Shops, as well as Spokane River Hydro, Clark Fork River Hydro,
and Maximo teams were formed and tasked with performing a condition and
risk-based assessment for assets in all Avista's hydro facilities. Additional
details may be found in the "2018 Hydro Asset Management Program
Directory". The full reference is provided below:
The Condition Assessments were based on the CEATI hydroAMP 2.0 guide.
The database developed during the 2018 assessment has been used to
create business information tools to identify and analyze equipment
strategies to be used by GPSS for making business decisions.
The purpose of the Risk Assessment was to identify the environmental,
financial, and safety risks associated with each asset and what possible
consequences might result from an asset failure. Consequences were
framed within the Avista Business Risk Matrix. Financial risks might include
lost generation during an outage. Probabilities were then estimated as an
answer to the following question: Given an asset failure, what is the
probability that a particular consequence will materialize? As an aid to this
process, probabilities were selected from a menu of specified probability
levels. Results of the Risk Assessments have been used to estimate asset
risk costs. Risk cost is the product of the Failure Rate, Potential
Consequence of failure. This risk cost is a probable dollar value associated
with Avista's exposure risk of each asset.
The results of the 2018 Assessment have been used to develop Asset
Management Plans (AMPs) and a Risk Based Investment Planning (RBIP)
tool. AMPs have been developed for a number of asset classes, such as
the generators, turbine runners, GSUs, trash rakes, etc. The AMPs outline
capital and maintenance strategies. A primary purpose of the RBIP tool is
to bring a risk-based perspective to the capital budget process.
Reference - Avista Utilities, "2018 Hydro Asset Management Program
Directory", Avista Utilities GPSS Dept., March 15, 2019
• 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
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 6 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 185 of 271

DocuSign Envelope ID: C6A78F7D-DOA6-496E-B7D1-33B84D21OD99
Nine Mile Unit 3 Mechanical Overhaul
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]
• A similarly scoped project was performed on Nine Mile Unit 4 several years
ago. Project cost estimates and construction experience from the project
were used to estimate a nearly identical body of work for Unit 3.
2.3 Summarize in the table and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital Reduced Outages $0 $0 $0 $0 $0
O&M Reduced Maintenance $50,000 $0 $0 $0 $0
This project will offset annual O&M maintenance charges in responding to failed
components and mitigate the risk of unanticipated failures.
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets I Offset Description 1 2024 1 2025 1 2026 1 2027 Ej028
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: January 2023 Page 7 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 186 of 271

DocuSign Envelope ID: C6A78F7D-DOA6-496E-B7D1-33B84D21OD99
Nine Mile Unit 3 Mechanical Overhaul
Capital NA I $0 I $0 $0 I $0 $0
O&M NA I $0 I $0 $0 I $0 $0
Estimated indirect savings and/or productivity gains and associated benefits
have not been quantified at this time; however, as applicable, please see the
referenced Risk Based Investment report (see Section 2.2) for additional
information.
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: The recommended solution is to
mechanical overhaul the Unit including installing new Francis Runners, new
downstream water lubricated bearing and pedestal, new combination
thrust/guide bearing with thrust shaft, and refurbishment of the wicket gate
stems and all operating components. The investment would be fielded in several
phases over the course of two years. The design, procurement, and installation
specifications of the new equipment would be overseen by GPSS Engineering
as part of a project team.
Alternative 1: Continue to Repair Current System; Capital Cost ($0)
This alternative would not replace or rehabilitate any mechanical components.
Labor and materials would be used to fix equipment as needed. While the Unit
is capable of continued operation in its current state, the likelihood of
catastrophic failure due to runner or bearing failure is increasing. Due to the
engineering required and long lead times on this equipment, the financial
impacts of a failure would be substantial due to extended down time. Given the
current bearing condition and known wear on the runners, doing nothing is not
a preferred option.
Business Case Justification Narrative Template Version: January 2023 Page 8 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 187 of 271

DocuSign Envelope ID: C6A78F7D-DOA6-496E-B7D1-33B84D21OD99
Nine Mile Unit 3 Mechanical Overhaul
2.6 Include a timeline of when this work is scheduled to commence and
complete, if known.
❑x Timeline is Known
• Start Date: 2022
• End Date: 2024
❑Timeline is Unknown
2.7 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
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
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
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 188 of 271

DocuSign Envelope ID: C6A78F7D-DOA6-496E-B7D1-33B84D21OD99
Nine Mile Unit 3 Mechanical Overhaul
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Nine Mile Unit 3 Mechanical
Overhaul 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: t6d fib- Date: AUg-08-2023 111:04 AM PDT
Print Name: Michael Truex
Title: GPSS Manager of Project
Management
Role: Business Case Owner
DocuSigned by:
Signature: ratk)'(S Q(k)IMtJIX Date: Au9-26-2023 11:38 AM PDT
Print Name: Alexis Alexander
Title: Director, GPSS
Role: Business Case Sponsor
Signature: NA Date:
Print Name: NA; Michael Truex is currently on
the steering committee
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: January 2023 Pape 10 of 10
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 189 of 271

DocuSign Envelope ID: 17B5DABE-A93D-407E-8C08-B089A3553C30
Nine Mile 3 & 4 Controls Upgrade
EXECUTIVE SUMMARY
PROJECT NEED: Nine Mile Units 3 and 4 controls were installed in the early 1990's and
are at the end of their intended life and there is an increased likelihood of forced outages
and subsequent loss of revenue and reliability. During the 2018 Maintenance
Assessment, the Unit controls were rated in poor condition and high in risk due their age
and current condition. The switchgear floor is overloaded which poses a safety risk. In
2010, the switchgear floor was found to be inadequate for any loading above and beyond
what it is currently supported, and partially replaced during the Unit 1 and 2 replacement
project. The re
EXECUTIVE SUMMARY
PROJECT NEED: There are a multitude of mechanical issues with Nine Mile Unit 3. The
original Unit 3 was replaced with a new American Hydro unit in 1995. Unit 3 experienced
cracked buckets on the runners in 2010. This was found to be due to heavy wear due to
erosion from sediment and cavitation damage. The cracks were repaired; however, the
sediment wear has continued, and bucket failure is anticipated. The installed roller guide
bearing also does not provide the thrust bearing support it was designed to, causing the
upstream generator guide bearing to take the entire thrust loading of the machine. This
condition puts increased stress and wear on the generator bearings and increases the
risk of failure. During the 2018 Maintenance Assessment, this bearing was identified as
high risk due to its current condition.
RECOMMENDED SOLUTION: The recommended solution is to mechanical overhaul the
Unit including installing new Francis Runners, new downstream water lubricated bearing
and pedestal, new combination thrust/guide bearing with thrust shaft, and refurbishment
of the wicket gate stems and all operating components
ALTERNATIVES CONSIDERED:
• Alternative 1: Do-nothing and continue to repair the current system under O&M.
COST OF RECOMMENDED SOLUTION: The estimated cost of the project is $6,500,000
ADDITIONAL INFO: 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). This alternative would provide a lasting solution to the problems
outlined above and avoid a costly unanticipated failure. If left unaddressed, the Unit is
likely to experience bucket or bearing failure.
minder of the floor will need to be replaced to ensure adequate floor loading can be
achieved.
RECOMMENDED SOLUTION: A controls upgrade including speed controllers
(governors), voltage controls (automatic voltage regulator or AVR), primary unit control
system (i.e., Unit PLC), and the upgraded protective relay system is needed on units 3
Business Case Justification Narrative Template Version: January 2023 Page 1 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 190 of 271

DocuSign Envelope ID: 17B5DABE-A93D-407E-8C08-B089A3553C30
Nine Mile 3 & 4 Controls Upgrade
and 4. Included in the scope of this project is replacement of the switchgear floor inside
the Nine Mile powerhouse that will be utilized for relocation of the unit controls and voltage
regulation equipment.
ALTERNATIVES CONSIDERED:
• Alternative 1: One alternative considered is to replace the electrical equipment but
not upgrade the floor.
• Alternative 2: A second alternative considered was to do-nothing
COST OF RECOMMENDED SOLUTION: The cost of the solution is estimated to be
about $4,125,000 per unit at this time; total of $8,250,000.
ADDITIONAL INFO: The completion of this project will reduce maintenance costs and
improve reliability delivered to Avista's customers as upgrading the controls, monitoring,
and protection will reduce unplanned outages. This solution will address issues of
obsolescence, increased likelihood of unplanned outages, and performance needs to
work with the new dynamics of modern systems. This includes integration of intermittent
resources, reserves, frequency and voltage response, and the ability to adapt these
controls and protection devices as the larger grid continues to evolve. If this business
case is not approved the risks above would continue as the asset condition continues to
decline.
Business Case Justification Narrative Template Version: January 2023 Page 2 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 191 of271

DocuSign Envelope ID: 17B5DABE-A93D-407E-8C08-B089A3553C30
Nine Mile 3 & 4 Controls Upgrade
VERSION HISTORY
Version Author Description Date Notes
Kristina
1.0 Newhouse Initial submission 7/2/2019
Ryan Bean
2.0 Kristina Updated to 2020 template 7/31/2020
Newhouse
3.0 Kristina Updated to 2022 template and 8/23/2022
Newhouse & modified budget to align with
PJ Henscheid improved 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
BCRT Team Has been reviewed by BCRT
BCRT Member and meets necessary
requirements
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2024 $ 2,100,000 $ 0
2025 $ 2,300,000 $ 0
2026 $ 2,250,000 $ 0
2027 $ 250,000 $ 8,250,000
2028 $ 0 $ 0
The business case will include 2 projects, one for Unit 3 and another for Unit 4.
Design and Construction for each project take place over 3 years with the design
of unit 4 starting during construction of unit 3. Each project with be transferred
to plant at the completion of construction
Construchon
Is
Business Case Justification Narrative Template Version: January 2023 Page 3 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 192 of 271

DocuSign Envelope ID: 17B5DABE-A93D-407E-8C08-B089A3553C30
Nine Mile 3 & 4 Controls Upgrade
Project Life Span 4 years
Requesting Organization/Department GPSS
Business Case Owner I Sponsor Michael Truex Alexis Alexander
Sponsor Organization/Department GPSS
Phase Planning
Category Project
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's
site see link.
Investment Drivers
Business Case Justification Narrative Template Version: January 2023 Page 4 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 193 of 271

DocuSign Envelope ID: 17B5DABE-A93D-407E-8C08-B089A3553C30
Nine Mile 3 & 4 Controls Upgrade
1. BUSINESS PROBLEM- This section must provide the overall business case
information conveying the benefit to the customer, what the project will do and current
problem statement.
1.1 What is the current or potential problem that is being addressed?
The problem is that Nine Mile Units 3 and 4 controls are obsolete, unsupported
and in overall poor condition; the switchgear floor is overloaded which is
structurally unsafe.
1.2 Discuss the major drivers of the business case
The major driver of this business case is Asset Condition. There have been unit
outages that were specifically taken to address problems associated with the
existing control and protection equipment. Problems with the governor and
wicket gate actuating mechanisms continue to affect unit reliability. The current
governor system is undersized to handle the required load, causing startup and
speed control issues.
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.
During the 2018 Maintenance Assessment, the Unit controls were rated in poor
condition and high in risk due their age and current condition. This equipment is
at the end of its intended life and there is an increased likelihood of forced
outages and subsequent loss of revenue and reliability.
Upgrading the speed controllers (governors), voltage controls (automatic
voltage regulator a.k.a. AVR), primary unit control system (i.e., PLC), and the
protective relay system will address issues of obsolescence, increased
likelihood of unplanned outages, and performance needs to work with the new
dynamics of modern systems.Also, the switchgear floor is inadequate to support
additional loading for new equipment to be place. Replacing the remainder of
the floor will ensure adequate floor loading can be achieved.
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
Replacing obsolete and problematic control equipment on unit 3 and unit 4 will
increase reliability and efficiencies at Nine Mile HED. This program safely,
responsibly, and affordably improves our customers' lives through innovative
energy solutions.
Customers benefit in that it will allow Avista to economically optimize an existing
asset to provide energy and other energy related products.
Business Case Justification Narrative Template Version: January 2023 Page 5 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 194 of 271

DocuSign Envelope ID: 17B5DABE-A93D-407E-8C08-B089A3553C30
Nine Mile 3 & 4 Controls Upgrade
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
During the 2018
Maintenance Assessment, Cost PmHk —Com Wive Costs/Age
the Unit controls were $600,000
rated in poor condition and $5W,000
high in risk due their age
and current condition. This :<�•�°
equipment is at the end of
its intended life and there 353°°'°°°
is an increased likelihood $2WOo°
of forced outages and
subsequent loss of $l°°•°°°
revenue and reliability.
:°
o as
Please see the graphs " " " " " " " . " Age(Years)
which illustrate the Lifecyle
Cost Analysis that was
done as part of the 2018
Maintenance
Assessment.
' 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 6 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 195 of 271

DocuSign Envelope ID: 17B5DABE-A93D-407E-8C08-B089A3553C30
Nine Mile 3 & 4 Controls Upgrade
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: The recommended solution is to replace unit control,
monitoring, and protection systems, and it includes replacement of the
switchgear floor to adequately support the new equipment to be placed. In
addition to addressing issues of obsolescence and increased likelihood of
unplanned outages, replacement of these key systems addresses the
performance needs to work with the new dynamics of the systems today. This
solution solves the problem described above through the integration of
intermittent resources, reserves, frequency and voltage response, and the
ability to adapt these controls and protection devices as the larger grid continues
to evolve.
In Scope: The requested capital costs will cover design (contract labor),
material, factory acceptance testing (contract labor), installation (AVA labor),
and commissioning. To accomplish project objectives that will improve unit
response, operating flexibility, and reliability, the following components will be
considered: governor and governor controls, generator excitation system and
AVR, protective relays, and unit controls, Unit 3 & 4 switchgear. The objective
is to ensure system compatibility with current standards and improve system
reliability. Flooring upgrades are limited to demo and reinforced (approx. half of
the switchgear floor, ballpark 30'x50')
Out of Scope: Disassembling or pulling poles on the generators; generator work
is limited to housekeeping, switchgear replacement.
Assumptions: Equipment will not be replaced in-kind: motor operated governor
will be replaced with a hydraulic system; the current Bailey controls hardware
will be replaced with a PLC; new Unit 3 & 4 switchgear will be relocated to the
new switchgear floor (no modifications to the existing switchgear location will
need to be made once the old switch gear is removed)
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
• CARS (Capital Additions and Retirement) form which documents added and
removed assets associated with Avista's facilities. This document helps
Avista maintain accurate continuing property records.
Business Case Justification Narrative Template Version: January 2023 Page 7 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 196 of 271

DocuSign Envelope ID: 17B5DABE-A93D-407E-8C08-B089A3553C30
Nine Mile 3 & 4 Controls Upgrade
• The 2018 Hydro Generation Condition & Risk Assessments, is referred to as
the "2018 Assessment." Early 2018 GPSS-Hydro department undertook an
initiative to revamp their maintenance programs. This included the 2018
Assessment, which was conducted in the hydro plants and incorporated
both Risk Assessments and Condition Assessments. Teams consisting of
representatives from the Mechanic, PCM Tech, and Electric Shops, as well
as Spokane River Hydro, Clark Fork River Hydro, and Maximo teams were
formed and tasked with performing a condition and risk based assessment
for assets in all of Avista's hydro facilities. Additional details may be found
in the "2018 Hydro Asset Management Program Directory". The full
reference is provided below:
The Condition Assessments were based on the CEATI hydroAMP 2.0 guide.
The database developed during the 2018 assessment has been used to
create business information tools to identify and analyze equipment
strategies to be used by GPSS for making business decisions.
The purpose of the Risk Assessment was to identify the environmental,
financial, and safety risks associated with each asset and what possible
consequences might result from an asset failure. Consequences were
framed within the Avista Business Risk Matrix. Financial risks might include
lost generation during an outage. Probabilities were then estimated as an
answer to the following question: Given an asset failure, what is the
probability that a particular, potential consequence will actually occur? As
an aid to this process, probabilities were selected from a menu of specified
probability levels. Results of the Risk Assessments have been used to
estimate asset risk costs. Risk cost is the product of the Failure Rate,
Potential Consequence of failure. This risk cost is a probable dollar value
associated with Avista's exposure risk of each asset.
The results of the 2018 Assessment have been used to develop Asset
Management Plans (AMPs) and a Risk Based Investment Planning (RBIP)
tool. AMPs have been developed for a number of the asset classes, such
as the generators, turbine runners, GSUs, trash rakes, etc. The AMPs outline
capital and maintenance strategies. A primary purpose of the RBIP tool is
to bring a risk-based perspective to the capital budget process.
Reference - Avista Utilities, "2018 Hydro Asset Management Program
Directory", Avista Utilities GPSS Dept., March 15, 2019
Additionally, the following files from the 2018 Maintenance Assessment can
be found at (c01m114) G:\Generation\Asset Management\GPSS Condition
Assessment Forms and References\Condition Assessment - NM
1. Nine Mile Hydro AMP 041912.xlsx file
2. NM Lifecycle Cost Calculator 061918.xlsx
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 8 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 197 of 271

DocuSign Envelope ID: 17B5DABE-A93D-407E-8C08-B089A3553C30
Nine Mile 3 & 4 Controls Upgrade
• 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 associate 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
While the generator is capable of producing energy with existing systems, this
solution requires maintenance of old systems that are no longer supported by
the original manufacturer and there is some question on parts availability.
Additionally, trained personnel available to work on these older systems are
becoming scarce and formal training is no longer available. For reasons of
obsolescence, inadequate system performance, and increasing maintenance
demands, this option is not the preferred option. This project is a replacement
of EOL technology and controls equipment that is no longer supported by
s Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: January 2023 Page 9 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 198 of 271

DocuSign Envelope ID: 17B5DABE-A93D-407E-8C08-B089A3553C30
Nine Mile 3 & 4 Controls Upgrade
industry R&D and necessary support infrastructure to ensure reliable,
affordable, and safe generation, production, and distribution of power.
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital N/A $0 $0 $0 $0 $0
O&M N/A $0 $0 $0 $0 $0
Estimated indirect savings and/or productivity gains and associated benefits
have not been quantified at this time; however, as applicable, please see the
referenced Risk Based Investment report (see Section 2.2) for additional
information.
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: The recommended solution is to replace
unit control, monitoring, and protection systems and upgrade the switchgear
floor. We cannot continue to operate units 3 and 4 at Nine Mile HED and expect
the same results as when the controls were installed over 20 years ago.
Technology has improved and the expectations for automation and monitoring
continue to increase. The installation of new controls and protection will also
provide increased visibility into the systems allowing better remote monitoring
and troubleshooting. If we do not invest and take care of these two units, they
will continue to be unreliable and fall further behind in technology that other
upgraded units operate with.
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 Pape 10 of 13
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 199 of 271

DocuSign Envelope ID: 17B5DABE-A93D-407E-8C08-B089A3553C30
Nine Mile 3 & 4 Controls Upgrade
Alternative 1: Replace Unit Control, Monitoring, and Protection Systems
Only, Do Not Replacing Flooring; $7.25M
This Alternative would replace unit control, monitoring, and protection systems.
This alternative would not upgrade the switchgear floor. This alternative is
currently in engineering evaluation to determine if the new controls equipment
can be functionally located somewhere other than the switchgear floor. There is
still the potential that this alternative could be feasible, thus saving —$1 M in total
project cost, but will not be determined until preliminary design is complete.
Alternative 2: Do Nothing; $0 in Capital
This alternative would leave the equipment as-is. Replacing the equipment is
critical due to the extensive age of the various systems and the difficulty to
upgrade only a portion of the technology as new technology is incompatible with
the obsolete technology
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
A successful investment to upgrade the Nine Mile 3 & 4 Control Monitoring, and
Protection systems would be measurable by Future Maintenance Assessments
that would show an improved condition and reduction in risk,
2.7 Include a timeline of when this work is scheduled to commence and
complete, if known.
The business case will include 2 projects, one for Unit 3 and another for Unit 4.
Design and Construction for each project take place over 3 years with the design
of unit 4 starting during construction of unit 3. Each project with be transferred
to plant at the completion of construction
2022 2023 2024 2025
$500,000 S3,250,000 $3,000,000 51.500,000
nit 3
. .
.
❑xTimeline is Known
• Start Date: 2023
• End Date: 2025
❑Timeline is Unknown
Business Case Justification Narrative Template Version: January 2023 Page 11 of 13
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 200 of 271

DocuSign Envelope ID: 17B5DABE-A93D-407E-8C08-B089A3553C30
Nine Mile 3 & 4 Controls Upgrade
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
The steering committee will minimally consist of the Controls Engineering
Manager, the Electrical Engineering Manager, The Mechanical Engineering
Manager, The protection Engineering Manager, the Protection Control Meter
Technician Foreman, and the Spokane River Plant and Operations 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 Pape 12 of 13
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 201 of 271

DocuSign Envelope ID: 17B5DABE-A93D-407E-8C08-B089A3553C30
Nine Mile 3 & 4 Controls Upgrade
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Nine Mile Unit 3 & 4 Control
Upgrade business case the and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.
Signed by:
Signature: FZa -rn,,), Date: Au9-09-2023 1 7:30 AM PDT
Print Name: Michael Truex
Title: GPSS Manager of Project
Management
Role: Business Case Owner
DocuSigned by:
Signature: a(q'is a(q-1aA11J -v' Date: Au9-26-2023 I 1:30 AM PDT
FA27RARA7fi7Fdfi7
Print Name: Alexis Alexander
Title: Director, GPSS
Role: Business Case Sponsor
Signature: NA Date:
Print Name: NA; Michael Truex is currently on
the steering committee
Title: NA
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: January 2023 Pape 13 of 13
xhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 202 of 271

Docusign Envelope ID:C32BD67F-447C-4C88-9DD3-94747252439A
Noxon Rapids Gantry Crane Modernization
EXECUTIVE SUMMARY
PROJECT NEED: Noxon Rapids construction was completed in 1959. Noxon can
produce over 500 MW of peaking power. A key component of the facility is the gantry
crane. The gantry crane is utilized to perform required maintenance and upgrades to the
turbine/generators. The crane's maximum lifting capacity is 325 tons. The gantry crane
is now over 60 years old. Parts are difficult to source, and the crane does not conform
to current safety standards. Past failures with the crane have caused delays in projects.
A functional crane is equipment critical to completing future planned work; without a
functional crane, work cannot be performed. This could negatively affect generator
availability which can have a negative impact on EIM performance.
RECOMMENDED SOLUTION: The recommended solution is to replace the existing
gantry crane in-kind
ALTERNATIVES CONSIDERED:
• Alternative 1: Rehabilitate the existing crane
• Alternative 2: Do Nothing
COST OF RECOMMENDED SOLUTION: $19,493,803
ADDITIONAL INFO: Delays in work caused by degrading asset condition can be costly
for Avista's customers. It is time to replace the Noxon gantry crane. If this project is
delayed, continued operational costs will be experienced, and any safety or functional
issues will not be mitigated into the future. Past failures with the crane have caused
delays in projects.
VERSION HISTORY
Version Author Description Date Notes
1.0 Alan Lackner Original Business Case 7/8/2020 Crane Modernization
Transfer to new BCJN No substantive changes/edits have
2.0 Jessica Bean Template 01/06/2023 been made to the business case
through this transfer
3.0 Wendy Iris Updates to BCJN 03/21/2023 Worked with Alan Lackner to
update Business Case Justification
4.0 Don Sherrill Update for annual 05/06/24
review/a proval
Business Case Justification Narrative Template Version: January 2023 Page 1 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 203 of 271

Docusign Envelope ID:C32BD67F-447C-4C88-9DD3-94747252439A
Noxon Rapids Gantry Crane Modernization
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT($)
2023 $ 493,803
2024 $ 2,000,000 $ 0
2025 $ 13,000,000 $ 0
2026 $ 4,000,000 $ 19,493,803
2027 $ 0 $ 0
Project Life Span 3 years
Requesting Organization/Department GPSS
Business Case Owner Sponsor Jeff Vogel David Howell
Sponsor Organization/Department GPSS
Phase Execution
Category Project
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's
site see link.
Investment Drivers
Business Case Justification Narrative Template Version: January 2023 Page 2 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 204 of 271

Docusign Envelope ID:C32BD67F-447C-4C88-9DD3-94747252439A
Noxon Rapids Gantry Crane Modernization
1. BUSINESS PROBLEM- This section must provide the overall business case
information conveying the benefit to the customer, what the project will do and current
problem statement.
1.1 What is the current or potential problem that is being addressed?
The problem being addressed is the Noxon gantry crane reliability, parts
availability and safety. The Noxon crane has failed and caused significant
delays in past projects. The crane controls and mechanical systems are
becoming antiquated technology, unreliable, and it does not meet current crane
safety standards. Parts, if available, are difficult to procure.
1.2 Discuss the major drivers of the business case
The driver for this business case is asset condition. In the past 60 years
technology and safety standards for cranes have changed significantly. The
reliability of the crane is becoming questionable during required maintenance
activities. If a major failure occurs during required maintenance this could force
a Noxon machine to be out for a significant time frame, but even worse could
cause catastrophic failure. This has the potential to have a direct impact on
customer rates and employee safety.
1.3 Identify why this work is needed now and what risks there are if not
approved or if deferred or risks being mitigated by the request.
A functional crane is equipment critical to completing future work. Noxon Rapids
HED has a maintenance plan that requires a reliable and safe crane; without a
functional crane, this work cannot be performed. Reduced generator availability
will have a negative impact on EIM performance.
Noxon has several significant projects planned in the coming years. Without a
reliable and safe gantry crane this work will not be able to be accomplished and
generator availability will suffer.
The metrics supporting this modernization are personal safety, equipment
safety and generator availability. Without a safe reliable gantry crane all of these
have the potential to be negatively impacted.
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
Noxon Rapids affordably supports the power needs of our company and our
customers. By taking care of this plant we support our mission of improving our
customer's lives through innovative energy solutions which includes carbon-free
hydroelectric generation. By executing this project, we ensure that Noxon
Rapids is performing at a high level and serving our customers with affordable
and reliable energy.
Business Case Justification Narrative Template Version: January 2023 Page 3 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 205 of 271

Docusign Envelope ID:C32BD67F-447C-4C88-9DD3-94747252439A
Noxon Rapids Gantry Crane Modernization
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.'
• Parts are difficult to source, and it does not conform to current safety
standards.
• The current condition of the crane and its subsequent impact on personal
safety and generation availability are the primary drivers.
' 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
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 206 of 271

Docusign Envelope ID:C32BD67F-447C-4C88-9DD3-94747252439A
Noxon Rapids Gantry Crane Modernization
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: The recommended solution is to replace the existing
gantry crane. This is a preferred alternative over rehabilitating the crane.
Replacement of the existing equipment can give Avista the reliability and
functionality needed.
In Scope: 325 Ton Gantry Crane Replacement
Out of Scope: Complete rail replacement/rehab
Assumptions: The current rail system can accommodate the loading needed for
the new equipment; Plant manager would like to adjust the configuration to
better access Unit 5 and auxillary equipment near unit 5.
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
• Lessons learned for the Cabinet gantry crane project have impacted the
decision for crane modernization.
• CARS (Capital Additions and Retirement) form which documents added and
removed assets associated with Avista's facilities. This document helps
Avista maintain accurate continuing property records.
• Class 5 Estimate
• The 2018 Hydro Generation Condition & Risk Assessments, is referred to as
the "2018 Assessment." Early 2018 GPSS-Hydro department undertook an
initiative to revamp their maintenance programs. This included the 2018
Assessment, which was conducted in the hydro plants and incorporated
both Risk Assessments and Condition Assessments. Teams consisting of
representatives from the Mechanic, PCM Tech, and Electric Shops, as well
as Spokane River Hydro, Clark Fork River Hydro, and Maximo teams were
formed and tasked with performing a condition and risk based assessment
for assets in all of Avista's hydro facilities. Additional details may be found
in the "2018 Hydro Asset Management Program Directory". The full
reference is provided below:
Business Case Justification Narrative Template Version: January 2023 Page 5 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 207 of 271

Docusign Envelope ID:C32BD67F-447C-4C88-9DD3-94747252439A
Noxon Rapids Gantry Crane Modernization
The Condition Assessments were based on the CEATI hydroAMP 2.0 guide.
The database developed during the 2018 assessment has been used to
create business information tools to identify and analyze equipment
strategies to be used by GPSS for making business decisions.
The purpose of the Risk Assessment was to identify the environmental,
financial, and safety risks associated with each asset and what possible
consequences might result from an asset failure. Consequences were
framed within the Avista Business Risk Matrix. Financial risks might include
lost generation during an outage. Probabilities were then estimated as an
answer to the following question: Given an asset failure, what is the
probability that a particular, potential consequence will actually occur? As
an aid to this process, probabilities were selected from a menu of specified
probability levels. Results of the Risk Assessments have been used to
estimate asset risk costs. Risk cost is the product of the Failure Rate,
Potential Consequence of failure. This risk cost is a probable dollar value
associated with Avista's exposure risk of each asset.
The results of the 2018 Assessment have been used to develop Asset
Management Plans (AMPs) and a Risk Based Investment Planning (RBIP)
tool. AMPs have been developed for a number of the asset classes, such
as the generators, turbine runners, GSUs, trash rakes, etc. The AMPs outline
capital and maintenance strategies. A primary purpose of the RBIP tool is
to bring a risk-based perspective to the capital budget process.
Reference - Avista Utilities, "2018 Hydro Asset Management Program
Directory", Avista Utilities GPSS Dept., March 15, 2019
• 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
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 6 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 208 of 271

Docusign Envelope ID:C32BD67F-447C-4C88-9DD3-94747252439A
Noxon Rapids Gantry Crane Modernization
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 associate with the assets that fail that year.
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 NA $0 $0 $0 $0 $0
O&M NA $0 $0 $0 $0 $0
Estimated direct savings, inclduing hard cost savings, has not been quantified.
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 NA $0 $0 $0 $0 $0
O&M NA $0 $0 $0 $0 $0
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 7 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 209 of 271

Docusign Envelope ID:C32BD67F-447C-4C88-9DD3-94747252439A
Noxon Rapids Gantry Crane Modernization
Estimated indirect savings and/or productivity gains and associated benefits have not
been quantified at this time; however, as applicable, please see the referenced Risk
Based Investment report (see Section 2.2) for additional information.
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: Rehabilitate the existing crane.
Alternative 1: Do Nothing; $0 Capital Cost
This alternative would continue to maintain the crane under O&M. This
alternative was not selected because repair parts can be hard to source and the
fact that the current crane controls and mechanical systems not meeting current
safety standards.
Alternative 2: Rehabilitate the existing crane; $10M
This alternative is to rehabilitate the current crane. This alternative was not
selected because the lessons learned from the Cabinet Gorge Crane
rehabilitation project. The crane rehabilitation does not allow for increased
functionality and changes in configuration; more specifically reaching
components of Noxon #5. There is also a high dollar maintenance cost
associated with rehabilitation to remove lead based paint, re-paint, and
structural integrity repairs. The risk to Avista, if this alternative is selected, is
that more money would be spent than likely needed.
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 ability of the crane to be utilized during capital and maintenance activities
2.7 Include a timeline of when this work is scheduled to commence and
complete, if known.
❑x Timeline is Known:
• Start Date: 2023
• End Date: 2026
❑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
Business Case Justification Narrative Template Version: January 2023 Page 8 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 210 of 271

Docusign Envelope ID:C32BD67F-447C-4C88-9DD3-94747252439A
Noxon Rapids Gantry Crane Modernization
Technical Team for input on Crane Performance:
• Dennis France; Larry Beeler; Doug Hutfles; Scott Renz; Gary Douglas;
Jerry Heglie; Sean Kelley
Steering Committee
• David Howell; Alan Lackner; Greg Wiggins; PJ Henscheid
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
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 211 of 271

Docusign Envelope ID:C32BD67F-447C-4C88-9DD3-94747252439A
Noxon Rapids Gantry Crane Modernization
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Noxon Rapids Gantry Crane
Modernization business case and agree with the approach it presents. Significant
changes to this will be coordinated with and approved by the undersigned or their
designated representatives.
Signed by:
Signature: JdF ,�J Date: Sep-17-2024 1 12:45 PM PDT
Print Name: -e-ff
,QSF6Y61F7498 .
Title: Sr Mgr,
Maint and Const
Role: Business Case Owner
Signed by:
Signature: Foaw,j t�dWtg Date: Sep-17-2024 1 12:46 PM PDT
8A3F,d5 fl Owe avl rI
Print Name: D
Title: Director, GPSS
Role: Business Case Sponsor
Signature: NA Date:
Print Name: NA
Title: NA
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: January 2023 Page 10 of 10
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 212 of 271

Docusign Envelope ID: DCCF3F6E-0053-4B57-BE6E-E990773040FD
Noxon Rapids Unit 5 Turbine Runner Replacement
EXECUTIVE SUMMARY
PROJECT NEED: There is extensive maintenance done on this asset (Unit 5 Turbine
Runner) yearly. It is the original runner, at the end of its useful life and we don't have
enough outage time to complete all the repairs needed.
RECOMMENDED SOLUTION: Conduct appropriate assessments/inspection and
develop appropriate engineering solution in 2025. With this solution, GPSS will follow
later with funding requests for project plan to replace the runner.
ALTERNATIVES CONSIDERED:
• Alternative 1: Continue with annual maintenance
• Alternative 2: Replace with in-kind turbine with no studies or analysis
COST OF RECOMMENDED SOLUTION: $500,000 (DESIGN/PLANNING)
ADDITIONAL INFO: If this project is not approved, then we will continue to maintain the
runner as best we can with the constraint of balancing repair time needed with outage
window available.
Business Case Justification Narrative Template Version: January 2023 Page 1 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 213 of 271

Docusign Envelope ID: DCCF3F6E-0053-4B57-BE6E-E990773040FD
Noxon Rapids Unit 5 Turbine Runner Replacement
VERSION HISTORY
Version Author Description Date Notes
1.0 Glen Farmer Initial Version 5/27/2022 Turbine only.
2.0 Glen Farmer Updated with Business Case 8/24/2022 New format.
template 4/12/22.
3.0 Glen Farmer Newest Business Case 5/10/2023 Supply Chain Delays on
Template. Reviewed and all orders. Added a year
updated. to order.
4.0 Don Sherrill Update for annual 09/03/2024
review/approval
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2024 $ 0 $ 0
2025 $ 500,000 $ 0
2026 $ 0 $ 0
2027 $ 0 $ 0
Project Life Span 4 years
Requesting Organization/Department GPSS
Business Case Owner I Sponsor PJ Henscheid David Howell
Sponsor Organization/Department GPSS
Phase Initiation
Category Project
Driver Asset Condition
Definitions for the Category and Driver can be found on the Business Case Review Team Team's
site see link.
Investment Drivers
Business Case Justification Narrative Template Version: January 2023 Page 2 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 214 of 271

Docusign Envelope ID: DCCF3F6E-0053-4B57-BE6E-E990773040FD
Noxon Rapids Unit 5 Turbine Runner Replacement
1. BUSINESS PROBLEM- This section must provide the overall business case
information conveying the benefit to the customer, what the project will do and current
problem statement.
1.1 What is the current or potential problem that is being addressed?
The problem being addressed is the replacement of the Turbine Runner. The
Turbine was installed and commissioned in 1977. We have been doing
extensive welding on the turbine for over 25 years. It is to the point now where
we don't have enough outage time to complete all the repairs needed. The
cavitation on the underside of the blades continues to erode the turbine. We
replaced the other 4 turbines back in the early 2000's time frame with different
material that appears to hold up better.
1.2 Discuss the major drivers of the business case
1.3 Asset Condition: We continue to maintain the turbine by welding in new material
that is lost. This is normally every year during the yearly outage. Even though
the metal is replaced the asset condition is still low after maintenance because
it doesn't last like original.
1.4 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.
1.5 Currently during this Units yearly outage there is a crew dedicated to welding on
the turbine runner. We have tried different ways to cut out the bad parts and
weld in the new parts. It all takes time, and we use all the outage window for
repairs. If this is not approved, we will continue to take the yearly outage and
dedicate a crew to the turbine welding.
1.6 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 turbine runner contributes to the Safe and responsible design, construction,
operation, and maintenance of Avista's generation fleet. A new turbine runner
will provide increased efficiency of the turbine which can turn into power savings
for our customers that can offset capital costs.
1.7 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.'
We have pictures of areas on each blade and some reports from outside
contractors evaluating the blade edges.
' 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 3 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 215 of 271

Docusign Envelope ID: DCCF3F6E-0053-4B57-BE6E-E990773040FD
Noxon Rapids Unit 5 Turbine Runner Replacement
2. PROPOSAL AND RECOMMENDED SOLUTION- Describe the proposed
solution to the business problem identified above and why this is the best and/or least cost
alternative (e.g., cost benefit analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Recommended Solution: The recommended solution is to replace the turbine
runner.
In Scope: Analysis the existing blow down system and or flow into the turbines
through the wicket gates (shaft, runner, draft tube, spiral case, wicket gates,
stay veins, bearing systems) design and specs needed for turbine performance
(cavitation, efficiency, fish studies, and operating range); turbine model (from
penstock through discharge) built and tested build a runner in a
manufacturing/test facility (Japan, Switzerland, Germany); shipping turbine to
Noxon, and install by AVA crews with assistance from turbine supplier. AVA
crews will also install spiral case, wicket gates and stay veins upgrades, as
required, based on turbine design. Flow monitoring devices. Performance
testing. Wear sleeve. Packing box system. Removals include existing turbine
runner and runner shaft, shaft sleeve replaced. Full details on
removals/replacements can be found in the Hydro Production RUC/CARS
document, attached.
Out of Scope: Structural modifications to the penstocks. Generator auxiliary
equipment and generator upgrades. Everything physically above the thrust
bearing is out of scope. Structural modifications to the plant to support a new
turbine. Headgates.
Assumptions: This scope shouldn't match Unit 1-4 design because it sees
higher flows and the spiral case and turbine diameter are different. Tobisha has
some model parts created as part of Unit 1-4 modeling they previously
performed. The scope documents for Units 1-4 can help inform Unit 5's.
Operations and Power Supply would request a different type of turbine than
Units 1-4.
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
• Maximo work orders
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 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 216 of 271

Docusign Envelope ID: DCCF3F6E-0053-4B57-BE6E-E990773040FD
Noxon Rapids Unit 5 Turbine Runner Replacement
• GPSS has pictures of areas on each blade and some reports from outside
contractors evaluating the blade edges.
• The capital request was developed from budgetary quotes from manufacture
and compared to previous projects of similar type.
• GPSS Ranking Matrix Template & Ranking Matrix Scores (if applicable).
Template: Each GPSS project, if applicable, has a unique score that equals
100 or less. The higher the score, the more critical and/or urgent the project
is. The score is the non-denominational sum of each category weight
multiplied by the unique category score. Ranking Matrix Score: This
document shows the calculated score for an individual project.
• CARS (Capital Additions and Retirements) Form which documents added
and removed assests associated with Avista's facilities. This document helps
avista maintain accurate continuing property records.
• The 2018 Hydro Generation Condition & Risk Assessments, is referred to as
the "2018 Assessment." Early 2018 GPSS-Hydro department undertook an
initiative to revamp their maintenance programs. This included the 2018
Assessment, which was conducted in the hydro plants and incorporated
both Risk Assessments and Condition Assessments. Teams consisting of
representatives from the Mechanic, PCM Tech, and Electric Shops, as well
as Spokane River Hydro, Clark Fork River Hydro, and Maximo teams were
formed and tasked with performing a condition and risk based assessment
for assets in all of Avista's hydro facilities. Additional details may be found
in the "2018 Hydro Asset Management Program Directory". The full
reference is provided below:
The Condition Assessments were based on the CEATI hydroAMP 2.0 guide.
The database developed during the 2018 assessment has been used to
create business information tools to identify and analyze equipment
strategies to be used by GPSS for making business decisions.
The purpose of the Risk Assessment was to identify the environmental,
financial, and safety risks associated with each asset and what possible
consequences might result from an asset failure. Consequences were
framed within the Avista Business Risk Matrix. Financial risks might include
lost generation during an outage. Probabilities were then estimated as an
answer to the following question: Given an asset failure, what is the
probability that a particular, potential consequence will actually occur? As
an aid to this process, probabilities were selected from a menu of specified
probability levels. Results of the Risk Assessments have been used to
estimate asset risk costs. Risk cost is the product of the Failure Rate,
Potential Consequence of failure. This risk cost is a probable dollar value
associated with Avista's exposure risk of each asset.
Business Case Justification Narrative Template Version: January 2023 Page 5 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 217 of 271

Docusign Envelope ID: DCCF3F6E-0053-4B57-BE6E-E990773040FD
Noxon Rapids Unit 5 Turbine Runner Replacement
The results of the 2018 Assessment have been used to develop Asset
Management Plans (AMPs) and a Risk Based Investment Planning (RBIP)
tool. AMPs have been developed for a number of the asset classes, such
as the generators, turbine runners, GSUs, trash rakes, etc. The AMPs outline
capital and maintenance strategies. A primary purpose of the RBIP tool is
to bring a risk-based perspective to the capital budget process.
Reference - Avista Utilities, "2018 Hydro Asset Management Program
Directory", Avista Utilities GPSS Dept., March 15, 2019
• 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 associate with the assets that fail that year.
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 NA $0 $0 $0 $0 $0
O&M Reduction in O&M $100,0000 $100000 $100000 $100000 $100000
s Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: January 2023 Page 6 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 218 of 271

Docusign Envelope ID: DCCF3F6E-0053-4B57-BE6E-E990773040FD
Noxon Rapids Unit 5 Turbine Runner Replacement
It is estimated that the Maintenance offsets will be about $100,000 per year
during the beginning of the maintenance cycle.
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 NA $0 $0 $0 $0 $0
O&M NA $0 $0 $0 $0 $0
Estimated indirect savings and/or productivity gains and associated benefits
have not been quantified at this time; however, as applicable, please see the
referenced Risk Based Investment report (see Section 2.2) for additional
information.
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: Conduct assessment and engineering to
inform cost estimate and project plan to follow.
Alternative 1: Continue with annual maintenance; $0 Capital Cost
This is what we are currently doing. It can continue but the window that we must
do the work is shrinking. We are driven be trying to keep the Units available.
We repair the biggest areas of erosion and leave the rest.
Alternative 2: Replace with in-kind turbine with no studies or analysis.;
$850,000
This alternative would replace the turbine runner without performing an
engineering analysis. The risk of selecting this alternative is that too much or
too little equipment could be replaced, either spending more money than is
needed to be spent or spending more money to fix problems not fixed during
the first try. Engineering analysis is a prudent step for any large scale project
and not having an engineering analysis performed would not be an appropriate
step for a project of this size
a Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: January 2023 Page 7 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 219 of 271

Docusign Envelope ID: DCCF3F6E-0053-4B57-BE6E-E990773040FD
Noxon Rapids Unit 5 Turbine Runner Replacement
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).
Avista replaced the other 4 turbine runners at NR with new runners, and they
are holding up very well. The current plan would be to use this same design and
material for the Unit 5 runner; assessment and engineering will determine if this
is appropriate.
2.7 Include a timeline of when this work is scheduled to commence and
complete, if known.
❑x Timeline is Known
• Start Date: 1/1/2027
• End Date: 5/1/2030
❑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
A steering committee is anticipated to be created for this project; candidates for
the steering committee could include the following: the Noxon Rapids plant
manager; GPSS Civil and Mechanical Engineering Manager; Power Supply
representative
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 member.
Business Case Justification Narrative Template Version: January 2023 Page 8 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 220 of 271

Docusign Envelope ID: DCCF3F6E-0053-4B57-BE6E-E990773040FD
Noxon Rapids Unit 5 Turbine Runner Replacement
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Noxon Rapids Unit 5 Turbine
Runner Replacement 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.
Signed by:
Signature: H hJA S"i Date: sep-16-2024 110:12 AM PDT
Print Name: .� enscWe21d
Title: Engineering Mgr, Mech/Civil
Role: Business Case Owner
Signed by:
Signature: Fv"J (�bWa Date: sep-16-2024 110:15 AM PDT
Print Name: 8A3F�s oweil
Davl
Title: Director, GPSS
Role: Business Case Sponsor
Signature: NA Date:
Print Name: NA; no committees have been
stood up at this time.
Title: NA
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: January 2023 Page 9 of 9
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 221 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Operational Safety and Compliance
EXECUTIVE SUMMARY
The diverse Avista-owned generating facilities include Hydro, Biomass, and Natural Gas fuel power
producing resources. The assets range in age, condition,output, and configuration. Together these facilities
bring a balanced approach to meeting our electric customers' needs throughout the year. The 13 Avista-
owned generating facilities have a total capacity of nearly 1.6GW of electricity. These facilities include 8
hydroelectric dams located on the Clark Fork and Spokane Rivers, a stand-alone biomass facility located in
Kettle Falls, Washington, and four natural gas generating plants in Idaho, Washington, and Oregon.
This program will support the various compliance and safety related projects within all the Avista-owned
generating facilities. The projects are intended to address compliance and/or safety related matters at the
facilities. Projects will be level 0 to level 1 in project complexity and coordination. This program is critical in
supporting facility compliance with agencies including NERC, FERC, WECC and OSHA. Identified projects
will be governed by the Plant Manager, Operations Engineering Manager, and Senior Operations &
Maintenance Manager.
The GPSS Operations team will coordinate and manage a 5-year plan of identified projects to sustain the
safe and reliable operations of the Avista-owned generation assets. The annual budget will vary and depends
on evaluation of asset condition to meet the mandate requirements identified.
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
1.0 Alexis Alexander Initial draft of original business case
1.1 Greg Wiggins Edits to narrative reflecting ongoing work in Safety and Compliance program 8/28/2024
BCRT BCRT Team Has been reviewed by BCRT and meets necessary requirements
Member
Business Case Justification Narrative Template Version: February 2023 Page 1 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 222 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Operational Safety and Compliance
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2025 2,000,000 2,000,000
2026 2,500,000 2,500,000
2027 3,000,000 3,000,000
2028 8,000,000 8,000,000
2029 8,000,000 8,000,000
Project Life Span 5years
Requesting Organization/Department A07/Generation Production Substation Support
Business Case Owner I Sponsor Greg Wiggins/David Howell
Sponsor Organization/Department David Howell/GPSS
Phase Execution
Category Program
Driver Mandatory&Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information
conveying the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
This program will support the compliance and safety related projects within all the Avista-owned
generating facilities. The projects are necessary to ensure employee safety and/or mandated to meet
compliance and safety standards at the facilities. The projects will be planned and emergent work.
The driver will primarily be mandatory and compliance but may vary between individual projects.
Business Case Justification Narrative Template Version: February 2023 Page 2 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 223 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Operational Safety and Compliance
1.2 Discuss the major drivers of the business case.
Mandatory and Compliance— Investments are driven by compliance with laws, rules, and contractual
obligations.
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 Avista-owned hydro and thermal generating facilities have a wide range of regulated requirements
to ensure operational compliance is met. This program will support the ongoing compliance and safety
related projects spread across the 13 facilities. Examples of these projects include: Noxon Spillgate
Remediation, Kettle Falls Landfill enhancements, and the Long Lake Stability project. Projects stem
from the FERC Dam Safety Program, the Spokane River and Clark Fork River License, and many
other regulating agencies, stakeholders, and constituents.
Without this funding source the facilities will be at risk of operating out of compliance with Federal,
State, and Local laws and regulations.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
This program aligns with Avista's core business by delivering energy safely, responsibly, and
affordably to our customers. This program will ensure all Avista-owned generating facilities are
operating in compliance with environmental and safety regulations and laws. Through prudent
investments in plant operations, we can ensure the generating facilities are reliable and available to
respond to the energy market of the future. In addition, many of the investments improve the
operational safety of our employees, enabling them to achieve their optimal performance.
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.'
This program will support 13 Avista-owned generating facilities and will fund several projects annually.
These projects will vary in size and scope and will be governed by the GPSS Operations team including
the Plant Managers, Operations Engineering Manager, and the Senior Operations and Maintenance
Manager. Projects will be analyzed, planned, and executed by one group aligning investment
decisions for optimal operational performance. Operations and Maintenance Engineering team will
work together to create supporting documentation in alignment with the PMO process. Larger projects
will be further vetted through the department Generation Round Table project approval process for
justifying the investment for each project, utilizing existing asset management analysis and
maintenance records.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 224 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Operational Safety and Compliance
2. PROPOSAL AND RECOMMENDED SOLUTION -Describe the proposed solution to
the business problem identified above and why this is the best and/or least cost alternative (e.g., cost benefit
analysis).
2.1 Please summarize the proposed solution and how it helps to solve the
business problem identified above.
Changes in regulatory and compliance standards continue to create challenges to operations. As a
result, the investments necessary to sustain the Avista-owned facilities has taken on a new model.
This program,accompanied by an enhanced resource strategy, including the development of plant and
regional project teams, have enable better coordinated project delivery for the respective plants. In
addition, a centralized list of projects across Avista's entire generation fleet will be maintained and
prioritized by the Senior Operations and Maintenance Manager. Project and resources will be
managed through OPC and the Project Delivery team.
Past asset management, maintenance, and investment strategies have changed to meet the new
demands. The new resource strategy along with the business case program structure will support
improved project planning, execution, and the adaptability needed to respond to unplanned events.
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
Projects will follow the GPSS risk based investment planning methodology for life cycle analysis, cost
benefit and risk reduction. This work will be done by the GPSS Operations Engineering Team. The major
component projects will have an average lifecycle look with current asset condition. The first year Risk
Cost Reduction will be projected which is the difference between the current risk costs, based on failure
rates, and the risk costs of a new assets. This is analogous to; if Avista were to pay an "insurance
premium" to pay for probable consequences of failure.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 225 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Operational Safety and Compliance
2.3 Summarize in the table and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
0&M $ $ $ $ $
DIRECT offsets will be determined for each project, when applicable. This information will be
calculated and documented in each project file.
2.4 Summarize in the table, and describe below the INDIRECT offsets'(Capital
and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
0&M $ $ $ $ $
INDIRECT offsets will be determined for each project, when applicable. This information will be
calculated and documented in each project file.
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: N/A
Alternative 2: N/A
Alternative 3: N/A
Where applicable, each project will document alternatives that were considered during the research
and planning phase. The alternatives for projects will be determined such as direct replacement,
manufactures recommendations and industrial standards.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 226 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Operational Safety and Compliance
2.6 Identify any metrics that can be used to monitor or demonstrate how the
investment delivered on remedying the identified problem (i.e., how will
success be measured).
Projects will be tracked and managed in Maximo asset management program. Historical asset data
may be used to compare the project benefits. When available, the data will be used to support the
investment decision.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Projects will commence and complete throughout the year over the various plant locations. This
process will allow"shovel ready" projects to be quickly put into the queue and executed when funds
and resources are available.
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.
Projects will be classified into level 0 and level 1 based on complexity and required coordination.
Level 0 projects will utilize the GPSS Operations team consisting of the Plant Manager, Operations
Engineering Manager, and Senior Operations and Maintenance Manager for project governance.
Projects will be ranked using the GPSS project ranking matrix which focus on various categories
including; Personnel and Public Safety, Environmental, Risk of Equipment Failure, Regulatory
Mandate, Maintenance Issues, Customer Value, Operating Efficiencies, Operating Costs, and
Obsolete Equipment. Level 0 projects are smaller in scope, generally less than $1 M,and completed
within the calendar year.
Level 1 projects, are larger in scope, schedule, and budget, costing between $1 M-$10M and are
completed over the course of two years. Level 1 projects will receive a higher level of scrutiny,
utilizing the GPSS strategic asset management plan to guide capital replacement strategies. Where
data is available, the GPSS risk based investment planning tool will be used to rank asset condition,
criticality, and risk costs for level 1 projects.
A dedicated GPSS Program Manager will be responsible for monitoring the program and the
associated projects to ensure expected budget and transfer to plant are on target.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 227 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Operational Safety and Compliance
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the GPSS_Operational Sustainment
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.
Signed by:
Signature: Fuji �S Date: Sep-17-2024 I 4:23 AM PDT
Print Name: Wi ig""..
Title: Manager, GPSS O&M
Role: Business Case Owner
Signed by:
Signature: rvawk Rbilvat Date: Sep-17-2024 I 12:37 PM PDT
Print Name: av-f&HbVW'S
Title: Director, GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 7 of 7
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 228 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Operational Sustainment
EXECUTIVE SUMMARY
The diverse Avista-owned generating facilities include Hydro, Biomass, and Natural Gas fuel power
producing resources. The assets range in age, condition, output, and configuration. Together these facilities
bring a balanced approach to meeting our electric customers needs throughout the year. The 13 Avista-
owned generating facilities have a total capacity of nearly 1.6GW of electricity. These facilities include 8
hydroelectric dams located on the Clark Fork and Spokane Rivers, a stand-alone biomass facility located in
Kettle Falls, Washington, and four natural gas generating plants spread between in Idaho, Washington, and
Oregon.
This program will support the operational sustainability of the Avista-owned generating facilities. These
projects primarily include moderate investments in system retrofits or replacements necessary to maintain
the operation of the facilities. Projects will be level 0 to level 1 in project complexity and coordination. This
program is critical in continuing to support asset management program replacement schedules until larger
operational enhancement program investments are made. Identified projects will be governed by the Plant
Manager, Operations Engineering Manager, and Senior Operations & Maintenance Manager.
The GPSS Operations team will coordinate and manage a 5 year plan of identified projects needed to sustain
the safe and reliable operations of the Avista-owned generation assets. The annual budget will vary and
depends on evaluation of asset condition.
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
1.0 Alexis Alexander Initial draft of original business case
2.0 Greg Wiggins Edits to narrative reflecting ongoing work in Sustainment program 8/28/2024
Business Case Justification Narrative Template Version: February 2023 Page 1 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 229 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Operational Sustainment
GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
($) PLANT ($)
2025 10,300,000 10,300,000
2026 13,300,000 13,300,000
2027 17,000,000 17,000,000
2028 17,000,000 17,000,000
2029 17,000,000 17,000,000
Project Life Span 5 years
Requesting Organization/Department A07/Generation Production Substation Support
Business Case Owner I Sponsor Greg Wiggins/David Howell
Sponsor Organization/Department David Howell/GPSS
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
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?
This program will support the operational sustainability of the Avista-owned generating facilities.
These projects are moderate investments, retrofits or system improvements intended to maintain the
operations of the facilities. Projects within this program are designed to maintain continued operations
of the hydro and thermal generating facilities. The projects will be planned and emergent work. The
driver will primarily be performance and capacity but may vary between individual projects.
Business Case Justification Narrative Template Version: February 2023 Page 2 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 230 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Operational Sustainment
1.2 Discuss the major drivers of the business case.
Major drivers include Performance and Capacity — Investments into hydro and thermal generation to
maintain a level of unit availability and to achieve efficiency output objectives.
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 Avista-owned hydro and thermal generating facilities have a wide range of aging equipment.
Continual investment will be required for the facilities to meet the demands of future energy markets.
This program will support the ongoing replacement and upgrade projects spread across the 13
facilities. Examples of these projects include: Emergency Standby Generator Replacement, Plant
HVAC Replacement, and Unit Governor Replacement projects. The dynamic performance of our
assets driven by the evolving energy markets is leading to increased unplanned failures. The
proposed business case allows for proactive,and when necessary, reactive measures to maintain unit
availably, ultimately contributing to energy costs savings for our customers.
Without this funding source the facilities will lack a minimum project funding to sustain safe, reliable,
and affordable operations.
1.4 Discuss how the proposed investment, whether project or program, aligns
with the strategic vision, goals, objectives and mission statement of the
organization. See link.
Avista Strategic Goals
This program aligns with Avista's core business by delivering energy safely, responsibly, and
affordably to our customers. Through prudent investments in plant operations, we can ensure the
generating facilities are reliable and available to respond to the energy market of the future.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 231 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Operational Sustainment
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.'
This program will support 13 Avista-owned generating facilities and will fund several projects
annually. These projects will vary in size and scope and will be governed by the GPSS Operations
team including the Plant Managers, Operations Engineering Manager, and the Senior Operations and
Maintenance Manager. Projects will be analyzed, planned, and executed by one group aligning
investment decisions for optimal operational performance. Operations and Maintenance Engineering
team will work together to create supporting documentation in alignment with the PMO process.
Larger projects will be further vetted through the department Generation Round Table project
approval process for justifying the investment for each project, utilizing existing asset management
analysis and maintenance records.
Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 232 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Operational Sustainment
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 combination of renewable integration, unprecedented weather patterns, and new energy policy,
has changed Avista's resource mix. As a result, the investments necessary to sustain the operation
and maintain our facilities has taken on a new forecasting profile.
This program,accompanied by an enhanced resource strategy, including the development of plant and
regional project teams, will enable better coordinated project delivery for the respective plants. In
addition, a centralized list of projects across Avista's entire generation fleet will be maintained and
prioritized. This is essential, as we modify how we dispatch our fleet, balancing affordability, and
reliability in the rapidly evolving energy markets.
Past asset management, maintenance, and investment strategies have changed to meet the new
demands. The new resource strategy along with the business case program structure will support
improved project planning, execution, and the adaptability needed to respond to unplanned events.
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
Projects will follow the GPSS risk-based investment planning methodology for life cycle analysis, cost
benefit and risk reduction. This work will be done by the GPSS Operations Engineering Team. The
major component projects will have an average lifecycle look with current asset condition. The first year
Risk Cost Reduction will be projected which is the difference between the current risk costs, based on
failure rates, and the risk costs of a new assets. This is analogous to; if Avista were to pay an
"insurance premium"to pay for probable consequences of failure.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 233 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Operational Sustainment
2.3 Summarize in the table, and describe below the DIRECT offsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
0&M $ $ $ $ $
DIRECT offsets will be determined for each project where applicable. This information will be
calculated and documented in each project file.
2.4 Summarize in the table, and describe below the INDIRECT offsets'(Capital
and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
0&M $ $ $ $ $
INDIRECT offsets will be determined for each project, when applicable. This information will be
calculated and documented in each project file.
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: N/A
Alternative 2: N/A
Alternative 3: N/A
Where applicable, each project will document alternatives that were considered during the research
and planning phase. The alternatives for projects will be determined such as direct replacement,
manufactures recommendations, and industrial standards.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 234 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Operational Sustainment
2.6 Identify any metrics that can be used to monitor or demonstrate how
the investment delivered on remedying the identified problem (i.e., how will
success be measured).
Projects will be tracked and managed in Maximo asset management program. Historical asset data
may be used to compare the project benefits. When available, the data will be used to support the
investment decision.
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
Projects will commence and complete throughout the year over the various plant locations. This
process will allow"shovel ready" projects to be quickly put into the queue and executed when funds
and resources are available.
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.
Projects will be classified into level 0 and level 1 based on complexity and required coordination.
Level 0 projects will utilize the GPSS Operations team consisting of the Plant Manager, Operations
Engineering Manager, and Senior Operations and Maintenance Manager for project governance.
Projects will be ranked using the GPSS project ranking matrix which focus on various categories
including; Personnel and Public Safety, Environmental, Risk of Equipment Failure, Regulatory
Mandate, Maintenance Issues, Customer Value, Operating Efficiencies, Operating Costs, and
Obsolete Equipment. Level 0 projects are smaller in scope, generally less than $1 M,and completed
within the calendar year.
Level 1 projects, are larger in scope, schedule, and budget, costing between $1 M-$10M and are
completed over the course of two years. Level 1 projects will receive a higher level of scrutiny,
utilizing the GPSS strategic asset management plan to guide capital replacement strategies. Where
data is available, the GPSS risk-based investment planning tool will be used to rank asset condition,
criticality, and risk costs for level 1 projects.
A dedicated GPSS Program Manager will be responsible for monitoring the program and the
associated projects to ensure expected budget and transfer to plant are on target.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 235 of 271

Docusign Envelope ID: FEA53AA9-3B74-47D5-8D5B-A2D2FC7E3B79
GPSS Operational Sustainment
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the GPSS_Operational Sustainment
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.
Signed by:
Signature: F �i �S Date: Sep-17-2024 I 4:23 AM PDT
Print Name: re Z W 1§�lgfI1 l F 9 .
Title: Manager, GPSS O&M
Role: Business Case Owner
Signed by:
Signature: � � �bW Date: Sep-17-2024 I 12:37 PM PDT
Print Name:
Title: Director, GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 8 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 236 of 271

Peaking Generation
EXECUTIVE SUMMARY
Avista's Peaking Generation plants offer operational flexibility and are utilized to
support energy supply needs. Thermal Peaking Generation power provides options
for Avista's System Operations and Power Supply groups to maximize value to
Avista and its customers. These plants represent more than 255 MW of power and
include Rathdrum Combustion Turbines, Boulder Park Generating Station and
Northeast Combustion Turbine, all natural gas fired power plants.
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,
replacement of equipment at their end of life, and small capital upgrades to plant
facilities. The business drivers for this projects in this program is a combination of
Asset Condition, Failed 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 customers and the stability of the grid.
VERSION HISTORY
Version Author Description Date Notes
Draft Mike Mecham Initial draft of original business 7/8/2020
case
1.0 Mike Mecham Peaking Generation Business 6/22/2021 for 2022-2026
Case
2.0 Mike Mecham Peaking Generation business case 5/26/2022 1 For 2023 -2027
Business Case Justification Narrative Page 1 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 237 of 271

Peaking Generation
GENERAL INFORMATION
Requested Spend Amount $2,300,000
Requested Spend Time Period 5 years 2023 through 2027
Requesting Organization/Department T07/GPSS
Business Case Owner I Sponsor Thomas Dempsey Alexis Alexander
Sponsor Organization/Department T07/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 use of the peaking thermal generation facilities, some core
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
generating facilities. This program is critical in providing funding to support the
replacement of core assets and systems that support the reliable operations of
these 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 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.
Asset age, hours of use 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
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
jeopardize plant availability and greatly impact the value to customers and the
stability of the grid.
Business Case Justification Narrative Page 2 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 238 of 271

Peaking Generation
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.
Thermal Plants utilize plant reliability and availability metrics as well as in use
hours to determine some of the projects. Historically, this program has funded
multiple projects per year which contributed to unit availability and ensure
reliability by completing hours based capital replacement or upgrades to
equipment.
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, used hours replacement of equipment, and
Failed Plant. Projects are typically completed in the calendar year. The
work is primarily performed in the 2rd and 4th quarters of the year when
outage in the Peaking Thermal Plants are scheduled, typically during run
off in the river systems or during milder weather conditions when power
prices are low and it is most opportune to have the plants unavailable for
projects.
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 that
consists of Thermal Management, Maintenance Engineering and Plant
Personnel.
Option Capital Cost Start Complete
Peaking Generation Program $2,250,000 0112023 1212027
Individual Capital Projects $2,250,000 0112023 1212027
Perform O&M maintenance 0
Business Case Justification Narrative Page 3 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 239 of 271

Peaking Generation
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
the a realistic annual budget is $500,000. In order to support the capital budget
goals of the GPSS department, this budget was reduced in the short term for
years 2023 through 2027 by 10%. Projects with lower risk will be delayed
through this period.
The drivers of the projects selected to be funded by this program are mix of use
hours based replacement, 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.
2.2 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 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 smaller
Capital projects covered under the Peaking 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 Peaking Generation facilities
covered under this Program are estimated to be:
Rathdrum CT: $3,800
Boulder Park GS: $1,300
Northeast CT: $1,200
(refer to 20220825 Thermal Daily Outage Cost Estimation Tool
CONFIDENTIAL.xlsx)
Business Case Justification Narrative Page 4 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 240 of 271

Peaking Generation
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 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 managed by the Thermal personnel, including Management and
engineering. 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 10 to
15 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 Group. These projects are specific to these
plants and the leadership in the Thermal Group understand best the nature and
context of these projects.
These projects are, at times, 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 Iifecycle. 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
Peaking Thermal Plants, which are typically in the spring and fall of each year.
Some projects may have the ability to be performed during non-outage times.
Business Case Justification Narrative Page 5 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 241 of 271

Peaking Generation
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 Peaking Generation 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 Peaking Thermal
generation. By executing the projects funded by the program, we insure that
Peaking Generation Facilities are performing at a high level and serving our
customers with affordable and reliable energy.
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 $500,000.
The 5 year historical average spend in the Peaking Generation Program is $460,000.
In order to support the capital budget goals of the GPSS department, this budget was
reduced in the short term for years 2023 through 2027 by 10% per year. 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 Advisory Group Information
The Advisory Group for this program consists of the GPSS Asset Management and
Business Case Justification Narrative Page 6 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 242 of 271

Peaking Generation
Compliance Engineering team, Thermal Plant Operations Manager, Thermal
Maintenance Engineering and the Manager of Thermal Operations and Maintenance.
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 Thermal 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 Thermal Operations Manager, 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
Peaking Generation 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 review on a monthly basis by the Advisory
Group.
Business Case Justification Narrative Page 7 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 243 of 271

Peaking Generation
The undersigned acknowledge they have reviewed the Peaking Generation
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.
M Digitally signed by Mike Mecham
Signature: Mike ec a''''' Date:2022.08.31 11:20:04-07'00' Date:
Print Name: Mike Mecham
Title: Manager, Plant Ops Thermal
Role: Business Case Owner
Digitally signed by Alexis
Signature: Alexis AlexanderAlexander
g Date:2022.09.02 15:59:09-07'00' 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 8 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 244 of 271

Docusign Envelope ID:C64A2134-861A-439B-ADOC-CABBADC3EB2F
Post Street Substation Crane Rehab
EXECUTIVE SUMMARY
The 35 Ton Niles Bridge Crane at the Post Street Substation is original to 1907 and
services the interior of the building. The primary function for this crane is to service the
Upper Falls and Monroe Street GSU's, substation 115kv transformers, switchgear, and
miscellaneous other substation equipment. It is a low frequency of use, high
consequence if unavailable when needed, piece of equipment.
The crane's controls and electrical are mostly original and have degraded in capability
over time. Recent experience with the crane exhibited issues with controls and
overheating/stalling with extended use. The current state of electrical components on this
crane are not capable of supporting the pick of a transformer without extensive
refurbishing. This negatively impacts the ability to respond to a failure in a critical
downtown substation and increases risk. The problem is aggravated by the lack of ability
to use a large enough standard mobile crane inside the building as an alternative.
The recommended solution includes a replacement of the existing crane electrical and
controls, refurbishment of the mechanical components, and replacement of the existing
hoist and trolley system with a modern arrangement. This approach is a modern in-kind
replacement of the current substation crane and would provide a lasting solution to meet
current and future demands.
The initial estimated cost of the project is $2,134,000 in order to fully rehabilitate the
crane. 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 Post 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).
2024 Update: Current estimated cost of the project is $2,591,000. Much of the
anticipated cost increase is due to internally driven timing changes and deferral for budget
constraints.
VERSION HISTORY
Version Author Description Date Notes
Draft Ran Bean Initial draft of original business case 5/10/2022
Updated based on
1.0 Ryan Bean Update 8/2/2022 past actual costs
and equipment lead
time.
2.0 Don Sherrill Update 09/03/2024 Annual Update
Business Case Justification Narrative Page 1 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 245 of 271

Docusign Envelope ID:C64A2134-861A-439B-ADOC-CABBADC3EB2F
Post Street Substation Crane Rehab
GENERAL INFORMATION
Current Requested Spend Amount $2 591 000
Requested Spend Time Period 3 years
Requesting Organization/Department C07/GPSS
Business Case Owner I Sponsor Greg Wiggins I David Howell
Sponsor Organization/Department C07/GPSS
Phase Execution
Category Project
Driver Failed Plant&Operations
Business Case Justification Narrative Page 2 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 246 of 271

Docusign Envelope ID:C64A2134-861A-439B-ADOC-CABBADC3EB2F
Post Street Substation Crane Rehab
1. BUSINESS PROBLEM
1.1 What is the current or potential problem that is being addressed?
The 35 Ton Niles Bridge Crane at the Post Street Substation is original to 1907
and its electrical and controls are beyond their useful life. The Primary function
for this crane is to service the Upper Falls and Monroe Street GSU's, substation
115kv transformers, switchgear, and miscellaneous other substation equipment.
In its current state, it is unlikely the crane could support restoration efforts for a
major equipment failure, thereby placing future repair or refurbishment activities
at risk. Restoring this crane's capability will enable response to a failure in this
critical downtown substation and prepare the site for future projects.
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 crane has exceeded its
useful life and is not likely able to perform the function needed to support the
substation and generator transformers. Post Street Substation supplies power
to a significant portion of downtown Spokane, as well as serving as a conduit
for Upper Falls and Monroe Street generating stations which supply year-round
base load hydroelectric power. Continuing to operate Post 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).
1.3 Identify why this work is needed now and what risks there are if not
approved or is deferred
The current state of electrical components on this crane is unlikely to support
the pick of a transformer without extensive refurbishing. This negatively impacts
the ability to respond to a failure in this critical downtown substation and
increases the risk to our ability to reliably serve our customers. Without
mitigating the risk, the company would continue to be exposed to an uncertain
recovery for any major work needed at the facility.
While the Downtown Network has full redundancy, the substations that provide
that redundancy each have risks associated with them. The Metro Substation
is being replaced, but the new Metro Substation won't be in place until at least
2026. The Post Street Substation (where the crane to be replaced is located)
is the other substation servicing downtown Spokane. While not quite at the point
of needing replacement, like Metro, the Post Street station is also dated. Having
a failure of a transformer at the Post Street Substation and not being able to
Business Case Justification Narrative Page 3 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 247 of 271

Docusign Envelope ID:C64A2134-861A-439B-ADOC-CABBADC3EB2F
Post Street Substation Crane Rehab
replace it would leave the downtown relying on Metro Substation, which is well
past its useful life, as evidenced by the approved business case to replace it.
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 restoring the crane's capabilities to provide
the lifting services needed at the location. This could be captured via a
successful post rehab load test, reduced O&M for crane repairs, and decreased
risk to future project schedules due to crane down time.
1.5 Supplemental Information
1.5.1 Please reference and summarize any studies that support the
problem.
A crane assessment and evaluation was performed on Dec. 1, 2021 by
Simmers Crane. At a high level, the assessment found the electrical
components/controls for the bridge and trolley to be beyond service life
and at risk of failing the main functions of the crane. It was highly
recommended to replace all existing electrical controls on this crane.
The current mechanical condition of this crane appears to be acceptable,
though all of the hoist gearing is showing signs of misalignment wear and
further use of this crane could lead to extensive wear of mechanical parts.
Mechanical parts can still be sourced through Kone crane, though the
price and availability of these parts is less than ideal and thus a new trolley
and bridge drives is being recommended
Please see also:
- Annual Crane Inspection Reports by PCI (2010-2021) with findings of
related deficiencies.
- 2002 Load Test
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 crane is that it is
beyond it's useful life and is no longer able to perform the function
required. Major repairs to equipment may not be feasible and future
projects will be impacted without a crane readily available.
Business Case Justification Narrative Page 4 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 248 of 271

Docusign Envelope ID:C64A2134-861A-439B-ADOC-CABBADC3EB2F
Post Street Substation Crane Rehab
2. PROPOSAL TO COMPLETE RECOMMENDED SOLUTION
Option Capital Cost Start Complete
Original BCJN Requested Funding
$2,134,000
Not approved in 2021
Original Approved Alternative via FCR
Design/etc for new hoist/trolley and AC $250,000 08/2022 06/2024
Controls on Existing Bridge Frame
Net FCR-approved funds
Largely due to Internally Driven Timing $1,641,000 --- 06/2024
Changes
Current BCJN update
additional funds request to complete project $700,000 --- 05/2025
in 2025
Current Estimate at Completion $2,591,000 --- 05/2025
2.1 Describe what metrics, data, analysis or information was considered when
preparing this capital request.
A Crane Assessment and Evaluation was performed By Simmers Crane on Dec
1st 2021 to establish the existing condition and recommended actions. The
report informed a high-level Alternatives Analysis performed by GPSS
Mechanical Engineering with budgetary cost estimates based on multiple
manufacturer's input and past crane overhaul experience.
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 estimated $2.134M capital cost will be spread out over three years 2022-
2024. 2022 will be primarily design and contracting totaling $250,000. 2023
would include procurement, fabrication, and construction estimated at
$1,730,000. 2023 will include as builds and project closeout site totaling
$154,000. This will not offset significant O&M charges because many of the
crane components are beyond service life and are unable to be maintained.
Business Case Justification Narrative Page 5 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 249 of 271

Docusign Envelope ID:C64A2134-861A-439B-ADOC-CABBADC3EB2F
Post Street Substation Crane Rehab
2.3 Outline any business functions and processes that may be impacted (and
how) by the business case for it to be successfully implemented.
Fortunately, the Post Street Crane is not often used and it being unavailable will
result in little impact to normal operations. If there is a transformer failure, the
primary business function impacted will be Generation and Substation response
time. 115 kV breaker failure, PT failure, underground line termination failure,
switchgear failure, and many other miscellaneous pieces would also be difficult
if not impossible to respond to. This could affect reliability of the 115 kV BES
as well as other Generation and Distribution components.
Constructability details will need to be identified by the project team, which may
impact substation operations during the construction window. Any impacts to
Substation and System Operations will be discussed and planned with the
respective parties to mitigate impacts.
2.4 Discuss the alternatives that were considered and any tangible risks and
mitigation strategies for each alternative.
Alternative 1: Minimal Repairs
• Clean all electrical components before use
• polish conductor wire for trolley and bridge
• Replace all loose bolts noted in inspection
• Replace worn collector shoes on trolley
• Inspect and adjust brake on main hoist motor
• Mount a fan near resistor bank to keep cool
• Perform test crane pick to evaluate capacity
This crane is electrically outdated, making most components obsolete or difficult
to obtain and costs associated with making or attaining parts unknown and a
risk to the budget. There are no guarantees that any of this work will make the
crane suitable for future use. There are also high safety risks associated with
this existing equipment as many electrical components are exposed and not
contained from accidental operator contact. The existing design of the crane
also does not meet current OSHA and CMAA standards
Alternative 2: In-Kind DC Control System
• Full Non-Destructive Examination of all moving components
• New DC main feed rails down length of runway
• New DC trolley festoon system
• Reuse existing trolley and bridge drive components
• Replace worn bushings on trolley/hoist
Business Case Justification Narrative Page 6 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 250 of 271

Docusign Envelope ID:C64A2134-861A-439B-ADOC-CABBADC3EB2F
Post Street Substation Crane Rehab
• Radio transmitter for wireless operation
• Misc. upgrades to meet current crane design and safety standards
The crane would be upgraded to a modernized DC system capable of running
the existing mechanical components and adding radio controls to crane. DC
controls are more specialized engineering and there is a potential risk of
excessive cost associated. All warn bushings would need to be custom
manufactured and replacement costs will be substantial. There is a risk the NDE
results will require replacement of parts. Any part needing replaced has an
unknown cost associated. This option poses risk of using exiting components
for long term crane use and does not provide extended service life equal to
options 4 and 5. Maintenance costs are also expected to be higher throughout
extended service life as compared to options 4 & 5 due to continued use of
bushings on rotating equipment and DC motors. The work and cost required to
replace worn items and correct the misalignment issues would be excessive and
a new trolley would likely be more cost effective. It should be noted that the
trolley frame construction is mainly cast iron, and the equipment mounted
directly to cast iron framework. This construction is often difficult to upgrade with
any new equipment due to the inability to weld. This option is also not
recommended due to use of DC system in an AC supplied facility.
Alternative 3: Recommended Alternative—New Hoist/Trolley and AC Controls
on Existing Bridge Frame
• Upgrade power feed to 480 VAC
• New AC conductor bar down length of runway
• Modernize hoist, trolley and controls
• New AC trolley festoon system
• Radio transmitter for wireless operation
• New Bridge drive components
• Inspect Bridge wheels for reuse
• Misc. upgrades to meet current crane design and safety standards
Business Case Justification Narrative Page 7 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 251 of 271

Docusign Envelope ID:C64A2134-861A-439B-ADOC-CABBADC3EB2F
Post Street Substation Crane Rehab
The new hoist, trolley and bridge drive would be vfd controlled for smooth and
safe operation of the crane. This option will also eliminate all outdated electrical
components and upgrade to a standard 480v system that is consistent with
similar equipment at other Avista facilities and in the industry. This is the option
that was chosen at both LF and LL facilities for crane upgrades and is the
recommended upgrade by GPSS engineering. Removing the old trolley and
installing the new trolley will pose some challenges and may require roof entry
of mobile crane as was done at LF. This option is beneficial for extended service
life of the crane and to reduce maintenance costs as well. The extended service
life will nearly match that of a new crane without the additional materials and
installation costs associated.
Alternative 4: Install a New Crane on Existing Runway
• Demo existing Niles Crane
• Runway structural engineering to confirm capacity with new crane
• Replace with new crane (end trucks,bridge girders, trolley, &hoist)
• Upgrade power feed to 480 VAC
• New AC conductor bar down length of runway
• New bridge walkway
• Radio transmitter for wireless operation
• New crane meets all updated codes and safety regulations
Removal of the existing crane structure and installation of a new crane structure
poses higher risk and constructability than other options and will require multiple
overhead cranes and in-depth planning and engineering to accomplish. This
option would also have the potential to require longer outages for the 115v
portion of the sub near the demo and install. There are also unknowns
associated with the structural engineering involved for the existing runway that
is required under this option. A new crane would guarantee the longest extended
service life of any of the options presented. This option also has the possibility
of increasing the crane capacity to be able to lift a transformer without following
strict engineered pick procedures. The method for demo of old crane and install
of new crane is still undefined and is expected to be the largest difference in
cost between this option and option 3.
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 12 months starting in 2022 and ending in 2023.
The effort in 2022 will be devoted to design, equipment sourcing, and
Business Case Justification Narrative Page 8 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 252 of 271

Docusign Envelope ID:C64A2134-861A-439B-ADOC-CABBADC3EB2F
Post Street Substation Crane Rehab
fabrication. The effort in 2023 will consist of site mobilization, construction, and
commissioning of the crane. The crane will not become used and useful until
successfully passing a load test during commissioning in 2023.
2.6 Discuss how the proposed investment aligns with strategic vision, goals,
objectives and mission statement of the organization.
Operating Post Street Substation 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. By taking care of this crane, we improve
our reliability and support our mission of improving our customer's lives through
innovative energy solutions, which includes hydroelectric generation. By
executing this project, we ensure that Post Street Sub, Upper Falls, and Monroe
Street generation stations will continue to provide reliable service to our
downtown customers and mitigate risk to future projects and 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 based on
manufacturers estimates and past in-house experience with crane rehabilitation.
We are currently operating at risk at this location with being unable to respond
to a major equipment failure in a timely manner, thereby incurring lost generation
impacting customers.
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 Regional Plant Manager
and Operations crew on the Upper Spokane, GPSS Engineering, GPSS
Business Case Justification Narrative Page 9 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 253 of 271

Docusign Envelope ID:C64A2134-861A-439B-ADOC-CABBADC3EB2F
Post Street Substation Crane Rehab
Construction and Maintenance, Substation Engineering, and System
Operations. Other stakeholders may be identified during project initiation.
2.8.2 Identify any related Business Cases
No current dependent Business Cases.
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 10 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 254 of 271

Docusign Envelope ID:C64A2134-861A-439B-ADOC-CABBADC3EB2F
Post Street Substation Crane Rehab
The undersigned acknowledge they have reviewed the Post Street Substation
Crane Rehab 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.
Signed by:
Signature: rj�ftDate: sep-17-2024 1 4:29 AM PDT
(� vus
Print Name: r"eg3 iggins
Title: GPSS Manager of OW
Role: Business Case Owner
Signed by:
Signature: bWt Date: Sep-17-2024 1 12:33 PM PDT
Print Name: Davis owell
Title: Director, GPSS
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role:
Template Version: 05/28/2020
Business Case Justification Narrative Page 11 of 11
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 255 of 271

Regulating Hydro
EXECUTIVE SUMMARY
Avista's regulating hydro plants are unique in that they have storage available in
their reservoirs. This 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. These plants are the four largest hydro plants on Avista's
system representing more than 950 MW of power and include Noxon Rapids and
Cabinet Gorge on the Clark Fork River in Montana and Idaho and Long Lake and
Little Falls on the Spokane River.
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 is 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 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 Final signed business case 7/2/20
1.0 Bob Weisbeck Updated for 2022-2026 Capital Plan 6/22/21
Business Case Justification Narrative Page 1 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 256 of 271

Regulating Hydro
GENERAL INFORMATION
Requested Spend Amount $17,150,000
Requested Spend Time Period 5 years
Requesting Organization/Department 1-07, D07, 107/GPSS
Business Case Owner I Sponsor Bob Weisbeck Andy Vickers
Sponsor Organization/Department A07/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 regulating 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 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
jeopardize plant availability and greatly impact the value to customers and the
stability of the grid.
Business Case Justification Narrative Page 2 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 257 of 271

Regulating 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 87% and Failed Plant,
approximately 13%. Projects are typically completed in the calendar year.
The work is primarily performed in the 3rd and 4th quarters of the year when
outage in the Hydro Plants are scheduled, typically after run off in the rivers
has subsided.
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 Group.
Option Capital Cost Start Complete
Regulating Hydro Program $17,150,000 0112022 1212026
Individual Capital Projects $17,150,000 0112022 1212026
Perform O&M maintenance 0
Business Case Justification Narrative Page 3 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 258 of 271

Regulating 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 $3.5 Million.
The drivers of the projects selected to be funded by this program are mix Asset
Condition (approximately 87%) and Failed Plant (13%). 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 $3.5 million. In order support the budget constraints of the
department, this amount has been reduced by 10% for 2022. Projects with
lower risk will be delayed through this period. The projects in this program
typically take place during the outages which are in the summer and fall of each
year. Most of the capital is deployed in the 3rd 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. 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
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 259 of 271

Regulating 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 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 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 but most
of the capital is deployed in the 3rd and 4th quarter of each year. Work performed
in and around the dams that require outages typically 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 for small to medium size
projects with the objective of keeping our hydroelectric plants reliable and
available. These plants affordably support the power needs of our company
and our customers. By taking care of these plants 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
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 260 of 271

Regulating 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 $3.5
Million. In order to support the capital budget goals of the GPSS department, this
budget was reduced in the short term for 2022 by 10%for that year. 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 (approximately 87%) and Failed Plant (13%). 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
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 261 of 271

Regulating 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 will be followed
for reporting and identifying and executing change orders. Smaller projects will
have a point of contact and financials will be review on a monthly basis by the
Advisory Group.
The undersigned acknowledge they have reviewed the Regulating Hydro Program
business case and agree with the approach it presents. Significant changes to this
Business Case Justification Narrative Page 7 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 262 of 271

Regulating Hydro
will be coordinated with and approved by the undersigned or their designated
representatives.
Signature: x• Date: 6/22/2021
Print Name: R. S. Weisbeck
Title: Manager, Hydro Ops and Maintenance
Role: Business Case Owner
Signature: ,A4111d4,� 14LA ,d- Date: 7/6/2021
Print Name: Andrew Vickers
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 8 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 263 of 271

EXECUTIVE SUMMARY
Non-federal hydroelectric facilities must have a license from the Federal Energy Regulatory
Commission (FERC) to operate. FERC issued Avista a new 50-year license for the continued
operation and maintenance of the Spokane River Project (No. 2545, effective June 18, 2009). This
license covers the Post Falls, Upper Falls, Monroe Street, Nine Mile and Long Lake Hydroelectric
Developments. This license defines how Avista shall operate the Spokane River Project and includes
several hundred requirements,through license conditions,that we must meet. The license was issued
pursuant to the Federal Power Act (FPA) and embodies the requirements of a wide range of other
laws (The Clean Water Act, The Endangered Species Act, The National Historic Preservation Act,
etc.). These requirements are expressed through specific license articles relating to fish, terrestrial,
water quality, recreation, land use, education, cultural and aesthetic resources. Avista also entered
into additional two-party agreements with local, state, and federal agencies and the Coeur d'Alene
and Spokane Tribes. Avista's FERC license and agreements include mandatory conditions issued by
the Idaho Department of Environmental Quality (401 Water Quality Certification, issued June 5,
2008), the Washington Department of Ecology (401 Water Quality Certification, issued May 8,
2009), the U.S. Forest Service (Federal Power Act 4(e), issued May 4, 2007), and the U.S.
Department of Interior on behalf of the Coeur d'Alene Tribe (Federal Power Act 4(e), filed January
27, 2009). The FERC license ensures Avista's ability to operate the Spokane River project on behalf
of our electric customers within our service territory for a 50-year license term with an annual cost
that varies annually.
Complying with our license is mandatory to continued permission to operate the Spokane River
Project and funding the implementation activities is essential to remain in compliance with the
FERC license. Specific elements of this program change from year to year, depending on license
requirements as well as resource conditions. Ongoing stakeholder engagement, and therefore,
negotiation,is also required by the license.As a result, some elements of the license are relatively
predictable and static while others are dynamic and evolving.
Now that the license has been issued for a term of 50-years, governance is multi-faceted and
includes the Spokane River License team engaging with regulatory agencies,external and internal
stakeholders in annual, five-year, and ten-year planning to implement the license and settlement
agreement conditions. Implementation measures for each of the natural resource conditions have
specific success criteria identified. This data along with key accomplishments are
reported/documented as part of the license conditions, along with agency/stakeholder approvals.
Internal governance can include steering committees for specific major projects, as well as the
organizational hierarchy within which the Spokane River team operates. Work coordination
occurs through multi-departmental meetings and work planning.
If this business case is not approved, Avista will continue compliance with the FERC license and all
costs would be Operating expenses.
VERSION HISTORY
Version Author Description Date
1.0 Me han Lunney Initial draft of original business case 1013123
2.0 Meghan Lunney Information moved to new 2025-2029 template 512124
BCRT Heide Evans Has been reviewed by BCRT and meets necessaiy requirements 512124
Exhibit No.7
Case Nos.AW-E-25-01iAW-G-25-01
D. Howell,Avista
Schedule 1, Page 264 of 271

GENERAL INFORMATION
YEAR PLANNED SPEND AMOUNT PLANNED TRANSFER TO
W PLANT ($)
2025 $1,039,600 $1,039,600
2026 $973,000 $973,000
2027 $794,800 $794,800
2028 $597,200 $597,200
2029 $564,000 $564,000
Project Life Span Annually
Requesting Organization/Department C04/Spokane River License Implementation
Business Case Owner I Sponsor Meghan Lunney/ Bruce Howard
Sponsor Organization/Department A04 / Environmental Affairs
Phase Execution
Category Mandatory
Driver Mandatory & Compliance
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
Investment Drivers
1. BUSINESS PROBLEM - This section must provide the overall business case information conveying
the benefit to the customer, what the project will do and current problem statement.
1.1 What is the current or potential problem that is being addressed?
Non-federal hydroelectric facilities must have a license from the Federal Energy
Regulatory Commission (FERC) to operate. Avista's first Spokane River Project
License expired in 2007, and after a multi-year process involving hundreds of
stakeholders,FERC issued Avista a new 50-year license for the continued operation and
maintenance of the Spokane River Project (No. 2545, effective June 18, 2009). This
license covers the Post Falls, Upper Falls, Monroe Street, Nine Mile and Long Lake
Hydroelectric Developments.This license,based in large part on settlement agreements,
defines how Avista shall operate the Spokane River Project and includes several
hundred requirements, expressed as license conditions, that we must meet. The license
was issued pursuant to the Federal Power Act(FPA) and embodies the requirements of
a wide range of other laws (The Clean Water Act, The Endangered Species Act, The
National Historic Preservation Act, etc.). These requirements are expressed through
specific license articles relating to fish, terrestrial, water quality, recreation, land use,
education, cultural and aesthetic resources.Avista also entered into additional two-party
agreements with local, state, and federal agencies and the Coeur d'Alene and Spokane
Tribes, most of which are embodied in the License. Avista's FERC license and
agreements include mandatory conditions issued by the Idaho Department of
Environmental Quality (401 Water Quality Certification, issued June 5, 2008), the
Washington Department of Ecology (401 Water Quality Certification, issued May 8,
2009), the U.S. Forest.
Exhibit No.7
Case Nos.AW-E-25-01/AW-G-25-01
D. Howell,Avista
Schedule 1, Page 265 of 271

Spokane River License Implementation
Service (Federal Power Act 4(e), issued May 4, 2007), and the U.S. Department of
Interior on behalf of the Coeur d'Alene Tribe(Federal Power Act 4(e), filed January
27, 2009). The FERC license ensures Avista's ability to operate the Spokane River
project on behalf of our electric customers within our service territory for a 50-year
license term. The capital costs of
implementing the License varies each year, depending on specific requirements and
opportunities to accomplish projects.
1.2 Discuss the major drivers of the business case.
Complying with our license is mandatory for continued permission to operate the
Spokane River Project. Funding implementation activities is essential to remain in
compliance with the FERC license. Specific elements of this program change from
year to year, depending on license requirements as well as resource conditions.
Ongoing stakeholder engagement,and therefore,negotiation,is also required by the
license. As a result, some elements of the license are relatively predictable and
static while others are dynamic and evolving.
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.
Complying with our license is mandatory to continued permission to operate the
Spokane River Project and funding the implementation activities is essential to
remain in compliance with the FERC license. Ultimately, FERC has the authority
to issue orders and penalties, or in the extreme, revoke our license, if we do not
comply with the terms and conditions required by it. Loss of operational flexibility,
or in the extreme, loss of our generation assets, would create substantial new costs
to our customers and no benefits. In addition,Avista would suffer reputational costs
for not meeting our commitments.
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
Implementing the required Spokane River license conditions during 2024 is required
by the FERC license in order to operate the Spokane River Hydroelectric Project.
This ensures a reliable energy supply for our customers. The License is the result
of seven years of community-based collaboration, and implementation also reflects
ongoing collaboration with key stakeholders.
Additionally, these implementation measures showcase Avista's ongoing
commitment to environmental stewardship which benefits our customers, the
company and the communities we serve.
Business Case Justification Narrative Template Version: February 2023 Page 3 of 8
Exhibit No.7
Case Nos.AW-E-25-01/AW-G-25-01
D. Howell,Avista
Schedule 1, Page 266 of 271

Spokane River License Implementation
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.'
Federal Energy Regulatory Commission (FERC). 2009. Order Issuing New License
and Approving Annual Charges For Use Of Reservation Lands. Issued June 18.
Avista. 2005. Spokane River Hydroelectric Project, FERC No. 2545, Final
Application for New License Major Project—Existing Dam. July 2005.
Avista. 2005. Post Falls Hydroelectric Project, Currently Part of Project No. 2545,
Final Application for New License Major Project—Existing Dam. July 2005.
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.
Complying with our license is mandatory to continued permission to operate the
Spokane River Project. Funding the implementation activities for the Spokane
River Project License is essential to remain in compliance with the FERC license.
There are no practicable alternatives to meet compliance. Avista evaluated the
potential of surrendering the Spokane River license at the beginning of the
relicensing process, determining that this option would be detrimental to our
customers, the company and the communities we serve.
If the PM&Es, license articles and settlement agreements are not implemented
and/or funded, we would be out of compliance and/or in violation of our License.
This would lead to penalties and fines,new license requirements, court costs,higher
mitigation costs, and loss of operational flexibility. Ultimately, FERC has the
authority to revoke our License if we do not comply with the terms and conditions
required by it. Loss of operational flexibility, or in the extreme, loss of our
generation assets, would create substantial new costs to our customers and no
benefits.
' Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
Business Case Justification Narrative Template Version: February 2023 Page 4 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 267 of 271

Spokane River License Implementation
2.2 Describe and provide reference to CIRR/IRR analyses, relevant studies,
documentation, metrics, data, analysis, risk reduction, or other
information that was considered when preparing this business case (i.e.,
samples of savings, benefits or risk avoidance estimates; description of
how benefits to customers are being measured; metrics such as
comparison of cost ($) to benefit (value), or evidence of spend amount to
anticipated return).2
Avista is required to comply with all terms of the License. Non-compliance would
expose Avista to potential enforcement by FERC ynder its FPA authority, as well
as the enforcement by agencies which claim direct enforcement authority under
specific statutes, as well as citizen anforcement allowed under statutes such as the
CWA. Each authority contains its own provisions on allowed penalties.
Additionally parties to the settlement could petition FERC for enforcement and/or
dispute resolution, creating legal costs in addition to penalty amounts.
Avista would risk challenges to its operational flexibility as the lack of flexibility
to comply with orders issued by FERC. Ultimately, non-compliance could allow
FERC to open a License for a third party to take over. Finally, Avista would suffer
reputational risks in not complying with the License and its attendant agreements.
2.3 Summarize in the table, and describe below the DIRECT ofPsets3 or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
There are no quantifiable direct savings calculable, as this Business Case funds
implementation of the Spokane River Federal Energy Regulatory Agency (FERC)
License,for Project#2545.A license from FERC is required to operate non-federal
hydroelectric projects. Avista underwent a 7-year relicensing effort from 2002-
2009 involving two states, several Tribes, multiple federal, state and local
agencies, multiple non-governmental environmental organizations, land owners
and other stakeholders. This resulted in a new 50-year license through which
Avista avoided the potential of extensive litigation and license delays, as well as
potentially costly applications of mandatory conditions.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
3 Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
Business Case Justification Narrative Template Version: February 2023 Page 5 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 268 of 271

Spokane River License Implementation
2.4 Summarize in the table, and describe below the INDIRECT offsets4
(Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2025 2026 2027 2028 2029
Capital $ $ $ $ $
0&M $ $ $ $ $
As a result of the relicensing process, the FERC License maintained operational
flexibility with a minimum of restraints. Maintaining this operational flexibility
was one goal of the relicensing process to ensure reliable energy to follow
customer loads. Replacing lost generation capacity would require the
development of new and more expensive resources with the capability of reliably
meeting load.
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:
There are no practicable alternatives to meeting compliance. Avista evaluated the
potential of surrendering the Spokane River license at the beginning of the
relicensing process, determining that this option would be detrimental to our
customers,the company and the communities we serve.
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).
Implementation measures conducted under this capital request are based upon
regular meetings engaging with regulatory agencies and external and internal
stakeholders during annual, five-year, and ten-year planning meetings.
Implementation measures for each of the natural resource conditions have specific
success criteria identified. This data along with key accomplishments are
reported/documented as part of the license conditions, along with
agency/stakeholder approvals. At every opportunity during project planning cost
sharing options and opportunities are fully explored to ensure Avista's fiduciary
duty to its customers is upheld.
4 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
Business Case Justification Narrative Template Version: February 2023 Page 6 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 269 of 271

Spokane River License Implementation
2.7 Please provide the timeline of when this work is schedule to commence
and complete, if known.
The requested capital costs will be implemented in accordance with the schedules,
milestones and benchmarks identified in the annual planning process as identified
and committed to within annual, five-year and ten-year workplans. The work is
completed in collaboration with internal and external stakeholders
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 majority of our external agency stakeholders that interface with this business
case include the Idaho Department of Environmental Quality, Idaho Department of
Fish and Game, Idaho State Historic Preservation Office, Idaho Department of
Lands, Washington Department of Ecology, Washington Department of Fish and
Wildlife, Washington State Historic Preservation Office, Washington Department
of Natural Resources, U.S. Forest Service, U.S. Fish and Wildlife Service,
U.S. Department of Interior, Coeur d'Alene Tribe, and Spokane Tribe. Additional
external stakeholders including conservation districts, non-profits, and local
educational institutions, as well as a number on non-governmental environmental
organizations.
Major internal stakeholders include GPSS, Power Supply, External Communications,
etc.
Business Case Justification Narrative Template Version: February 2023 Page 7 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1,Page 270 of 271

Spokane River License Implementation
3. APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the Spokane River License Implementation and
agree with the approach it presents. Significant changes to this will be coordinated with and approved
by the undersigned or their designated representatives.
Signature: Date:
Print Name: Meghan Lunney
Title: Spokane River Manager
Role: Business Case Owner
Signature: Date:
Print Name: Bruce Howard
Title: Sr Dir Environmental Affirs
Role: Business Case Sponsor
Signature: Date:
Print Name:
Title:
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2023 Page 8 of 8
Exhibit No.7
Case Nos.AVU-E-25-01/AVU-G-25-01
D. Howell,Avista
Schedule 1, Page 271 of 271