20260709Appendix B - BCJN East CDA Lake System Reinforcement 2025 Signed.pdf

Docusign Envelope ID:8CCC3A68-03CE-43DA-B898-C7252FC06A79
East Coeur d'Alene Lake System Reinforcement Project
EXECUTIVE SUMMARY
Growth on the east side of Lake Coeur D'Alene is impacting the ability of the existing distribution system to
reliably serve customer load. During winter peak loading conditions, the feeder cable that crosses Lake
CDA is reaching the cable's rating limits. Exceeding equipment ratings will require either pre-emptive load
shed to reduce loading or the risk of permanently damaging the equipment due to the overload which would
result in a longer duration outage. Operations is also experiencing protection concerns which will only be
exacerbated in the near term. The protection concern is the ability to properly size fault detection devices,
fuses and reclosers, to adequately detect faults while not tripping the circuit due to heavy load.
The consequence of the protection failures are primarily fuses melting due to load causing customer
outages and the ability to restore service to the customers is constrained by the additional loading from cold
load pickup therefore requiring staged restorations.The consequence of low voltage is potentially damaging
customer's end use equipment and not meeting the required performance criteria enforced by the state
commission. The need for a plan to mitigate these concerns has been evident for years, and thus property
was purchased in 2011 on Elk Road near Carlin Bay to be utilized for this a substation to remediate this
issue. Technical analysis completed by System Planning has been performed to confirm the project as
proposed provides acceptable system performance and mitigates the critical issues which exist on the
distribution feeders, impacting customers on the east side of Lake Coeur D'Alene.
The identified operational challenges have become more severe with increasing load growth of around 5%
per year, leading to this request.The complete scope will be executed in a phased approach so equipment
loading, and protection coordination issues are mitigated and operational while the remainder of the scope
can be completed. The complete scope includes the following:
• Phase 1 includes construction of the lake crossing, construction of a 115kV transmission line tap
from the Benewah—Pine Creek 115kV line near O'Gara to the new Carlin Bay Substation and the
Carlin Bay Substation itself. The initial phase will relieve adjacent Blue Creek and O'Gara
distribution feeders in the near term.
o The construction for the lake crossing is expected to be completed by the end of 2025.The
transmission line project commenced with the line siting process in 2023. This portion
involved hiring a consultant to identify the best route possible while limiting environmental,
property, and cost impacts.As of 2025 the transmission line is in the easement acquisition
process and the route has been finalized.
■ 115kV Transmission Line Cost: $14,500,000
■ Carlin Bay Substation Cost: $13,100,000
• Phase 2 includes a rebuild of the O'Gara Substation. The rebuild will address aging infrastructure,
capacity needs, and increase reliability for area customers and Kootenai Electric who has a feeder
out of the existing substation. Property for the new O'Gara substation was purchased in 2023.
o O'Gara Substation Cost: $17,100,000
It is important to note the dependencies amongst the three projects. Due to the lack of transmission in this
area the transmission line will need to be constructed first to energize the new Carlin Bay substation upon
its completion. From there Phase 2 will commence with the construction of the rebuilding of the existing
O'Gara Substation.
VERSION HISTORY
Version Author Description Date
1.0 Prugh/Kusel/ Initial draft of original business case 0412024
Gross
2.0 Pru h/Godinez Annual Update of Business Case 0512025
2.1 Kusel Added Approved Budget Amounts 0812025
BCRT BCRT Team Has been reviewed by BCRT and meets necessary requirements 4130125
Member SMC
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Docusign Envelope ID:8CCC3A68-03CE-43DA-B898-C7252FC06A79
East Coeur d'Alene Lake System Reinforcement Project
GENERAL INFORMATION
YEAR APPROVED BUDGET
AMOUNT ($) PLANNED TRANSFER TO PLANT($)
2026 $8,850,000 $0
$28,635,000 (TRANSMISSION LINE,
2027 $13,300,000 CARLIN BAY SUBSTATION)
2028 $9,000,000 $18,135,000 (OGARA SUBSTATION)
2029 $4,800,000 $1,645,000
2030 $0 $0
Project Life Span 10 Years
Requesting Organization/Department Substation Engineering
Business Case Owner Sponsor Cesar Godinez I Vern Malensky
Customer Engagement & Outreach Lead Tamara Bradley
Sponsor Organization/Department M08/Substation Engineering
Phase Planning
Category Project
EPIC Strategy Ensure Robust Energy Supply& Delivery
Opportunity Grow Capacity
Driver Performance & Capacity
Sub-driver Capacity
Named Communities* Geographic
Definitions for the Category and Driver can be found on the Business Case Review Team Team's site see link.
*If there is an identified community and census tract.
EPIC Strategic Plan
0 Investment Driver Definitions (06.12.2017).docx
** Need to add definitions
2. 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.
2.3 What is the current or potential problem that is being addressed?
The population and load demand growth on the east side of Lake Coeur D'Alene has resulted
in rising concerns for Avista to reliably support new customers at the far-reaching end of two
distribution feeders. Currently, two distribution feeders serve the east shore of Lake Coeur
D'Alene, one originating from the Blue Creek Substation and the other originates from the
existing O'Gara Substation. The associated feeders cannot support additional growth in the
area and have reached their capacity, see table 1 below. A 13.2kV distribution system is
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Docusign Envelope ID:8CCC3A68-03CE-43DA-B898-C7252FC06A79
East Coeur d'Alene Lake System Reinforcement Project
constrained in serving long distances due to protection coordination issues distinguishing fault
current from load current.
The consequence of protection coordination issues is customers will experience outages due
to fault detection devices,fuses and reclosers,tripping under heavy load conditions. Equipment
capacity issues have emerged, including overloaded feeder cable, voltage drop, voltage
imbalance, reduced fault current, overloaded fusing and feeder protection, and cold load
pickup, all of which contribute to system protection challenges. This occurred during winter
peak loading conditions. In 2024 there was significant cold snap, and the cable was loaded to
over 400A for approximately 2 hours (with a peak loading of approximately 429 A).To prevent
overloading equipment, Avista will disrupt service to customers to reduce loading or risk the
equipment becoming damaged which would result in a longer outage duration to customers.
Forecasted load in the area will further stress the existing infrastructure. Much of the new and
forecasted load is concentrated at the far reaches for each distribution feeder. Additionally,
several large developments, like the Gozzer Ranch development have either been proposed
or are under development. The following table is a list of known developments under various
stages of construction or planned for the near future. Some customer projects are waiting for
Avista
att}o�mitigate the above listed performance issues prior to starting construction.
N AN 'Fear
I Powderhorn Ranch [25%conf] up to 1300 residences I 2023 OGA611
I_ Patriot Homes [100%conf]—40 units I 2023 BLU321
I Fish Inn Campground [100%conf]Campground 2023 BLU321
w/cabins& RV spots
Burma Rd I [100%conf]old mill needs 2024 BLU321
cleanup
I Gotham Bay I [100%conf]—50 premium lots I 2024 BLU321
[100%conf]3000 scl ft houses-
Stonegate Development Harrison has building moratorium 2024 BLU321
b/c of sewer issues-3ph PM for
water
Carlin Bay Lodge Replacement [75%conf] 2024 OGA611
Table 1 provides the expected feeder and transformer loading over the next 10 years. Avista
has established performance criteria in the planning horizon to mitigate equipment loaded
about 80% of its applicable facility rating. When equipment approaches 100% of its facility
ratings in real time operations, customers power will be turned off to prevent damaging
equipment. In the East Lake Coeur d'Alene area, customer outages can have long restoration
times due to cold load pickup causing fuses and/or reclosers to trip. The project schedule is
aiming to be complete at the time when the loads are consistently around 100% capacity.
Feeder . 2023 2024 2025 2026 2027 2028
BLU Xfmr1 55 58 61 64 67 71 75 79 83 88 93
BLU321 75 80 84 90 95 100 107 113 120 127 135
BLU322 24 24 24 25 25 25 26 26 26 27 27
OGA Xfmr 1 90 90 94 96 98 100 102 104 106 106 106
OGA611 94 94 102 105 109 113 116 120 124 124 124
OGA612 KEC1 121 121 121 121 121 121 121 121 121 121 121
Table 1: Blue Creek and O'Gara Forecasted Peak Loading (%)
' Loading constraints on the OGA612 feeder are being addressed outside of the scope of this business case.
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Docusign Envelope ID:8CCC3A68-03CE-43DA-B898-C7252FC06A79
East Coeur d'Alene Lake System Reinforcement Project
2.4 Discuss the major drivers of the business case.
As stated above, Gozzer Ranch and other housing developments on the east side of Lake CDA
continue to drive up loading levels on BLU321 and OGA611 and has pushed our existing
system to its capacity. A substation near Carlin Bay is needed to serve the continuing
increasing load.
2.5 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. Include
a description of how this project benefits customers and how it will be
measured.
The impact of not performing this work is that Avista would not be able to reliably serve an area
that is experiencing significant growth. Customers will experience outages during peak winter
conditions when building electric heating demand is high. The outages may occur due to
overloaded equipment tripping or failing, or Avista intentionally reducing load to prevent
equipment damage. Instances of this have been detailed in the most recent study.The outages
could impact several hundred customers for multiple hours and may occur daily until peak
winter loading weather conditions pass. Further customer growth in the area will increase the
number of customers impacted.
The risk of not constructing the proposed project by the need by date is the inability to serve
customers during heavy winter loading conditions.There are few operating procedures in place
to mitigate equipment loading before the equipment reaches 100% of the applicable facility
rating. Operational mitigation is required during heavy winter loading until Carlin Bay Station is
energized. The Blue Creek Station transformer can briefly operate above 100% of the
applicable facility rating until a major transformer alarm is triggered. O'Gara Station currently
does not have SCADA, so real-time operation is not available. If the East Coeur d'Alene Lake
System Reinforcement project is not completed by the winter of 2025, Avista will operate with
the risk of turning customer's power off for 4-6 hours daily until heavy winter loading conditions
have passed.
2.6 Discuss how the proposed investment, whether project or program,
aligns with the strategic vision, goals, objectives and mission statement
of the organization. EPIC STRATEGIC PLAN
Ensure Robust Energy Supply & Delivery:
Avista aims to ensure reliable electrical service for customers on the East side of Lake Coeur
d'Alene.The Carlin Bay Substation and associated projects will provide the necessary capacity
to meet growing energy demands, aligning with Avista's reliability objectives and unlocking
growth potential in the area.
This project supports Avista's Ensure Robust Energy Supply&Delivery Focus Area and aligns
with the company's Vision, Mission, and Focus Areas by improving construction processes and
positively impacting the community. The investment in the transmission system is a long-term
commitment to infrastructure that will serve customers for generations.
Safety: The project ensures that the electrical system is built and maintained to the highest
safety standards, protecting both customers and employees.
Reliability: By increasing capacity and reinforcing the system, the project guarantees
consistent and dependable electrical service, meeting Avista's reliability objectives.
Affordability: The investment in infrastructure is designed to be cost-effective, ensuring that
customers receive reliable service at an affordable price.
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Docusign Envelope ID:8CCC3A68-03CE-43DA-B898-C7252FC06A79
East Coeur d'Alene Lake System Reinforcement Project
1.5 Supplemental Information — please describe and summarize the key
findings from any relevant studies, analyses, documentation,
photographic evidence, or other materials that explain the problem this
business case will resolve.2
System Planning has completed a thorough system study for this project. Many of the details
have been added to this business case document, a detailed engineering analysis is included
in the System Planning Study Report. Additionally, the electric system is analyzed bi-annually
through the System Assessment process performed by the System Planning team. The most
recent System Assessment is the 2023-2024 System Assessment Version 0(2023-2024 Avista
System Assess ment-VO.pdf). An example of study results are shown in the table provided in
section 1.2.
During the January 13th, 2024 peak winter conditions, operational issues as previously
described impacted customers.The picture provided below is an example of an 80T fuse which
melted due to too much load.
t)-
i
i
Low voltage issues were also experienced during the same peak winter conditions. The first
diagram below represents the voltage measured by the ZC952V midline regulator on BLU321.
Low voltage on the feeder results in voltage at customer service points not meeting state
requirements and can result in damage to customer end use equipment. Low voltage issues
were also present on the OGA611 feeder which is represented by the second diagram below
for the ZC620V midline regulator.
2 Please do not attach any requested items to the business case, rather be sure to have ready access
to such information upon request.
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Docusign Envelope ID:8CCC3A68-03CE-43DA-B898-C7252FC06A79
East Coeur d'Alene Lake System Reinforcement Project
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3. 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 complete scope of the Carlin Bay Project will be executed in a phased approach so
immediate concerns are mitigated and operational while the remainder of the scope can be
completed. The complete scope includes the following:
• Phase 1 includes construction of the Carlin Bay Station and a 115kV transmission line tap
from the Benewah — Pine Creek 115kV Transmission Line near O'Gara to the Carlin Bay
Station. The expected in-service date is 2028.
o 115kV Transmission Line Cost: $14,500,000
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Docusign Envelope ID:8CCC3A68-03CE-43DA-B898-C7252FC06A79
East Coeur d'Alene Lake System Reinforcement Project
o Carlin Bay Substation Cost: $13,100,000
Feeder Feeder
South North
Phase 1 Project Notes
1 Carlin Bay Substation T
_ ........................., ep BBnBwaft-P—Geek 115kV lne near
1 O O 0 Ce ane—t-1 app,ox.netery 15 m+es of
new 115 kV m Win 15 U A) OPGW to
Cerin Bar(mm rating 150 MVA)
yI/ yI/ y1/ O C tr c w Germ Bar SuI,,I,I wdh
15113 SkV d5oiWon uanstm aW w oo
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Blue Creek
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TL Pine Creek
y nvlxv
30 WA
_________________________________________________________________________________r
Leaend. O
Existing Fw1rhes
New 230 W
New 115 W 115 kV to
New Distributionif J
Benewah�A„
KEC Distnbution
At] A29]
O'Gara 115 kV to
Substation St Marles
Figure 1:Phase I Implementation Project Diagram
• Phase 2 includes a rebuild of the O'Gara Station to a breaker and a half configuration with
space for a future line position and future capacitor bank. The expected in-service date for
this work is 2028.
o O'Gara Substation Cost: $17,100,000
2.2 Describe and provide the following analyses:
• CIRR/IRR analyses
• Monetized Risk Reduction3
• Benefit/Cost ratio'
• Absent any of the above, is the proposed solution the lowest reasonable cost solution to project
state objectives and if so, why?5
• Identify risks associated with the project/program: not meeting stated objectives, experiencing
cost overruns,missing timelines,etc.6 Identify potential off ramps or corrective actions that serve
to mitigate the risks. What are the potential risks associated with the project not meeting stated
objectives, cost or timeline.
Study reports prepared by System Planning can be referenced for the East CDA Lake System
Reinforcement. An example of work includes:
• 2023 Avista System Plan—Version 0, 2024
3 Specific to residual risk, after taking into account already existing mitigation efforts that help offset
the inherent risks.
' Annual and/or Life of Project Benefits measured against Annual or Life of Project Costs.
5 Lowest cost solution, in this instance, still meets safety, reliability or other statutory or regulatory
requirements and fits within the overall corporate strategies (EPIC).
'Identify Probability of Occurrence for each risk(High/Medium/Low)and its impact(High/Medium/Low).
Business Case Justification Narrative Template Version: February 2025 Page 7 of 17

Docusign Envelope ID:8CCC3A68-03CE-43DA-B898-C7252FC06A79
East Coeur d'Alene Lake System Reinforcement Project
• BLU321-OGA611 —2023-24 Winter Peak Loading Summary
• East Coeur d'Alene Lake System Reinforcement—Version 0, 2025
Risk analysis performed by System Planning shows the project results in an 80%risk reduction.
The scope of the project reduces the likelihood of the occurrence of the issues described in
other sections. The impact scores are based on implications of dropping load during
contingency situations. The table below provides analysis results.
Option 1 Option 2 Option 3 Option 4
Issue Descripti Risk Do conv No on Category Nothi Risk ert to Risk O'Gara Risk Proposed Scope Risk
ng 25kV
f Likelihood 4 1 1 1
Financial 2 2 2 2
Impact
BLU321 Stakehold 3 3 3 3
1.1 Feeder erImpact 152 38 38 38
Loading Outages 3 3 3 3
Safety 4 4 4 4
Environme 0 0 0 0
ntal
Likelihood 5 1 1 1
Financial 2 2 2 2
Impact
BLU321 Stakehold 3 3 3 3
1.2 Low er Im act 190 38 38 38
Voltage Outages 3 3 3 3
Safety 4 4 4 4
Environme 0 0 0 0
ntal
f Likelihood 5 1 1 1
Financial 2 2 2 2
Impact
BLU321 Stakehold
Lake erImpact 3 3 3 3
1.3 Crossing 190 38 38 38
Cable Outages 3 3 3 3
Safety 4 4 4 4
Environme 0 0 0 0
ntal
f Likelihood 5 1 1 1 f
Financial 2 2 2 2
BLU321 Impact
Protectio Stakehold 3 3 3 3
1.4 n er Impact 190 38 38 38
Coordinat Outages 3 3 3 3
ion Safety 4 4 4 4
Environme 0 0 0 0
ntal
BLU321 Likelihood 5 0 0 0
1.5 Open Financial 1 20 1 0 1 0 1 0
Impact
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Docusign Envelope ID:8CCC3A68-03CE-43DA-B898-C7252FC06A79
East Coeur d'Alene Lake System Reinforcement Project
Delta Stakehold 1 1 1 1
Voltage er Impact
Outages 1 1 1 1
Safety 1 1 1 1
Environme 0 0 0 0
ntal
Likelihood 5 1 1 1 f
Financial 2 2 2 2
Impact
OGA Stakehold 3 3 3 3
2.1 Feeder er Impact 165 33 33 33
Loading Outages 2 2 2 2
Safety 4 4 4 4
Environme 0 0 0 0
ntal
Likelihood 5 1 1 1
Financial 2 2 2 2
Impact
Stakehold 3 3 3 3
2.2 OGA Low er impact 165 33 33 33
Voltage Outages 2 2 2 2
Safety 4 4 4 4
Environme 0 0 0 0
ntal
f Likelihood 5 1 1 1
Financial 2 2 2 2
Impact
OGA Stakehold 3 3 3 3
2.3 Transfor er Impact 165 33 33 33
mer Outages 2 2 2 2
Loading
Safety 4 4 4 4
Environme 0 0 0 0
ntal
Likelihood 4 1 1 1 f
Financial 2 2 2 2
OGA Impact
Protectio Stakehold 3 3 3 3
2.4 n er Impact 132 33 33 33
Coordinat Outages 2 2 2 2
ion Safety 4 4 4 4
Environme 0 0 0 0
ntal
Likelihood 5 0 0 0 f
Financial 1 1 1 1
Impact
OGA Stakehold 1 1 1 1
2.5 Open er Impact 20 0 0 0
Delta Voltage Outages 1 1 1 1
Safety 1 1 1 1
Environme 0 0 0 0
ntal
3.1 1 Likelihood 0 0 0 0 4 124 1 0 0
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Docusign Envelope ID:8CCC3A68-03CE-43DA-B898-C7252FC06A79
East Coeur d'Alene Lake System Reinforcement Project
Financial 2 2 2 2
Impact
Stakehold 3 3 3 3
Transmis er Impact
sion Outages 3 3 3 3
Outages
Safety 3 3 3 3
Environme 0 0 0 0
ntal
Overall Option 1389 284 408 284
Risk
Reduction in Risk
(Option 1 to 0% 80% 71% 80%
Option X
3.3 Summarize in the table and describe below the DIRECT offsets' or
savings (Capital and O&M) that result by undertaking this investment.
Offsets Offset Description 2024 2025 2026 2027 2028
Capital $ $ $ $ $
2.4 Summarize in the table and describe below the DIRECT offsets' or
savings (Capital and O&M) that result from undertaking this investment.
Offsets Offset Description 2026 2027 2028 2029 2030
Capital NIA $0 $0 $0 $0 $0
0&M Annual Cost ($50,000) ($50,000) ($50,000) ($50,000) ($50,000)
New transmission infrastructure projects are required to safely and reliably serve customers.
O&M costs include monthly inspection of the substations, periodic inspection of the
transmission line, substation yard maintenance (i.e., weed prevention, fire extinguisher
replacement), and substation equipment maintenance. Annual O&M costs for a transmission
substation is approximately $50,000.
2.5 Summarize in the table and describe below the INDIRECT offsets' (Capital
and O&M) that result by undertaking this investment.
Offsets Offset Descri tion 1 2026 1 2027 1 2028 1 2029 2030
Capital NIA $0 $0 $0 $0 $0
' Direct offsets are defined as those hard cost savings Avista customers will gain due to the work
under this business case. Such savings could include reductions in labor, reduced maintenance
due to new equipment, or other.
8 Indirect offsets are those items that do not directly reduce the current costs of the Company, but
may serve to reduce future hirings, improve efficiencies, reduces risk (cost or outage), or allows
current employees to focus on higher priority work.
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Docusign Envelope ID:8CCC3A68-03CE-43DA-B898-C7252FC06A79
East Coeur d'Alene Lake System Reinforcement Project
0&M N/A $0 $0 $0 $0 I $0
No indirect capital or O&M offsets are expected to result from this investment. Qualitatively the
project reduces exposure to potential customer outages as described in the problem statement
and avoids possible fines for non-compliance with NERC standards. Both examples of savings
cannot be clearly defined with assumed values.
The table below details the Avista System reliability results for 2024.
Reliability 20241 • .•-
Measure (2019-2023)
SAIFI 10.91 1 0.79 10.96
SAIDI 144.6 minutes 124.2 minutes 140.4 minutes
(2.41 hours) (2.07 hours) (2.34 hours)
CAIDI 159.6 minutes 156.6 minutes 147.0 minutes
I
(2.66 hours) (2.61 hours) (2.45 hours)
CEMI 4.31% 3.61% 5.40%
CAIFI 1.92 1.77 1.99
The table below details the 2024 reliability results for the OGA611 Feeder:
Reliability - Results
SAIFI 0.94
CAI D I 3.03
CEM13 54.2%
The table below details the 2024 reliability results for the BLU321 Feeder:
Reliability
SAIFI 2.31
CAI D I 3.21
CEM 13 71.7%
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Docusign Envelope ID:8CCC3A68-03CE-43DA-B898-C7252FC06A79
East Coeur d'Alene Lake System Reinforcement Project
2.6 Describe in detail the alternative. The alternative analysis has to include:
• Proposed cost for each alternative
• Why those alternatives did not provide the same benefit as the chosen solution.
• Additional risks to Avista may occur if an alternative is selected.
Alternative 1: Do Nothing/Status Quo: $0
The expected system performance if no mitigation alternatives are executed were previously
discussed in the Business Problem. BLU321 is at capacity to accommodate existing loading
levels as it relates to maintaining adequate feeder protection. Both BLU321 and OGA611 each
have 3 stages of voltage regulation (including substation regulators). Providing sufficient
voltage regulation is already a challenge and will become more difficult as load continues to
increase. Represented below are the previous recorded winter peak loading values compared
to the last cold load pickup event recorded.
The following data was recorded for the BLU321 feeder.
• The highest cold load pickup was 397A recorded on 3/25/2021 which was —2.5x the pre-
outage load of 145A.
• The winter peak load on 1/13/2024 was 533A.
• The winter peak load during the 2024-2025 season was not as severe as the cold snap in
2023-2024. The peak loading on the cable (as measured at ZC150R)occurred on 2/13/25 and
reached as high as 356 A. Assuming a winter rating of 440 A, which would correspond to 81%
of the rating.
• Using 387A as a potential pre-outage load, the cold load pickup is expected to be 2.5 x
387A= 967A. The cold load pickup exceeds the phase pickup setting of 525A for the ZC150R.
The following data was recorded for the OGA611 feeder.
• The winter peak load on 1/13/2024 was 215A.
• Using 184A as a potential pre-outage load, the cold load pickup is expected to be 2.5 x
184A = 460A. The potential cold load pickup is more than the phase pickup of 310A for
ZC613R.
The "do nothing" alternative is not valid for the Carlin Bay Substation project as protection
challenges will continue to increase as load in the area increases.
Alternative 2: $75M
Distribution voltage for BLU321 and OGA611 could be increased from 13.2kV, as it operates
today, to 25kV. Today BLU321 supports 1,840 customers and that number is expected to
continue to grow. This choice would improve distribution reliability for customers on the east
side of Lake Coeur D'Alene and eliminate the existing voltage drop, reduced fault current, and
cold load pickup concerns.The conversion would be very involved and complicated.The option
would include reconductoring the feeder from 15kV cable to 25kV and
constructing/reconstructing substations to provide 25kV transformation. This alternative would
address the protection challenges however the significant cost of this option has deemed the
option invalid. Additionally, it would result in normal operation feeder loading levels in excess
of 10 MVA as load growth continues into the future,which is inconsistent with traditional loading
guidelines (i.e., the "500A feeder plan").
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Docusign Envelope ID:8CCC3A68-03CE-43DA-B898-C7252FC06A79
East Coeur d'Alene Lake System Reinforcement Project
Alternative 3: $27.6M
A new Carlin Bay Substation could be fed from a tap of the Benewah — Pine Creek 115kV
Transmission Line near O'Gara. This option would reduce the modifications needed at O'Gara
thus reducing the overall cost of the project by almost$17.1 M million. Alternatively, this option
does not address equipment condition concerns at O'Gara and increases customer exposure
to outages on the Benewah — Pine Creek 115kV line thus reducing customer reliability in the
area.Approximately 5000+customers will be exposed to an additional 15 miles of transmission
line exposure which may cause 1-2 outages per year with a duration of 2-4 hours.
Alternative 4: $44.7M
In addition to the development of the Carlin Bay Station, this option includes re-building the
O'Gara station to be a switching station. This option increases the overall cost of the project,
however, provides significant benefits for the reliability of the system. Existing customer
exposure to outages, due to the O'Gara — St. Maries 115kV line section and O'Gara — Pine
Creek 115kV line section, will be eliminated with implementation of a switching station at
O'Gara. Customers fed from transmission between the Benewah and Pine Creek stations will
have redundant sources thus increasing reliability. Equipment condition concerns at O'Gara
are also alleviated with the implementation of this option.
Based on the benefits described above, a rebuild of the O'Gara Substation is included in the
scope of the project.
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).
Successful mitigation of the problem statement will be monitored as part of the bi-annual
System Assessment conducted by System Planning. The project will be successful if
performance criteria in short-term planning horizon studies can be met, and performance
issues are not observed in the operations time horizon. Assumptions made in System
Assessments are not static therefore projects are developed based on the best information
available. For example, future load forecasts may show additional load growth not expected
when a project is requested. If the project takes ten years to construct, it is possible the base
line assumptions have changed, and additional projects will need to be justified.
The performance criteria metrics which are monitored as part of the System Assessment
process are provided in DP-SPP-02 — Distribution System Performance. Expected
performance following completion of the project is all impacted distribution equipment will be
loaded less than 80% of applicable facility ratings during forecasted peak load conditions.
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Docusign Envelope ID:8CCC3A68-03CE-43DA-B898-C7252FC06A79
East Coeur d'Alene Lake System Reinforcement Project
2.8 If a continuing business case (year 2+), provide analysis on performance
against stated and/or existing metrics (i.e., is the project/program
meeting expectations.)
Phase 1 of this project is underway, meeting expectations and on schedule. As of 2025 the
Transmission Line is in the design and easement acquisition process and the route has been
finalized. The Carlin Bay substation permitting and the Ogara Substation scoping and start of
design is tracking. Success will be determined based on meeting the schedule, scope and
budget in conjunction with improvement in loads as referenced in section 2.7. Upon the
completion of the transmission line and the substations, this business case will be considered
closed out.
2.9 Please provide the timeline of when this work is scheduled to commence
and complete, if known.
Schedule for the new Carlin Bay 115kV Substation, 115kV Transmission Line, and O'Gara
115kV Substation:
115kV Transmission Line:
2023: Line Siting
2024: Design begins
2025: Easement Acquisition & Final Design
2026: Construction
2027: Finish Construction
Carlin Bay Substation:
2024: Early Permitting
2025: Distribution Design
2026: Scoping, Design, Site prep and Fencing
2027: M/S and Electrical Construction
2028: Relay & Protection Construction and Energize Substation
O'Gara Substation:
2025: Scoping and Start of Design
2026: Complete Design, Site prep and Fencing
2027: M/S Construction and Start Electrical Construction
2028: Complete Electrical Construction, Relay& Protection Construction and Energize Sub
3.0 PLEASE IDENTIFY AND DESCRIBE THE STEERING COMMITTEE /
GOVERNANCE TEAM, including customer engagement and outreach representation (as
needed) that are responsible for the initial and ongoing approval and oversight of the business case.
Cesar Godinez— Business Case Owner/Manager, Substation Engineering
Brian Hyde—Manager, Transmission Engineering
Katie Prugh— Manager, Engineering Projects
Kate Yarboro—Project Manager, Project Delivery
Casey McGinn— Project Manager, Project Delivery
Business Case Justification Narrative Template Version: February 2025 Page 14 of 17

Docusign Envelope ID:8CCC3A68-03CE-43DA-B898-C7252FC06A79
East Coeur d'Alene Lake System Reinforcement Project
For the Carlin Bay Substation and associated projects,there will be a Project Manager, Construction
Inspectors and Design Engineers (Transmission, Substation and Distribution) that will form the
oversight group. The Engineering Roundtable will provide technical review of potential scope
changes with the support of the System Planning and Operations department. Scope changes which
require additional fund requests to the Capital Planning Group will be vetted at the Engineering
Roundtable.
- Expected spend monthly meetings with Electrical Engineering managers.
4.0 ENERGY EQUITY CONSIDERATIONS FOR WASHINGTON STATE
4.1 Is the project wholly contained within an
Justice40:Kootenai County,Idaho Uact
Avista-identified community (System versus 1
6°5500'900 Popul Lion:J,°"
Geographic)? If yes, what metrics and
indicators are used to determine the
existence of energy-related disparities in `i
these communities. If not, what are the a s
indirect opportunities associated with this
project?
Yes, projects contained within this business case, when
implemented, would be categorized as Geographic since
the capital work projects are location-specific and could
impact Named Communities (Census tract 16055001900).
These projects are designed to address the needs, _
challenges, or opportunities within a specific region, and
their benefits are localized to the communities within that area. As such the following metrics
would be tracked as part of the project delivery:
Energy SupplyDelivery
reliability; emergency response; generation availability
❑ Project or program is part of a resiliency or disaster System Average Interruption
recovery plan which reduces the interruption frequency or Frequency(SAIFI)
reduces average outage duration for identified System Average Duration
communities. (SAIDI)
❑ Project or program increases reliability (or works Customers Experiencing
towards parity) for identified communities through multiple interruptions (CEMI)
maintaining current systems, upgrades or new
infrastructure or asset management program.
❑ Increases generation or improves infrastructure Percent of customers to
resulting in reduced percentage of long duration outages. experience long duration
Including increased transmission and distribution. outages (CELID)
❑ Improves or supports or Improves quality of service — Quality of service metrics
worst performing circuits (top 10)
❑ Enhances service quality through retiring of inefficient
plants, minimizing service interruptions,fostering customer
trust and satisfaction
Business Case Justification Narrative Template Version: February 2025 Page 15 of 17

Docusign Envelope ID:8CCC3A68-03CE-43DA-B898-C7252FC06A79
East Coeur d'Alene Lake System Reinforcement Project
❑Supports customer growth through improved Investment in identified
accessibility to those areas underserved or in need of community
investments. Either as an individual investment or as part
of comprehensive integrated plan
4.2 What community data are you relying on to support this program/project
affecting equity?
The Named Communities map and data are being used to identify where these projects take
place and the categories that identify these census tracts.
4.3 Summarize in the table and describe the equity offsets or savings$ that
result in undertaking this investment.
Offsets Offset 2026 2027 2028 2029 2030
Description
Non-energy Impacts
Social Cost of Carbon
Environmental
Economic
For the 2025 Capital Project Implementation period, the Company is working on developing a
common method for valuing these offsets.
4.4 Alternative analysis shall include how equity was evaluated as part of the
alternative analysis. Describe the analysis.
See question 2.6 above. Even though alternative analysis was conducted, it is typically
performed in the pre-project planning phase of the Equitable Business Planning process. The
objective is to evaluate alternatives using indicators and metrics which may inform the decision
and summarize in the Business Case. As such, this question is not applicable for the 2025
planning season.
Business Case Justification Narrative Template Version: February 2025 Page 16 of 17

Docusign Envelope ID:8CCC3A68-03CE-43DA-B898-C7252FC06A79
East Coeur d'Alene Lake System Reinforcement Project
5.0 APPROVAL AND AUTHORIZATION
The undersigned acknowledge they have reviewed the East Coeur d'Alene Lake System
Reinforcement and agree with the approach it presents. Significant changes to this will be
coordinated with and approved by the undersigned or their designated representatives.
Signed by:
Signature: Sar C,b Date: Aug-01-2025 1 2:03 PM PDT
Print Name: oecsrM NSodinez
Title: Manager, Substation Engineering
Role: Business Case Owner
Signed by:
Signature: Ut,Vln, kdva Date: Aug-04-2025 1 7:31 AM PDT
Print Name: 1432 g2A&�4BCk1A�lensky
Title: VDiireflct�vo�r, Electrical Engineering
Role: Business Case Sponsor
Signed by:
Signature: /i* Date: Aug-01-2025 1 9:03 AM PDT
Print Name: 368Ad`}i�Wag h
Title: Manager, Engineering Projects
Role: Steering/Advisory Committee Review
Business Case Justification Narrative Template Version: February 2025 Page 17 of 17