20260709Appendix A - East Coeur d Alene Lake System Reinforcement.pdf

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East Coeur d'Alene Lake System Reinforcement 2024
Table of Contents
1. Project Overview......................................................................................................4
2. Project Description...................................................................................................4
2.1. Problem Statement ............................................................................................4
2.1.1. Risks............................................................................................................5
2.1.2. Need by Date............................................................................................... 5
2.1.3. Technical Prioritization................................................................................. 6
2.2. Project Scope and Requirements....................................................................... 6
2.2.1. System Modifications................................................................................... 6
2.2.2. Protection Requirements ............................................................................. 9
2.2.3. Communication Requirements .................................................................... 9
2.2.4. Metering Requirements ............................................................................. 10
2.3. Project Execution ............................................................................................. 10
2.3.1. Construction Schedule............................................................................... 10
2.3.2. Cost Estimate ............................................................................................ 10
2.3.3. Long Lead Time Equipment....................................................................... 10
2.4. Contingent Facilities......................................................................................... 11
3. Technical Analysis ................................................................................................. 11
3.1. Scope of Study................................................................................................. 11
3.2. Distribution Base Case Assumptions ............................................................... 11
3.2.1. Distribution Load Assumptions .................................................................. 12
3.3. Distribution Base Case Results........................................................................ 13
3.4. Mitigation Plan Results..................................................................................... 15
3.5. Simulation and Modeling Methodology ............................................................ 17
3.5.1. Transmission Base Case Assumptions ..................................................... 17
3.5.2. Transmission Projects Modeled................................................................. 17
3.6. Transmission Project Representation .............................................................. 17
3.7. Power Flow Model............................................................................................ 18
3.8. Steady State Contingency Analysis ................................................................. 20
3.8.1. Heavy Summer Scenario........................................................................... 20
3.8.2. Heavy Winter Scenario.............................................................................. 22
3.8.3. 2026 Light Spring Scenario ....................................................................... 25
3.9. Voltage Stability Analysis ................................................................................. 25
3.9.1. Power/Voltage (PV) Adequacy.................................................................. 25
3.9.2. Reactive/Voltage (QV) Stability Analysis ................................................... 26
I
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East Coeur d'Alene Lake System Reinforcement 1 2024
3.9.3. Reactive Support Analysis......................................................................... 27
3.10. Stability Contingency Analysis...................................................................... 28
3.10.1 . Transient Performance........................................................................... 28
3.10.2. Maximum Clearing Times....................................................................... 29
3.11. Short Circuit Analysis.................................................................................... 29
3.12. Reliability Analysis ........................................................................................ 30
3.13. Redlined Scada Variable Limits.................................................................... 31
3.13.1 . Feeders.................................................................................................. 31
3.13.2. Transformers.......................................................................................... 31
3.13.3. Transmission Lines ................................................................................ 32
4. Appendix................................................................................................................ 36
4.1. Project Alternatives .......................................................................................... 37
4.1.1. Do Nothing................................................................................................. 37
4.1.2. Increase Distribution Voltage..................................................................... 37
4.1.3. Carlin Bay Station with Tap from O'Gara................................................... 38
4.1.4. Carlin Bay Station with O'Gara Switching Station...................................... 38
4.1.5. Star Point Configuration with O'Gara Switching Station ............................ 38
4.2. Distribution Integration .....................................................................................40
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East Coeur d'Alene Lake System Reinforcement 2024
1 . Project Overview
Growth on the east side of Coeur d'Alene Lake is impacting the ability of the existing
distribution system to reliably serve customer load. Operations are experiencing multiple
concerns which are expected to worsen in the near-term planning horizon. The need for
a plan to mitigate these concerns is evident. The identified concerns led to a necessity
for the East Coeur d'Alene Lake System Reinforcement project. The complete scope
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:
o Upgrade cable at lake crossing on BLU321 feeder from 350CN15 to
1000CN15
o Construction of 115/13kV Carlin Bay Station, 20 MVA Transformer
0 115kV transmission line tap from the Benewah — Pine Creek 115kV line
near O'Gara Station to the Carlin Bay Station
0 328A (250kVA) Voltage Regulators will provide voltage regulation on
CBY641 and CBY642 feeders
o Distribution integration of Carlin Bay Station feeders
• Phase 2 includes a rebuild of the O'Gara Station
o Construction of 115/13kV Ogara Station, 20 MVA Transformer
0 115kV transmission bus breaker-and-a-half configuration
0 328A (250kVA) Voltage Regulators will provide voltage regulation on
OGA611 feeder, KEC will provide voltage regulation on OGA612 feeder
o Distribution integration of new O'Gara Station feeders.
Phase 1 will relieve capacity constraints in the near term on adjacent distribution
feeders, BLU321 and OGA611 . Phase 2 will address O'Gara Station capacity
constraints and reliability for area customers. Technical analysis has been performed to
confirm the project as proposed provides acceptable system performance and mitigates
the critical system performance issues which exist on the distribution feeders, impacting
customers on the east side of Lake Coeur d'Alene.
2. Project Description
2.1 . Prohlem Statement
The population and load demand growth on the east side of Coeur d'Alene Lake has
resulted in operational challenges for Avista to reliably support new customers at the
far-reaching end of two distribution feeders. Currently, two distribution feeders serve the
east side of Lake Coeur d'Alene, one originating from the Blue Creek Station and the
other originates from the O'Gara Station. The associated feeders cannot support
additional growth in the area considering the long distances are currently pushing
limitations of the 13kV distribution system. 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,
similar to the Gozzer Ranch development, have either been proposed or are under
development. Table 1 provides the expected feeder and transformer loading over the
next 10 years.
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East Coeur d'Alene Lake System Reinforcement 2024
System performance criteria violations have emerged due to area load growth, including
thermal capacity, current imbalance, and voltage performance. Blue Creek Station has
existing and anticipated capacity constraints on the BLU321 feeder and Blue Creek
Transformer 1 . O'Gara Station has multiple existing and anticipated thermal
performance criteria violations. System protection challenges include low fault current
availability and cold load pickup which contribute to decreased reliability in the area.
BLU XFMR#1 50.54 54.07 58,15 62.49 67.33 72.23 77.77 83.61 '90.12 I 97.16 _I
BLU321 70.56 75.31 81.01 89.24 96.66
PM
BLU322 24.51 26.08 27.91 28.41 30.41 32.54 35.02 37.48 40.34 43.41 46.72
OGA XFMR#1 78.33 81.91 85.68 89.27 93.34 97.54
OGA611 84.23 88.05 92.66 109.38 114.31 119.91 125.91 132.14 138.39 144.86
OGA612* 111WI 3 139.95 145.93 152.13 158.65 165.45 172.53 179.92
Table 1: Blue Creek and O'Gara Station Forecasted Peak Loading (%)
*Metering CT is the limiting equipment. KEC voltage regulators are next capacity limiting
equipment at 86% loading.
Several enhancements have been implemented to the distribution system to attempt to
delay the need for a new station:
• Reconductor four miles of the BLU321 feeder
• Adjust locations of protective devices and sizes to best accommodate load
• Addition of midline recloser devices
• Balance feeders and laterals
Despite system enhancements, the near-term planning horizon reveals existing
infrastructure will be unable to reliably accommodate anticipated customer service
requests and load growth in the area. The East Coeur d'Alene Lake System
Reinforcement study identifies the recommended solutions to support future customer
needs.
1.1 .1 . Risks
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.
2.1 .2. Need by Date
Technical studies show equipment ratings are exceeded during heavy winter conditions.
Table 1 Table 2 shows the expected 80% and 90% need by dates.
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East Coeur d'Alene Lake System Reinforcement 1 2024
Feeder/Sub 80% need by date 90% need by date
BLU XFMR#1 2031 2032
BLU321 2026 2028
OGA XFMR#1 2025 2028
OGA611 Exceeded 2026
OGA612 Exceeded Exceeded
Table 2: Station need by dates
2.1 .3 'echnical Prioritization
Avista's Engineering Roundtable compares projects using a scoring matrix which
evaluates both the technical importance and urgency of a project. Table 3 provides the
suggested scoring for the Engineer Roundtable to use. The technical importance
scoring accounts for the inability to serve load without experiencing capacity issues and
the asset condition considerations of some equipment. The urgency scoring considers
the need by date stated in Section 2.1.2.
Tangential
eliability P.erfor-"rsafeWlEnviron- Regula-
mance mental tory Benefits Score
3 F::73 2 2 0 0 0 0 F 66
D. Number Urgency
Flexible -
Stations
3 3 3 1 1 2 88
Table 3: Engineering Roundtable prioritization scoring
2.2. Project Scope and Requirements
0.2.1 . System Modifications
Following the technical analysis outlined in Section 3, the scope of the system upgrades
shown below in Figure 1 and Figure 2 are necessary to improve system performance.
The complete East Coeur d'Alene Lake System Reinforcement project scope will be
implemented over two phases.
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East Coeur d'Alene Lake System Reinforcement 2024
Feeder Feeder
CBY642 CBY641
Phase 1 Project Notes
Carlin Bay Substation Tap Benewah-Pine Creek 115kV line near
----------------------------- ----------- --------- - ,
O ; O'Gara and construct approximately 15 miles of
new 115 KV transmission line with OPGW to
Carlin Bay(min rating 150 MVA)_
OConstruct new Carlin Bay Substation with one
115/13-8kV distribution transformer and two
distri bution feeders.
250 kVA M WA 250 kVA __.. _. Future to O Carlin Bay 115113-8kV distribution transformer
BIUe Creek NLTC set to 115.5kV
1
O
115 kV to
Pine Creek
y 115113W
20 MVA
---------------------------------------------------------------------------------
Legend: O
Existing Facilities
New 230 W
New 115 W 115 kV to
New Distribution /
Benewah A11 Al2
KEC Distribution
A13*1 A 29 5
O'Gara 115 kV to
Substation St Maries
Figure 1: Phase 1 Implementation Project Diagram
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East Coeur d'Alene Lake System Reinforcement 2024
Feeder Feeder
CBY642 CBY641
Carlin B ay Substation Phase 2 Project Notes:
ORebuild O'Gara lobe 115 kV,breaker and me
halfsubstation with one 115/13.8kV tlistnbutlon
transformer and Iw o distribution feetlers-
IIIF--+I/ Illi�l/ 2 Design for an additional line position and space
O for future capacitor bank or distribution
3 O'Gara 115/13.8kV 6slnbution transfornerNLTC
kvA �2Eu kVA �29]kVA Future to
set ID 115.5KV
- -� Blue Creek
• ®Voltage R r for Feetler 612 will be supplied
V and installed letl by Dy KEC.
1 n O BPA to add metering for KEC feeder
T 6 O'Gara Substation will include a microwave site
O to establish a connection to Mica Peak
y 115113kV
20 MVA
---------------------------------------------------------------------------------
Legend:
Existing Facilities -
O'Gara Substation 1
New 230kV
r---------------------------------------
New 115 W 115 W to
New Distribution O Pine Creek
KEC Distribution .._•. ._i...:_:�.
115 W to
` Benewah
115 W to
Mica Peak St Maries
` 115113kV O
20 WA
Feeder
T O OGA612
O'Gara ILA rj (KEC)
25D WA
Feeder
OGA611
250 WA
�6
Figure 2: Phase 2 Implementation Project Diagram
I Carlin Bay Station Desigr
The Carlin Bay Station project will include a new station at Avista-owned property on S.
Elk Rd. Coeur d'Alene, ID. The station is fed from a 115kV transmission line tap from
the Benewah — Pine Creek 115kV Transmission Line near O'Gara to the Carlin Bay
Station. The distribution portion of the station will have a 115kV circuit switcher, a
115/13kV 20MVA transformer with two distribution feeders, and auxiliary feeder
position. 328A (250kVA) Voltage regulators will provide feeder voltage regulation. A
portion of load served by the existing Blue Creek Station 115/13kV Transformer 1 and
O'Gara Station 115/13kV Transformer 1 will transfer to the new Carlin Bay Station.
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East Coeur d'Alene Lake System Reinforcement 2024
?.2.1 .? O'Gara Station Design
O'Gara Station will be a greenfield rebuild of the existing O'Gara Station at Avista-
owned property on S. Hwy 97 in Kootenai County, ID. The transmission portion of the
station includes a four-position breaker-and-a-half bus configuration with space for a
future bay. The distribution portion of the station will have a 115kV circuit breaker, a
115/13kV 20MVA transformer with two distribution feeders, and auxiliary feeder
position. 328A (250kVA) Voltage regulators will provide feeder voltage regulation on the
OGA611 feeder. KEC will provide voltage regulation on the OGA612 feeder. The load
served by the existing O'Gara Station will be transferred to the new station.
It is recommended to maintain the star point on the Benewah — O'Gara — Pine Creek
115kV transmission line until such a time the low voltage concerns, due to a loss of the
Benewah 230/115kV Transformer, can be mitigated.
2.2.1 .3. Distribution Integration Desigr
The following modifications to the distribution system are necessary to mitigate the
identified performance issues and integrate the new Carlin Bay Station feeders:
• Increase conductor size of the 9600' lake crossing from 350kCM to 1000kCM on
BLU321 feeder.
• Reconductor sections of feeder trunk to #556 AAC.
• Add midline recloser devices to feeders CBY641, CBY642, BLU321 and
OGA611.
• Add phases to specified existing single-phase and two-phase laterals to balance
per-phase loading.
Distribution integration details are shown in Section 5.2.
2.2.2. PrntP(-tion Requirements
Protection relay settings need to be modified at the Benewah A536 transmission line
terminal to coordinate with the system modifications. Protection relays at the Pine Creek
A292 transmission line terminal are obsolete and require upgrading with a new
protection package.
Typical distribution station protection schemes will need to be developed and deployed
for both the O'Gara Station and the Carlin Bay Station. The Carlin Bay Station includes
a 115/13kV 20MVA transformer and two distribution feeders. The O'Gara Station
includes 115/13kV 20 MVA transformer and two distribution feeders.
2.2.3. C011 II 1 IUI 11t,6LIU1 I rm--qu11 CI I ICI IlJ
Communication aided protection schemes are required on the Benewah — O'Gara and
O'Gara — Pine Creek 115kV transmission lines. A new network communication path is
required from O'Gara Station to Benewah and Pine Creek Stations. Redundant
communications for the protection schemes are not required. The new O'Gara Station
will include a microwave site to establish a connection to the existing Mica Peak tower.
The O'Gara and Carlin Bay Stations will require communications to provide SCADA
access to the sites. Carlin Bay Station can be connected by a radial fiber spur on the
new transmission line from O'Gara to Carlin Bay. Secondary communications paths for
SCADA backhaul may be provided by third-party cellular networks.
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East Coeur d'Alene Lake System Reinforcement 2024
2.2.4. Metering Requirements
No metering points related to Avista Balancing Authority Area will be impacted by the
project scope. The Kootenai Electric feeder OGA612 from the O'Gara Station will
require metering by BPA.
2.3. Project Execution
2.3.1 . Construction Schedule
The full project scope is to be completed prior to 2028 winter operating season. The
following timeline provides a high level, preliminary estimate of key milestones. Project
Delivery will maintain the actual schedule used for proceeding with the project.
Preliminary Carlin Bay Station project schedule is as follows:
• Project Scoping - - - - - - Q1 2026
• Physical and Electrical Design - - Q2 2026
• Site Prep Q2 2026
• Physical and Electrical Transmittal - Q4 2026
• Physical Construction - - - - Q4 2026
• Electrical Construction - - - - Q1 2027
• Construction Commissioning - - - Q2 2028
Preliminary O'Gara Station project schedule is as follows:
• Project Scoping - - - - - - Q3 2025
• Physical and Electrical Design - - Q4 2025
• Site Prep Q2 2026
• Physical and Electrical Transmittal - Q3 2026
• Physical Construction - - - - Q4 2026
• Electrical Construction - - - - Q2 2027
• Construction Commissioning - - - Q4 2028
2.3.2. Cost Estimate
The work to be completed under the East Coeur d'Alene Lake System Reinforcement
project requires budget allocated for Substation, Transmission, Distribution and
Communication work. An estimate of total project cost is roughly $43.945M.
iTotal Carlin Bay _`llllllllllllllllllll0'Gara'6MW7' Blue Creek
Substation $21,895,000 $8,750,000 $13,145,000 -
Transmission $15,400,000 $14,450,000 $950,000 -
Distribution $4,000,000 $2,250,000 $750,000 $1,000,000
Communication $2,650,000 $1,550,000 $1,100,000 -
Total $43,945,000 $27,000,000 $15,945,000 $1,000,000
Table 4: Project cost estimate
2.3.3. Lona Lead Time Equipment
Any electric system expansion may be delayed by long-lead time requirements, such as
equipment, land acquisition and/or outage windows. Known schedule constraints that
may impact the proposed project schedule are detailed in Table 5.
Page 10 of 44 Lim

East Coeur d'Alene Lake System Reinforcement 1 2024
Potential Constraint Typical Extended Impact
Procurement Procurement
Distribution Transformer 9 months 36 months Yes
115kV Circuit Breaker 6 months 36 months Yes
Table 5: Long-Lead Time Constraints
2.4. Contingent Facilities
Contingent facilities are unbuilt facilities which if delayed or not built could cause a need
for restudying the requested project.
No contingent facilities were identified for the East Coeur d'Alene Lake System
Reinforcement project.
ScopeInitiative ERT# Project Name
None
Table 6: Contingent Facilities
3. Technical Analysis
3.1 . Scope of Study
This study was performed to determine the transmission system and distribution system
performance impacts and mitigation solutions for the addition of the Carlin Bay Station.
Distribution system performance is compared against the criteria defined in DP-SPP-02
— Distribution System Performance. Distribution analysis performed included the
following:
• Multi-year Load Flow Analysis
• Short Circuit Analysis
Transmission system analysis performed included the following:
• Steady State Contingency Analysis
• Voltage Stability Analysis
• Stability Contingency Analysis
• Short Circuit Analysis
• Reliability Analysis
Transmission system performance is compared against the criteria defined in TP-SPP-
01 — Transmission System Performance. TP-SPP-01 contains criteria which
encompasses at a minimum the criteria established through regulatory requirements of
North American Electric Reliability Corporation (NERC) and Western Electric
Coordinating Council (WECC).
3.2. Multi-Year Load Flow Analysis
3.2.1 . Distribution Base Case Assumptions
Only data pertaining to the feeders and stations directly impacted by the selected
project solution are listed in this section.
Key Assumptions
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East Coeur d'Alene Lake System Reinforcement 2024
• Peak loading at each feeder was set to operationally observed peak winter
loading on 1/14/2024 and balanced per phase loading.
• This analysis does not explicitly account for EV adoption or building
electrification.
• Relative load at service transformers was assumed to be proportional to the
average loading over several days of data recorded during the cold event of
2024.
• No block load additions were assumed - Growth rate was used in lieu of block
load additions.
• Growth rate was calculated using multivariate regression based on historical data
2021-2023. Due to O'Gara Station not having SCADA, ZC613R recloser was
used to analyze the growth rate at this station.
Based on the stated assumptions, the annual growth rates in Table 7 were applied to
the stations impacted by the project work.
Blue Creek Transformer 1 6.33%
O'Gara Transformer 1 4.33%
Table 7: Station growth rates
3.2.2. Distribution Load Assumptions
Historical loading on the feeders at the O'Gara and Blue Creek Stations were analyzed
to determine the appropriate base case loading assumptions for load flow simulations.
The feeder loading shown in Table 8 was balanced and used in the distribution system
model to represent the base year of 2024.
Peak Demands
Start 1/14/2024 7:30
Finish 1/14/2024 7:35
BEACON.TEMP -2.44
STATIONBLUE CREEK
BLU XFMR#1 629.42 637.84 576.97 614.74 51.26% 51.94% 46.98%
BLU321 462.08 499.92 443.13 468.38 69.17% 74.84% 66.34%
BLU322 164.2 134.96 131 143.39 24.58% 20.20% 19.61%
ZC869R 47.86 110.98 76.57 78.47
ZC150R 351.64 380.96 342.57 358.39
ZC883R 302.95 285.49 258.63 282.36
• STATION
OGAXFMR#1(Insp) 383 249 369 333.67 87.24% 56.72% 84.05%
OGA611(Insp) 215 116 191 174 94.30% 50.88% 83.77%
OGA612(Insp) 168 133 178 159.67 88.67%
ZC613R 143.06 81.9 159.29 128.08 62.75% 35.92% 69.86%
ZC618R 77.9 32.82 90.51 67.08
Table 8: Station Peak Winter Loading
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East Coeur d'Alene Lake System Reinforcement 2024
3.2.3. Distribution Base Case Results
The results for the base case are shown in Table 9. This table is contextualized by
noting that this is an all-lines in service, 1/14/2024 peak winter loading analysis with
balanced per-phase loading. O'Gara Station has existing and anticipated capacity
constraints. Blue Creek Station has existing capacity constraints on the distribution
system and anticipated station capacity constraints.
Feeder/Sub 1 . 2025 2026 2027 2028 `
BLU XFMR#1 50.54 54.07 58.15 62.49 67.33 72.23 77.77 83.61 90.12 97.16 _
BLU321 70.56 75.31 81.01 89.24 96.66
MMMI
BLU322 24.51 26.08 27.91 28.41 30.41 32.54 35.02 37.48 40.34 43.41 46.72
OGA XFMR#1 78.33 81.91 85.68 89.27 f 93.34 97.54 P 101.
OGA611 84.23 88.05 92.66 119.91 125.91 132.1
OGA612 _WM 1f 34.23 JW5 145.93 152.13 158.65 165.45 172.53 179.92
Table 9: Base Case Station % Loading Results
The existing distribution system layout represented in the distribution system model for
analysis is shown in Figure 3.
Page 13 of 44

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East Coeur d'Alene Lake System Reinforcement 2024
3.2.4. Mitigation Plan Results
Implementation of the East Coeur d'Alene Lake System Reinforcement project results in
significant improvements to system performance. The results of a multi-year analysis
are shown in Table 10. The proposed Carlin Bay Station, energize year 2028, will have
a portion of load transferred from feeders BLU321 and OGA611 to mitigate existing
capacity constraints. The proposed O'Gara Station rebuild, energize year 2028 after
Carlin Bay Station, will have load transferred from the existing O'Gara Station and
mitigates the existing capacity constraints.
To mitigate the high growth on BLU321 feeder, CBY641 feeder can pick up a portion of
load at Gozzer Ranch during peak winter conditions if necessary to meet system
performance criteria. This capacity for the CBY641 feeder to pick up a portion of Gozzer
Ranch load increases as more sections of trunk conductor are upgraded to #556 AAC.
Year
Year Year 1rear--7'F91FwW Year Year I
BLU XFMR#1 50.54 54.07 58.15 62.49 56.21 60.3 64.71 69.53 74.74 80.22 86.33
BLU321 70.56 75.31 81.01 89.24 73.35 79.05 85.25 W92.16 99.34
BLU322 24.51 26.08 27.91 28.4 30.39 32.52 34.81 37.25 39.86 42.66 45.91
OGA XFMR
#1 78.33 81.91 85.68 89.27 0 0 0 0 0 0 0
OGA XFMR
#1 NEW 0 0 0 0 25.03 26.12 27.25 28.46 29.7 31.04 32.4
OGA611 84.23 88.05 tlz.bb Z
0 0 0 0 0 0 0
OGA611 2 0 0 038 39.67 41.56 43.54 45.61 47.88 49.99
OGA612 1 128.54 0 0 0 0 0 0 0
OGA612 2 0 0 0 0 30.28 31.57 32.91 34.32 35.79 37.32 38.92
CBY XFMR
#1 0 0 0 0 13.17 13.9 14.69 15.52 16.42 17.32 18.37
CBY641 0 0 0 0 16.91 17.97 19.11 20.39 21.75 23.13 24.74
CBY642 0 0 0 0 14.96 1 15.65 16.34 17.1 17.89 18.55 19.51
Table 10: Mitigation Case Winter% Loading
Page 15 of 44

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East Coeur d'Alene Lake System Reinforcement 2024
3.3. Simulation and Modeling Methodology
Technical studies used to analyze the project's impact on the transmission system was
performed. Transmission system analysis follows the methodology described in the TP-
SPP-01 — Transmission System Performance. Distribution system analysis
methodology was performed to determine expected feeder and transformer impacts.
The following sections outline specific assumptions used for the East Coeur d'Alene
Lake System Reinforcement project.
3.3.1 . Transmission Base Case Assumptions
Project analysis was performed using transmission system models representing the
scenarios listed in Table 11. Each scenario was used to determine existing transmission
system performance as well as post project performance.
Avista Planning cases are tailored from approved WECC cases, and each case
includes a full suite of steady state power flow contingency scenarios that are run to
analyze the impact of the project alternatives. These contingencies include outages
within the Avista Transmission System as well as select outages in adjacent Planning
Coordinator and Transmission Planner areas. Contingencies are also added or modified
to include elements added to the Transmission System for the purposes of this study.
Scenario WECC Case
Five Year 2026 Heavy Summer 26HS2a1 PW
Five Year 2026 Heavy Winter 26HW2a1 PW
One Year 2022 Light Spring 21LW1a1PW
Table 11: Scenario Studied
Transmission Projects Modeled
No unbuilt transmission system projects were identified to impact the analysis for the
East Coeur d'Alene Lake System Reinforcement project and therefore not included in
the models used for analysis.
3.4. Transmission Project Representation
The East Coeur d'Alene Lake System Reinforcement project is represented in the
transmission system model for analysis with two star point configuration options. Figure
5 shows the transmission system with the O'Gara — Plummer 115kV Transmission Line
section open, as it operates today. Figure 6 shows the transmission system with the
O'Gara — Plummer 115kV Transmission Line section closed.
Page 17 of 44

East Coeur d'Alene Lake System Reinforcement 2024
4.QL1 w EASTFARM UCKROAD VOSi ELS PRAIRIU ,Ye vE ax
ISw
LA
I 0.
OU
TM I2.11! 7.7 „,
5]3IM M ROl OEE 2Q WII Mvar
1A W. ]UIIA ST -
�.00 Olt F ILUEQK MI8 m
.017W 00 Mvar 6.T IEYII 1.OMVLEWAY L00)11 OORw ,. 32 EIM
Id3
4R HW OA MW T1. 2 9.6Hw9.9 Hvar U Hvr 11.2 Mvar
O.O" 11.9MW 2.3 MW 36.3 HW
0.0 W. 2A Hqr 0.6 Hvar l2.7 Mvar 7A MW
2.2 Mvar
20.5 Mvar
W
SHW
Hva
I li Wr
CAAUX SAY
Mw
-73.
1 Mwr
O.906
VLUHHE0. w
BENYYAH
tc I.O HW TA EIEII /
1.6 HW r lA EIRI
•.]' T ��-�.� 13 Hvar 0.1H
\: O.O Hvar
5 HW �✓
0 Hvar 1 1
0.9Ji w
23.0 HW S
Figure 5: O'Gara — Plummer 115kV Line Section Open
� H..
..ECRK
K9Mp ~ � SS Mrar w 6J3 Nrar 09%ws 200)��. LW1 pv RK
1101 II
OTr � Haa 1 .sue lames _ Mra
Lo . WTwFARM s1cKRo
LWl � as Hw MEE111
1.3 MW aI MW 1 6.1 MW�w ' I �� Mus�m filOMq� 10[
�zz H.r a HKs ao Le HKs� �°o Jk Laa w o 0 99fi w
LIBBTYLK 7.1
n21m 21 rnv
13.1 Mrr Ofi Hvar 120 Mrar
11 Mrar
CARIlH MY
PLUN6[ o6Rlu
19afiw
OBELW n i n—rr
uHla
» uKnY of M�.r uMla
sKm "
SciT oELlw II
IIQ aERS +a.9efi w
81MW y
2J MKs
81ENNEWAH
I
z
Q OA llrr
BAH y
/ F
Figure 6: O'Gara - Pine Creek 115kV Line Closed
3.5. Power Flow Model
Figure 7 depicts modeling the East Coeur d'Alene Lake System Reinforcement project
in the 2026 Heavy Summer scenario with the star point configuration closed through.
Page 18 of 44

East Coeur d'Alene Lake System Reinforcement 2024
O M r 0."s P. 1002 pu 3.5
~0 M ar PINE fJIK
M MW 8.1 MW DALTON A 1.00)p0 PEE W(
0 Mvar 5.5 Mvx PRA0VE8 67.3 Mvx 0.996 pu 1.031 W
Mvx -M 0 M W r 0.996 ry• •,j, Os�1.0 ~D Mvzr 5.1 11W ~7� is lMva
PU 9.5 Mvx TT
1.001 p BE 1.001 6.6 M
3.2 My/ 1.1 Mvvx I.8 51 BLUEC'W M; Ou 0.0 M�1002 �1.M00]2B.WMW
DOWIRP7 T __
�0.99fi Ou T
IlafYlL 1 1.001-1 7.2 MW I.a MW
1 OM pu ].0 Mwr Ir 0.99a Ou ].0 Mvar 0.5 Nvar
37.2 MW 2.4 MW 34.7 VM
MW 13.1 W. 0.6 Mvx 12.0 Mvar
Mvar
3.0 MW
1.4 Mvx
GREE-m-S U RlJN BAY
1.002 pU
MW
Mvar
PI UMMER �
1.006 pU 1.00D pu*O.l Mvx -0.1 Nwr
~ 1.]MW
0.3 M-
5MW
0 Mvar
099pµ �0986 pu
as Mvar 22.4 MW
7.1 Mvx
■ 3 °Fl��i pN � �
2 i t T
^.. � OW.OpHMvx
1.012 W �
Figure 7: 2026 Heavy Summer Power Flow
Figure 8 depicts modeling the East Coeur d'Alene Lake System Reinforcement project
in the 2026 Heavy Winter scenario with the star point configuration closed through.
0 Mvar 1.030 p 1.012 pv 1.3 Mva
» MW
I.
Mvar PINE CRK
» MW 6.1 MW DALTON A 1.010 W PINE CRK
O Mvar 23 Mwr PRAIRIES 68A Mwr I.007 PU 1.036 pv
45.]Mvar ~O MWr I.OlO m• y S41.MW
vL _ » MWY S.OM
OTI5 O M- lA Mvar 1A13 p 1
IRIS pv EASTFARM aECKROAD
1.013 p• 1.012 pv 7.7 MW 42 MW
3ULIA 51 0.9 Mvar
1.013 pppyyy ��I t BUN-
S 4.2 MW 5.5 MW I.J �Y�1 Mission 0.0M LOSS pu
IS Mvar O.5 Mvar DOWER RD 0.6 Mva , pv 1 a,n M
1.008 A DDLEWAV DA 85 MW 3.3 MW
L787Y1K 11.0 MW 1.012 pv 3 MW 1.009 P 14 Mvar 0.4 Mvar
IA33 p 1.4 Mvar 1 Mvar
33.4 MW 23 MW 34.5 MW '.
MW 6.1 Mvar 0.2 Mvar 6.4 Mvar
Mva
3.0 MW
f1A Mvar
�EEMACRFS -.N BAV
3A32 p
MW Tr pLUMMFR 06I1RA
1.6��1.011 W 1.004 w*�
� O.S MW E • E�
0.2 Mvar O.1 Mwr
7.9 MW 2.2 MW
0.9 Mwr 0.2 Mwr
O MWar
ETFE S o.992 PO3u
9.]MW
1.2 Mvar 24.0 MW
3A Mwr
RBEWAM •
1A34p / �
_2 i T
o.o Mwr �
BENEWAH
l.o1a p.
Figure 8: Heavy Winter Power Flow
Figure 9 depicts modeling the East Coeur d'Alene Lake System Reinforcement project
in the 2022 Light Spring scenario with the star point configuration closed through.
Page 19 of 44

East Coeur d'Alene Lake System Reinforcement 2024
�r W 1.00fiw
MNE fJa _
QOMva MWr ai Mtiz �� aO flKat 01N006 WA I.OM�� LN�NEw
n� 6.6MW IW6w •- N;
Ll�w BfCKfID/1D �
allN
ARM I.aa uu � saMw Hw
a— L]UIIRR;. Qw. �e WNKRHI
.� f6V 0.1 FIW SSMWw BLUEQ6l JWr M590N QOIMy cc��a 1.009W
alfNar 0.0fMar O�E1t1D al Mnr L T ` 1.001W -- 1/f, O.n
pry �L006w �
�L66w ♦7MW N1.61M�'•
l LLI� 1'�w 3�
LK Lm6w aoMv no Mvar S
16.6m L]MM 17.1M1
a7— aoMWr al MM
LI M
CANIIN 0A11
GNEFKA[IR6
LOOI W
KUM M
o66W .6mw
» x9m I.I MR
naMaar 'aG Maar
0MW
RM.r
RS srwwEs
w Lonl ou
4.6 MW
0.1 M— 11.B fIW
0.9 FNar `
KW M
.n o.o Erar
F i
0Ffi ryF Wl1M
Figure 9: 2022 Light Spring Power Flow
3.6. Steady State Contingency Analysis
3.6.1 . Heavy Summer Srpnarin
The following sections describe some existing or newly identified performance issues
influenced by the project in the heavy summer scenario. Steady state analysis was
performed under two system configurations. The system was first analyzed with the
Benewah — Pine Creek 115kV Transmission Line open, as it currently operates,
followed by analysis with the Benewah — Pine Creek 115kV Transmission Line closed
through.
All performance/reliability issues, considering both system configurations, in the Heavy
Summer scenario involve an outage of the Benewah 230/115kV Transformer. With the
Benewah — Pine Creek 115kV Transmission Line open and using the current seasonal
system configuration, 50.8MW of customer load and the 4.5MW generator in Plummer
is dropped for a P1 contingency, loss of the Benewah 230/115kV Transformer. With the
Benewah — Pine Creek 115kV Transmission Line closed and using the current seasonal
system configuration the same P1 contingency result in low voltage concerns for the
area served by the Benewah 230/115kV Transformer.
Based on analysis of the two configuration alternatives, it is recommended to maintain
the star point in an open configuration on the Benewah — O'Gara — Pine Creek 115kV
transmission line until the low voltage concern can be mitigated.
.1 R 1 1 :IPnPXniah TrangfnrmPr ni itan,,
By closing the Benewah — Pine Creek 115kV Transmission Line, low voltage concerns
appear under P1 contingency analysis which previously were not of concern. When the
Benewah — Pine Creek 115kV Transmission Line is open the same P1 contingency
Page 20 of 44

East Coeur d'Alene Lake System Reinforcement 2024
results in a loss of 50.8 MW of customer load and 4.5 MW of generation. Figure 10
shows the resulting system for a P1 outage of the Benewah 230/115kV Transformer.
-�1��) - - :
Figure 10: Benewah 230/115kV Transformer Outage, Heavy Summer
3.6.1 .2. Heavy Summer Summary Results
HS
GA
I
P1 • •
T-1: Benewah 230/115 kV
BENEWAH 48035 50.8 MW Load 0.94
HOPKINS# 47507 Dropped 0.93
LATAH 48181 0.94
MICA(47509) 0.93
ROCKFORD 48367 0.93
SETTERS(47376) 0.93
STMARIES 48417 0.95
TEKOA(48427) 0.94
P2
BF: R463 Benewah 230 kV Switched Shunt,Benewah 230/115 Transformer
BENEWAH 48035 50.8 MW Load 0.94
HOPKINS#(47507) Dropped 0.93
LATAH 48181 0.94
MICA(47509) 0.93
ROCKFORD 48367 0.93
SETTERS(47376) 0.93
STMARIES 48417 0.95
TEKOA(48427) 0.94
BF: R468 Benewah-Boulder,Benewah 230/115 Transformer
BENEWAH(48035) 50.8 MW Load 0.94
HOPKINS# 47507 Dropped 0.93
LATAH(48181) 0.94
MICA 47509 0.93
ROCKFORD(48367) 0.93
SETTERS 47376 0.93
STMARIES(48417) 0.95
TEKOA 48427 0.94
BF: R470 Benewah-Thornton,Benewah 230/115 Transformer
BENEWAH 48035 50.8 MW Load 0.94
HOPKINS#(47507) Dropped 0.93
LATAH 48181 0.94
MICA(47509) 0.93
ROCKFORD 48367 0.93
SETTERS(47376) ` 0.93
Page 21 of 44

East Coeur d'Alene Lake System Reinforcement 2024
STMARIES 48417 0.95
TEKOA 48427 0.94
BF: R474 Benewah-Pine Creek,Benewah 230/115 Transformer
BENEWAH 48035 50.8 MW Load 0.94
HOPKINS# 47507 Dropped 0.93
LATAH 48181 0.94
MICA 47509 0.93
PLUMMER 48323 0.95
ROCKFORD 48367 0.93
SETTERS 47376 0.93
STMARIES 48417 0.95
TEKOA 48427 0.94
BF: R476 Benewah-Moscow 230,Benewah 230/115 Transformer
BENEWAH 48035 50.8 MW Load 0.94
HOPKINS# 47507 Dropped 0.93
LATAH 48181 0.94
MICA 47509 I 0.93
ROCKFORD 48367 0.93
SETTERS 47376 0.93
STMARIES 48417 I 0.95
TEKOA 48427 I 0.94
P6
N-1: Benewah-Pine Creek 230 kV+T-1: Benewah 230/115 kV
50.8 MW Load
PLUMMER 48323 Dropped I 0.95
N-1: Burke-Pine Creek#3 115 kV BUR-LKY +T-1: Benewah 2301115 kV
150.8 MW Load
PLUMMER 48323 I Dropped 0.95
N-1: Burke-Pine Creek#4 115 kV BUR-BIG +T-1: Benewah 230/115 kV �_ I
50.8 MW Load
PLUMMER 48323 Dropped I 0.95
N-1: Burke-Thompson Falls B 115 kV+T-1: Benewah 2301115 kV
50.8 MW Load
PLUMMER 48323 Dropped 0.95
N-1:Coeur dAlene 15th St-Ramsey 115 kV+T-1: Benewah 2301115 kV
50.8 MW Load
PLUMMER 48323 Dropped 0.95
N-1: Noxon-Pine Creek 230 kV+T-1: Benewah 230/115 kV
I 50.8 MW Load
PLUMMER(48323) Dropped 0.95
A6
N-1: Burke-Pine Creek#3 115 kV Open @ BUR+T-1: Benewah 230/115 kV
50.8 MW Load
PLUMMER(48323) 1 Dropped I 0.95
N-1: Burke-Thompson Falls B 115 kV Open @ BUR+T-1: Benewah
230/115 kV
50.8 MW Load
PLUMMER 48323 Dropped 0.95
A7
IN-2:Appleway-Ramsey 115kV and Coeur dAlene-Ramsey 115kV+T-1:
Benewah 230/115 kV _ _
I 157.2 MW Load
PLUMMER(48323) Dropped 0.95
Table 12: Heavy Summer Steady State Contingency Results
3.6.2. Heavy Winter Scenario
The following sections describe some existing or newly identified performance issues
influenced by the project in the Heavy Winter scenario. Similar to the Heavy Summer
Scenario, analysis was performed under the same two system configurations and
performance/reliability issues in the Heavy Winter scenario also involve the loss of the
Benewah 230/115kV Transformer.
Page 22 of 44

East Coeur d'Alene Lake System Reinforcement 1 2024
With the Benewah — Pine Creek 115kV Transmission Line open and using the current
seasonal system configuration, 66.8MW of customer load and the 4.5MW generator in
Plummer is dropped in the P1 contingency of the loss of the Benewah 230/115kV
Transformer. With the Benewah — Pine Creek 115kV Transmission Line closed and
using the current seasonal system configuration the same P1 contingency result in low
voltage concerns for the area served by the Benewah 230/115kV Transformer.
Based on analysis of the two configuration alternatives, it is recommended to maintain
the star point in an open configuration on the Benewah — O'Gara — Pine Creek 115kV
transmission line until the low voltage concern can be mitigated.
3.6.2.1 . Benewah Transformer Outaor
By closing the Benewah — Pine Creek 115kV Transmission Line, low voltage concerns
appear under P1 contingency analysis which previously were not of concern. When the
Benewah — Pine Creek 115kV Transmission Line is open the same P1 contingency
results in a loss of 66.8MW of customer load and 4.5MW of generation. Figure 11
shows the resulting system for a P1 outage of the Benewah 230/115kV Transformer.
=
w
Figure 11: Benewah 230/115kV Transformer Outage, Heavy Winter
3.6.2.2. Heavy Winter Summary Results
HW CLOSEOGA HW—BASE —PIN
P1
T-1: Benewah 230/115 kV
BENEWAH 48035 66.8 MW Load 0.94
HOPKINS#(47507) Dropped 0.92
LATAH 48181 0.94
MICA(47509) 0.92
PLUMMER 48323 0.95
ROCKFORD(48367) 0.93
SETTERS 47376 0.93
TEKOA(48427) 0.94
P2
BF: R463 Benewah 230 kV Switched Shunt, Benewah 230/115 Transformer
BENEWAH 48035 66.8 MW Load 0.94
HOPKINS#(47507) Dropped 0.92
LATAH 48181 0.94
MICA(47509) 0.92
Page 23 of 44

East Coeur d'Alene Lake System Reinforcement 2024
PLUMMER 48323 0.95
ROCKFORD 48367 0.93
SETTERS 47376 I 0.93
TEKOA 48427 _ 0.94
BF: R468 Benewah-Boulder,Benewah 230/115 Transformer
BENEWAH 48035 66.8 MW Load 0.94
HOPKINS#(47507) Dropped 0.92
LATAH(48181) 1 0.94
MICA(47509) 0.92
PLUMMER 48323 0.95
ROCKFORD(48367) 0.93
SETTERS(47376) 0.93
TEKOA(48427) I 0.94
BF: R470 Benewah-Thornton,Benewah 2301115 Transformer
BENEWAH(48035) 166.8 MW Load 0.94
HOPKINS# 47507 I Dropped 0.92
LATAH(48181) I 0.94
MICA(47509) 0.92
PLUMMER 48323 0.95
ROCKFORD 48367 0.93
SETTERS 47376 0.93
TEKOA 48427 �_ 0.94
BF: R474 Benewah-Pine Creek,Benewah 230/115 Transformer
BENEWAH 48035 66.8 MW Load 0.94
HOPKINS# 47507 j Dropped 0.92
LATAH 48181 0.93
MICA 47509 0.92
PLUMMER 48323 0.95
ROCKFORD 48367 0.92
SETTERS 47376 0.92
STMARIES 48417 I 0.95
TEKOA 48427 I 0.93
BF: R476 Benewah-Moscow 230,Benewah 230/115 Transformer
BENEWAH 48035 166.8 MW Load 0.94
HOPKINS# 47507 Dropped 0.92
LATAH(48181) 0.94
MICA 47509 0.92
PLUMMER 48323 I 0.95
ROCKFORD 48367 0.93
SETTERS 47376 0.93
TEKOA 48427 I 0.94
P6
N-1: Benewah-Pine Creek 230 kV+T-1: Benewah 230/115 kV
66.8 MW Load
STMARIES 48417 Dropped 0.95
N-1: Burke-Pine Creek#3 115 kV BUR-LKY +T-1: Benewah 230/115 kV
66.8 MW Load
STMARIES 48417 Dropped 0.95
N-1: Burke-Pine Creek#3 115 kV(PIN-LKY)+T-1:Benewah 230/115 kV
66.8 MW Load
STMARIES 48417 I Dropped 0.95
N-1: Burke-Pine Creek#4115 kV BUR-BIG +T-1: Benewah 230/115 kV
66.8 MW Load
STMARIES 48417 Dropped 0.95
N-1: Burke-Pine Creek#4 115 kV(PIN-BIG)+T-1: Benewah 230/115 kV
66.8 MW Load
STMARIES 48417 Dropped 0.95
N-1: Burke-Thompson Falls B 115 kV+T-1: Benewah 230/115 kV
66.8 MW Load
STMARIES 48417 I Dropped 0.95
N-1:Coeur dAlene 15th St-Ramsey 115 kV+T-1:Benewah 230/115 kV
66.8 MW Load
STMARIES 48417 Dropped 0.95
N-1: Hatwai-Moscow 230 230 kV+T-1: Benewah 230/115 kV
Page 24 of 44

East Coeur d'Alene Lake System Reinforcement 2024
PIN
66.8 MW Load
STMARIES 48417 Dropped 0.95
N-1: Noxon-Pine Creek 230 kV+T-1: Benewah 230/115 kV
66.8 MW Load
STMARIES 48417 Dropped 0.95
S-1: Ramsey 115kV Switched Shunt+T-1: Benewah 230/115 kV
66.8 MW Load
STMARIES 48417 I Dropped 0.95
A7
N-2:Appleway-Ramsey 115kV and Coeur dAlene-Ramsey 115kV+T-1:
Benewah 230/115 kV
66.8 MW Load
STMARIES 48417 I Dropped 0.95
A6
N-1: Burke-Pine Creek#3 115 kV Open @ BUR+T-1: Benewah 230/115 kV
66.8 MW Load
STMARIES 48417 Dropped 0.95
N-1: Burke-Pine Creek#3 115 kV Open @ PIN+T-1: Benewah 230/115 kV
66.8 MW Load
STMARIES 48417 I Dropped 0.95
N-1: Burke-Pine Creek#4 115 kV Open @ PIN+T-1: Benewah 230/115 kV
66.8 MW Load
STMARIES 48417 I Dropped 0.95
N-1: Burke-Thompson Falls B 115 kV Open @ BUR+T-1: Benewah
230/115 kV
66.8 MW Load
STMARIES 48417 Dropped 0.95
N-1:Coeur dAlene 15th St-Pine Creek 115 kV Open @ CDA+T-1: Benewah
230/115 kV
66.8 MW Load
STMARIES 48417 Dropped 0.95
Table 13: Heavy Winter Steady State Contingency Results
3.6.3. 2026 Light Spring Scenario
Steady state analysis using the Light Spring scenario did not identify any new
performance issues for the subject area. The same load loss reliability concern, as with
the Heavy Summer and Heavy Winter scenarios, transpire with the loss of the Benewah
230/115kV Transformer.
3.7. Voltage Stability Analysis
3.7.1 . Power/Voltage (PV) Adequacy
With the necessary network upgrades represented in the model, a Load Ramp PV
Curve analysis was conducted while monitoring all buses in the local area. The PV
curve process automatically solves a sequence of power flows at incremental levels of
power transfer between a source Injection Group and a sink Injection Group. The
source Injection Group, supplying the generation necessary for the incremental load
increase, was configured to be sourced from all generation in WECC. Power transfer of
load in the Coeur D'Alene and Palouse areas was incrementally increased, while
performing contingency analysis for a pre-defined set of contingencies at each load
increment, until voltage collapse occurred. This process provides the resulting PV Curve
as shown in Figure 12. Analysis was performed assuming the 115kV transmission line
is closed through from Benewah to Pine Creek.
Any breaker failure at Benewah or loss of the Benewah 230/115kV Transformer have a
similar response to increase in load. The most limiting contingency is the R474 breaker
Page 25 of 44

East Coeur d'Alene Lake System Reinforcement 2024
failure at Benewah. Voltage in the area quickly decreased for the breaker failure outage
as load in the area is increased.
0.9T
0- _
091
090
091
09
009
0,87
OBfi
001
0�
n 0.01
OB
BM
0T8
0]1
OB]
0.%
000 1,090 1,300 1,100 1,600 1,000 3,000 �__., _.�_ 3,6W 20W ­.
O.a nnv:coevvamema Palouse
— 50(1 T) — 5.0(ae1n,
—BF:RIfiBBmexeM1-Boultler,BmcxeM1 330I115Trensl0rmer:STM1VRIES_115.0(1811T) -RI]IBmexeM1-Pine Geek.Be---M1 3501115Trenslarmer:STMMIES_1150(1811')
Build Date:December 9,2021
Figure 12: PV Analysis Results
3.7.2. Reactive/Voltage (QV) Stability Analysis
The reactive power and voltage relationship show the sensitivity and variation of bus
voltages with respect to reactive power injections or absorptions. A system is
considered stable, with respect to voltage, if VQ sensitivity is positive for every bus.
Positive reactive margin is an indication of how far a transmission system is from
voltage instability. Low reactive margin (below 200Mvar at any 230kV bus or any
230/115kV source on the low side) is considered marginal and is indicative of potential
system concerns.
Voltage adequacy studies were performed to determine the relative strength of the local
transmission system. Several buses in the area were selected as an injection bus where
reactive load was increased until the voltage collapsed (i.e., the case became
numerically unstable) for each contingency. Analysis was performed assuming the
115kV transmission line is closed through from Benewah to Pine Creek.
The results provided in Table 14 show improved reactive margin in some areas and
very little change in reactive margin in other areas. A notable improvement is made at
the St. Maries bus under the base case. The reactive margin improved from 85Mvar to
almost 152Mvar. The pre-project contingencies at Benewah 115kV bus and the St.
Maries bus result in an outage for the area, therefore no reactive margin was calculated
for these instances.
Reactive Margin
Bus/Contingency Pre-Project Post-Project Percent Change
BENEWAH 115
BASECASE -313.77 -385.09 22.73%
BF:R463 BENEWAH 230 KV SWITCHED SHUNT,BENEWAH 230/115 TRANSFORMER 0 -62.98
BF:R468 BENEWAH-BOULDER,BENEWAH 230/115 TRANSFORMER 0 -63.15
Page 26 of 44

East Coeur d'Alene Lake System Reinforcement 1 2024
Reactive Margin
Bus/Contingency Pre-Project Post-Project Percent Change
BF:R474 BENEWAH-PINE CREEK,BENEWAH 230/115 TRANSFORMER 0 -62.27
BF:R476 BENEWAH-MOSCOW 230,BENEWAH 230/115 TRANSFORMER 0 I -63.22
T-1:BENEWAH 230/115 KV 0 -62.98
BENEWAH 230
BASECASE -1035.17 -1068.58 3.23%
BF:R463 BENEWAH 230 KV SWITCHED SHUNT,BENEWAH 230/115 TRANSFORMER -1168.84 -1160.88 -0.68%
BF:R468 BENEWAH-BOULDER,BENEWAH 230/115 TRANSFORMER -687.1 -682.44 -0.68%
BF:R474 BENEWAH-PINE CREEK,BENEWAH 230/115 TRANSFORMER -958.03 -957.96 -0.01%
BF:R476 BENEWAH-MOSCOW 230,BENEWAH 230/115 TRANSFORMER -944.88 -936.84 -0.85%
T-1:BENEWAH 230/115 KV -1168.84 -1160.88 -0.68%
PINE CRK 115
BASECASE -582.74 1 -619.74 6.35%
BF:R463 BENEWAH 230 KV SWITCHED SHUNT,BENEWAH 230/115 TRANSFORMER -592.58 -528.46 -10.82%
BF:R468 BENEWAH-BOULDER,BENEWAH 230/115 TRANSFORMER -607.35 -553.75 -8.83%
BF:R474 BENEWAH-PINE CREEK,BENEWAH 230/115 TRANSFORMER -471.63 -416.84 -11.62%
BF:R476 BENEWAH-MOSCOW 230,BENEWAH 230/115 TRANSFORMER -608.94 -555.1 -8.84%
T-1:BENEWAH 230/115 KV -615.45 -559.55 -9.08%
PINE CRK 230
BASECASE -754.59 -765.83 1.49%
BF:R463 BENEWAH 230 KV SWITCHED SHUNT,BENEWAH 230/115 TRANSFORMER -804.35 -768.09 -4.51%
BF:R468 BENEWAH-BOULDER,BENEWAH 230/115 TRANSFORMER -782.2 -752.77 -3.76%
BF:R474 BENEWAH-PINE CREEK,BENEWAH 230/115 TRANSFORMER -520.16 -489 -5.99%
BF:R476 BENEWAH-MOSCOW 230,BENEWAH 230/115 TRANSFORMER -810.43 -772.68 -4.66%
T-1:BENEWAH 230/115 KV -824.86M-87.14
-3.84%
STMARIES
BASECASE -85.27 77.91%
BF:R463 BENEWAH 230 KV SWITCHED SHUNT,BENEWAH 230/115 TRANSFORMER 0BF:R468 BENEWAH-BOULDER,BENEWAH 230/115 TRANSFORMER 0BF:R474 BENEWAH-PINE CREEK,BENEWAH 230/115 TRANSFORMER I 0
BF:R476 BENEWAH-MOSCOW 230,BENEWAH 230/115 TRANSFORMER 0 -86.96
T-1:BENEWAH 230/115 KV 1 0 I -87.14
Table 14: QV Analysis Results
3.7.3. Reactive SUDDort Analysi,
Steady state contingency analysis results in low voltage concerns in both the heavy
summer and heavy winter scenarios with the loss of the Benewah 230/115kV
transformer. The star network around Benewah can be rearranged post contingency to
transfer load thus mitigating low voltage concerns. Should future studies or operations
deem load transfers unacceptable, additional analysis was performed to evaluate the
size and optimal location for future capacitors.
The following table shows post contingency reactive support in the area. Various size
capacitor banks were evaluated, considering locations at either O'Gara or Benewah.
Two steps of 6.7Mvar at Benewah is recommended to mitigate post contingency
undervoltage concerns.
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East Coeur d'Alene Lake System Reinforcement 1 2024
SupportOGA @ OGA @ •
P1
T-1: Benewah 230/115 W
BENEWAH 48035 0.94 1 0.959 0.971 0.984 0.967 0.987 1.013
HOPKINS# 47507 0.92 I 942 0.954 0.967 0.949 0.97 0.997
LATAH 48181 0.94 0.956 0.968 0.98 0.963 0.984 1.010
MICA 47509 0.92 943 0.955 0.968 0.951 0.971 0.998
OGARA 48297 0.97 0.983 0.995 1.008 0.983 0.994 1.009
PLUMMER 48323 0.95 0.968 0.979 0.992 0.972 0.988 1.009
ROCKFORD 48367 0.93 0.946 0.959 0.971 0.954 0.975 1.001
SETTERS 47376 0.93 0.945 0.958 0.97 0.953 0.973 0.999
ST MARIES 48417 0.96 0.97 0.982 0.995 0.969 0.981 0.996
TEKOA(48427) 0.94 0.955 0.967 0.98 0.962 0.983 1.009
Table 15: Reactive Support Analysis
3.8. Stability Contingency Analysis
Modifications to the transmission system may impact the transient stability performance
of the transmission system. An analysis is necessary to determine if the completion of
the East Coeur d'Alene Lake System Reinforcement project will introduce new transient
stability issues. Additionally, an analysis can be performed to determine the maximum
clearing time at stations impacted by the project. Analysis was performed assuming the
115kV transmission line is closed through from Benewah to Pine Creek.
3.8.1 . Transient Performance
A high generation, light load scenario where power angles across transmission lines are
relatively large will typically create the highest potential for transient performance
issues. Spring runoff for the hydroelectric facilities in north Idaho and eastern Montana
is the scenario historically studied. Combining spring runoff with high output from
Colstrip and the gas plants at Lancaster and Rathdrum stresses the performance
concerns. The retirement of Colstrip units 1 and 2 has led to a lower probability of
having the high-power angle spreads historically studied. The scenario studied for the
Carlin Bay Station project represents a realistic operating condition.
No new transient performance issues were identified. Figure 13 shows the rotor angle
and real power output trajectory for a fault on the Pine Creek 115kV bus with a
protection system failure contingency. The simulated fault represents one of the larger
impacts to the system for this area but no material changes in performance to the
simulation was observed. The transient performance was equal to or better under
various contingencies in the region.
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East Coeur d'Alene Lake System Reinforcement 2024
Local Generators
90
80
70
60
in 50
$D
rn
v 3°
y 20
10
Q o
`o
p -10
-20
-30
-40
-50
-60
0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30
Time(s)
130
120
110
100
_ so
80
70
r
a
0 50
a
4o v
0
� 20
10 -
0
-10
-20
-30
0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30
Time(s)
PSF:Pine Creek 115 W 3P
PowerWorkl euld lanuary 25,2022
February 24,2022 08:42:56
Figure 13: Transient Response to Fault and PSF at Pine Creek 115kV Bus
3.8.2. Maximum Clearing Times
Simulations defined did not have communication aided protection schemes and the
resulting transient performance was adequate. No further analysis for maximum
clearing times was required for East Coeur d'Alene Lake System Reinforcement project.
3.9. Short Circuit Analysis
Short circuit analysis for a three-phase and single-line-to-ground bus fault was
performed to determine circuit breaker interrupting capacity requirements for expected
fault current at Carlin Bay and O'Gara Stations. Analysis was performed assuming the
115kV transmission line is closed through from Benewah to Pine Creek. New equipment
shall have an interrupting capacity greater than the available fault current at the
stations. The expected available fault current at Carlin Bay Station and Thevenin
equivalent impedance are show in Table 16 and Table 17. The expected available fault
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East Coeur d'Alene Lake System Reinforcement 2024
current and Thevenin equivalent impedance for O'Gara Station are shown in Table 18
and Table 19.
Fromcman
t 1pomnm Three Single Line
Phase to Ground
Fault
115 kV Bus 3065.6 A 1951 A
13 kV Bus 5080.3 A 5498.7 A
Table 16: Expected Carlin Bay Station available fault current
i 115 kV Bus 5.21834+j21.8122 13.306+j59.3829
I 13kVBus 0.12405+j1.61928 0.0489+j1.25277
Table 17: Expected Carlin Bay Station Thevenin Impedance
Location Three Single Line
Phase to Ground
Fault
I115 kV Bus 4947.8 A 3238.3 A
13 kV Bus 5494.3 A 5814.5 A
Table 18: Expected O'Gara Station available fault current
I115 kV Bus 3.67065+j13.4005 6.97164+j35.247
13 kV Bus 0.10184+j1.49815 0.0489+j1.25277
Table 19: Expected O'Gara Station Thevenin Impedance
3.10. Reliability Analysis
Exhaustive reliability metrics are not readily available for Avista's electrical system.
Reliability is therefore discussed in a relative, qualitative manner. However, there are
perceived impacts to reliability with completion of the project.
The Benewah — Pine Creek 115kV Transmission Line is currently operated open
between O'Gara and Plummer. The open point reduces customer exposure to the
transmission line between O'Gara and Pine Creek. With the addition of a switching
station at O'Gara, the Benewah — Pine Creek line will become two separate lines,
O'Gara — Pine Creek 115kV Transmission Line and Benewah — O'Gara 115kV
Transmission Line, increasing reliability to customers in the area.
The Carlin Bay Station will initially have only one 115kV transmission line to the station.
If warranted in the future, increased reliability can be achieved with a second 115kV
transmission line into Carlin Bay, sourced from Blue Creek.
The Carlin Bay Station initial construction will include one 20MVA transformer with two
feeders and an auxiliary feeder position. Following the Distribution Substation Planning
procedure in DP-SPP-01, the Carlin Bay Station will be designed as a Stage 1
configuration and will not include 115kV circuit breakers in the initial construction. Motor
operated switches should be installed, and allocations made for breakers in the future.
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East Coeur d'Alene Lake System Reinforcement 2024
A Stage 2 configuration at Carlin Bay Station will be considered as a future option
should current conditions change.
3.11 . Redlined Scada Variable Limits
Preliminary SCADA Variable Limits (SVL's) are prepared with the intent of identifying
constraints of existing equipment and identifying requirements for new equipment.
3.11 .1 .Feeders
The new feeders at Carlin Bay and new O'Gara Station are expected to have a
minimum 512A rating at 400C ambient temperature. The new feeders at the stations will
have an expected winter SVL rating of 668 amps.
The existing feeders at Blue Creek Station and O'Gara Station will not have a change to
their facility ratings.
CARLIN BAY-COEUR D'ALENE,IDAHO--13.2kV FDR CBY641, CBY642
(via 115-13.8kV XFMR NO.1)
LOCATION DEVICE TYPE RATING(A) AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS
V.C.B. FVR 1200 1200 1200 1200 1200 1200 1200 1200 1200 1094
CURRENT XFMR 1200/5 M.R. coon.800/5(TRF=1.33) 1064 1064 1064 1064 1064 1064 1064 1064 1064
DISCONN.SW. S&C SPST(B02) 600 1070 1018 963 905 842 775 701 618 522
S&C SPTT(B02) 600 1070 1018 963 905 842 775 701 618 522
CONDUCTOR 1000 MCM CU(75°C) 1862 1763 1653 1534 1420 1293 1150 983 778
500 MCM CU(75-C) 1222 1157 1087 1010 936 853 761 654 523
PROTECTION SEL 351S 2400 2400 2400 2400 2400 2400 2400 2400 2400 2400
(50P1P) 1104 1104 1104 1104 1104 1104 1104 1104 1104
(50P2P) 1104 1104 1104 1104 1104 1104 1104 1104 1104
5%VOLT.REG. 250KVA 525 668 668 668 668 668 643 590 512 433
-------(7.5%) MAX CURRENT= 394 561 561 561 561 522 482 443 384 325
-------(10%) 668 A 328 467 467 467 467 435 402 369 320 271
DISTRIBUTION LINE 556 AAC"D.M."(80°C) 1059 1006 948 886 825 759 685 601 502
643 600 512" ON.
*NOTE: FOR SYSTEM CURRENT LIMITS,IT IS ASSUMED THAT VOLTAGE REGULATORS ARE OPERATING WITHIN A RANGE OF 5%BUCK TO 5%BOOST,
AMPACITY LIMITS FOR THE RANGES OF(+/-)7.5%AND(+/-)10%,HOWEVER,HAVE ALSO BEEN LISTED TO AID ACTUAL OPERATING DECISIONS.
Figure 14: Expected Carlin Bay Feeder SVL
OGARA-COEUR D'ALENE,ID-- 13.2kV FDR 611
(via 115-13.8KV XFMR NO. 1)
LOCATION DEVICE TYPE RATING(A) AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS
V.C.B. FVR 1200 1200 1200 1200 1200 1200 1200 1200 1200 1094
CURRENT XFMR 120015 M.R. conn.800/5(TRF=1.33) 1064 1064 1064 1064 1064 1064 1064 1064 1064
DISCONN.SW. S&C SPST(B02) 600 1070 1018 963 905 842 775 701 618 522
S&C SPTT(B02) 600 1070 1018 963 905 842 775 701 618 522
CONDUCTOR 1000 MCM CU(75°C) 1862 1763 1653 1534 1420 1293 1150 983 778
500 MCM CU(75-C) 1222 1157 1087 1010 936 853 761 654 523
PROTECTION SEL 351S 2400 2400 2400 2400 2400 2400 2400 2400 2400 2400
(50P1P) 1104 1104 1104 1104 1104 1104 1104 1104 1104
(50P2P) 1104 1104 1104 1104 1104 1104 1104 1104 1104
5%VOLT.REG. 250KVA 525 668 668 668 668 668 643 590 512 433
-------(7.5%) MAX CURRENT= 394 561 561 561 561 522 482 443 384 325
-------(10%) 668 A 328 467 467 467 467 435 402 369 320 271
DISTRIBUTION LINE 556 AAC"D.M."(80°C) 1059 1006 948 886 825 759 685 601 502
YSTEM:CURRENT..!MtT:FORSPEGIFkCIEMRERAT.URE ;:i'. .i?! .:'> ..'> .668 . '>668. .668. .668>:i. 668..>::643 S90 5121' 433'
*NOTE: FOR SYSTEM CURRENT LIMITS,IT IS ASSUMED THAT VOLTAGE REGULATORS ARE OPERATING WITHIN A RANGE OF S%BUCK TO 5%BOOST.
AMPACITY LIMITS FOR THE RANGES OF(+/-)7.5%AND(+/-)10%,HOWEVER,HAVE ALSO BEEN LISTED TO AID ACTUAL OPERATING DECISIONS.
Figure 15: Expected O'Gara Feeder SVL
3.11 .2.Transformers
The new transformers at O'Gara and Carlin Bay will have an expected SVL of 29.3 MVA
(20 MVA nominal) at 0°C ambient temperature.
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East Coeur d'Alene Lake System Reinforcement 2024
The existing transformer at Blue Creek Station will not have a change to its facility
ratings.
CARLIN BAY-COEUR D'ALENE,IDAHO--115-13.8kV XFMR NO. 1
(and ASSOCIATED 115& 13.8kV BUSES)
LOCATION DEVICE TYPE RATING(Amps.) AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS
PRIMARY SIDE XFMR AIR SWITCH USCO AGCH5V-11512(D06) 1200 1915 1843 1768 1689 1607 1520 1417 1294 1157
CKT.SWR.A-# S&C 2030 1200 1200 1200 1200 1200 1200 1200 1200 1200 1094
CONDUCTOR 3"AL Pipe(85"C) 3591 3432 3262 3079 2879 2659 2414 2133 2000
2"AL Pipe(850C) 2196 2099 1995 1883 1762 1629 1481 1313 1114
CURRENT XFMR 120015 M.R. conn.600/5(TRF=1) 600 600 600 600 600 600 600 600 600
(55/65°C) XFMR OA/FA/FOA 112 147 147 147 147 140 133 124 114 102
22400000 115500
LOCATION DEVICE TYPE RATING(Amps.) AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS
PRIMARY SIDE XFMR AIR SWITCH USCO AGCH5V-11512(D06) 10043 16028 15425 14797 14136 13450 12722 11860 10830 9684
CKT.SWR.A-# S&C 2030 10043 10043 10043 10043 10043 10043 10043 10043 10043 9156
(@ 13kV) CONDUCTOR 3"AL Pipe(85°C) 30055 28724 27302 25770 24096 22255 20204 17852 16739
2"AL Pipe(850C) 18380 17568 16697 15760 14747 13634 12395 10989 9324
CURRENT XFMR 1200/5 M.R. 5022 5022 5022 5022 5022 5022 5022 5022 5022
SECONDRY SIDE XFMR DISCONNECT SW ROYAL VT1520(D06) 2000 3192 3071 2946 2815 2678 2533 2362 2157 1929
CONDUCTOR 2"Al.Pipe(85°C) 2196 2099 1995 1883 1762 1629 1481 1313 1114
CURRENT XFMR GE JCW-5 1200/5 S.R. conn.1200/5(TRF=1.33) 1596 1596 1596 1596 1596 1596 1596 1596 1596
2000/5 M.R. coon.1200/5(TRF=1.33) 1596 1596 1596 1596 1596 1596 1596 1596 1596
(55/65°C) XFMR CA/FA/FOA r 937 1228 1228 1228 1228 1171 1115 1040 956 853
22400000 13800
Figure 16: Expected Carlin Bay Transformer SVL
OGARA-COEUR D'ALENE,ID--115-13.8kVXFMR NO. 1
(and ASSOCIATED 115& 13.8kV BUSES)
LOCATION DEVICE TYPE RATING(Amps.) AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS
PRIMARY SIDE XFMR AIR SWITCH USCG AGCH5V-11512(D06) 1200 1915 1843 1768 1689 1607 1520 1417 1294 1157
CKT.SWR.A-# S&C 2030 1200 1200 1200 1200 1200 1200 1200 1200 1200 1094
CONDUCTOR 3"AL Pipe(85°C) 3591 3432 3262 3079 2879 2659 2414 2133 2000
2"AL Pipe(85°C) 2196 2099 1995 1883 1762 1629 1481 1313 1114
CURRENT XFMR 120015 M.R. conn.600/5(TRI 600 600 600 600 600 600 600 600 600
(55/65°C) XFMR OA/FA/FOA 1 112 147 147 147 147 140 133 124 114 102
22400000 115500
LOCATION DEVICE TYPE RATING(Amps.) AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS
PRIMARY SIDE XFMR AIR SWITCH USCG AGCHSV-11512(D06) 10043 16028 15425 14797 14136 13450 12722 11860 10830 9684
CKT.SWR.A-# S&C 2030 10043 10043 10043 10043 10043 10043 10043 10043 10043 9156
(@ 131,V) CONDUCTOR 3"AL Pipe(85°C) 30055 28724 27302 25770 24096 22255 20204 17852 16739
2"AL Pipe(85°C) 18380 17568 16697 15760 14747 13634 12395 10989 9324
CURRENT XFMR 120D/5 M.R. 5022 5022 5022 5022 5022 5022 5022 5022 5022
SECONDRY SIDE XFMR DISCONN.SW. ROYAL VT1520(DO6) 2000 3192 3071 2946 2815 2678 2533 2362 2157 1929
CONDUCTOR 2"Al.Pipe(85°C) 2196 2099 1995 1883 1762 1629 1481 1313 1114
CURRENT XFMR GE JCW-5 1200/5 S.R. corm.1200/5(TRF=1.33) 1596 1596 1596 1596 1596 1596 1596 1596 1596
200015 M.R. onn.1200/5(TRF=1.33) 1596 1596 1596 1596 1596 1596 1596 1596 1596
(55/65°C) XFMR CA/FA/FOA r 937 1228 1228 1228 1228 1171 1115 1040 956 853
22400000 13800
Figure 17: Expected O'Gara Transformer SVL
3.11 .3.Trans mission Lines
Phase one reinforcements include the new Carlin Bay— O'Gara 115kV Transmission
Line which will have minimum 239MVA rating. New station equipment for phase one at
O'Gara and Carlin Bay should have standard 2000A ratings. The Benewah — Pine
Creek 115kV line will have no changes to the SVL ratings for phase one.
The single SVL for the Benewah — Pine Creek 115kV Transmission Line will be split into
four new SVL spreadsheets with the new O'Gara 115kV Station for phase two.
Proposed SVL's shown below include the following impacted 115kV transmission lines-
• Carlin Bay— O'Gara 115kV Transmission Line
• Benewah — O'Gara 115kV Transmission Line
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East Coeur d'Alene Lake System Reinforcement 2024
• O'Gara — St. Maries 115kV Transmission Line
• O'Gara — Pine Creek 115kV Transmission Line
CARLIN BAY-O'GARA 115kV
A-XXX A-XXX,A-XXX
AMBIENT TEMPERATURE (C)
-30 -20 -10 0 10 20 30 40 50'
LOCATION DEVICE TYPE RATING Am AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS
CARLIN BAY AIR SWITCH (2)USCO AGCH5V-11520(DO6) 2000 3192 3071 2946 2815 2678 2533 2362 2157 1929
(O'GARA LINE)
TRANSMISSION LINE CONDUCTOR 795 ACSS"Drake" 200'C 1864 1816 1777 1736 1699 1660 1620 1578 1s34
O'GARA 115KV SUBSTATION G.C.B.A-XXX SIEMENS SPS2S-145-40-1 2000 3002 2876 2746 2611 2469 2321 2165 2000 1823
(CARLIN BAY LINE) CONDUCTOR 3"AI.Pipe(85°C)" 3591 3432 3262 3079 2879 2659 2414 2133 2000
2 x 1272 kCM AAC"Narcissus"(80'C) 3556 3376 3176 2962 2758 2532 2282 1994 1650
CURRENT XFMR. (2)2000/5 M.R. conn.2000/5(TRF=2) 4000 4000 4000 4000 4000 4000 4000 4000 4000
(2)2000/5 M.R. conn.120015(TRF=2) 2400 2400 2400 2400 2400 2400 2400 2400 2400
AIR SWITCH (2)USCO AGCH5V-11520(D06) 2000 3192 3071 2946 2815 2678 2533 2362 2157 1929
O'GARA 115KV SUBSTATION G.C.B.A-XXX SIEMENS SPS2S-145-40-1 2000 3002 2876 2746 2611 2469 2321 2165 2000 1823
(115kV LINE TIE) CONDUCTOR 3"Al.Pipe(85'C)" 3591 3432 3262 3079 2879 2659 2414 2133 2000
2 x 1272 kCM AAC"Narcissus"(80'C) 3556 3376 3176 2962 2758 2532 2282 1994 1650
CURRENT XFMR. (4)2000/5 M.R. conn.120015(TRF=2) 2400 2400 2400 2400 2400 2400 2400 2400 2400
AIR SWITCH (2)USCO AGCH5V-11520(DO6) 2000 3192 3071 2946 2815 2678 2533 2362 2157 1929
O'GARA 115KV SUBSTATION G.C.B.A-XXX SIEMENS SPS2 2000 3002 2876 2746 2611 2469 2321 2165 2000 1823
(PINE CREEK LINE) CONDUCTOR 3"AI.Pipe(85'C)" 3591 3432 3262 3079 2879 2659 2414 2133 2000
2 x 1272 AAC"Narcissus"(80'C) 3556 3376 3176 2962 2758 2532 2282 1994 1650
CURRENT XFMR. (2)2000/5 M.R. conn.2000/5(TRF=2) 4000 4000 4000 4000 4000 4000 4000 4000 4000
(2)2000/5 M.R. conn.120015(TRF=2) 2400 2400 2400 2400 2400 2400 2400 2400 2400
AIR SWITCH (2)USCO AGCH5V-11520(DO6) 2000 3192 3071 2946 2815 2678 2533 2362 2157 1929
PROTECTION SEL-421(Z1MP) 3600 30881 30881 30881 30881 30881 30881 30881 30881 30881
(Z2MP) 19004 19004 19004 19004 19004 19004 19004 19004 19004
(ZLF) 2447 2447 2447 2447 2447 2447 2447 2447 2447
(50P1) 1920 1920 1920 1920 1920 1920 1920 1920 1920
(67P2)*'* 1920 1920 1920 1920 1920 1920 1920 1920 1920
SEL-311L(Z1P) 3600 30881 30881 30881 30881 30881 30881 30881 30881 30881
(Z2P) 19004 19004 19004 19004 19004 19004 19004 19004 19004
(ZLF) 2447 2447 2447 2447 2447 2447 2447 2447 2447
(50P1) 1920 1920 1920 1920 1920 1920 1920 1920 1920
67P2"' 1920 1920 1920 1920 1920 1920 1920 1920 1920
SYSTEM CURRENT LIMIT FOR SPECIFIC TEMPERATURE 1854 1818 1777 1738.. 1889 ..IND. 1620 1578 1634'
Figure 18: Preliminary Carlin Bay - O'Gara 115kV SVL
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East Coeur d'Alene Lake System Reinforcement 2024
BENEWAH-O'GARA 115kV
A-536 A-XXX,A-XXX
AMBIENT TEMPERATURE (C)
.30 -20 .10 0 10. 20 30 40 50
LOCA71ON DEVICE TYPE RATING Am AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS
BENEWAH SUB. G.C.B.A-536 MITSUBISHI 100SFMT40HEI 2000 3002 2876 2746 2611 2469 2321 2165 2000 1823
(O'GARA LINE) CONDUCTOR 3"Al.Pipe(85'C)" 3591 3432 3262 3079 2879 2659 2414 2133 2000
CURRENT XFMR. (2)2000/5 M.R. conn 800/5(TRF-2) 1600 1600 1600 1600 1600 1600 1600 1600 1600
2000/5 M.R. conn 2000/5(TRF=2) 4000 4000 4000 4000 4000 4000 4000 4000 4000
AIR SWITCH (2)USCO AGCH5V(DO6) 2000 3192 3071 2946 2815 2678 2533 2362 2157 1929
PROTECTION SEL421(ZIMP) 2400 2195 2195 2195 2195 2195 2195 2195 2195 2195
(Z2MP) 1518 1518 1518 1518 1518 1518 1518 1518 1518
(Z4MP) 1458 1458 1458 1458 1458 1458 1458 1458 1458
(ZLF) 690 690 690 690 690 690 690 690 690
(501 584 584 584 584 584 584 584 584 584
(67P2)"' 584 584 584 584 584 584 584 584 584
SEL-311L(Z1 P) 2400 2195 2195 2195 2195 2195 2195 2195 2195 2195
(Z2P) 1518 1518 1518 1518 1518 1518 1518 1518 1518
(ZLF) 762 762 762 762 762 762 762 762 762
(50P1) 584 584 584 584 584 584 584 584 584
67P2"' 584 584 584 584 584 584 584 584 584
TRANSMISSION LINE CONDUCTOR 7#7 CU(80-C) 572 544 513 481 448 413 374 330 278
210 CU 7S(85-C) 549 524 496 466 437 406 371 332 288
551 ACSR"Parakeef'(100`C) 1159 1111 1060 1005 953 896 836 769 695
556.5 AAC"Dahlia"(100°C) 1130 1083 1033 980 929 874 815 750 678
1622 ACSSITW"Pecos"(80"C) 2088 1981 1864 1738 1617 1485 1337 1167 963
AIR SWITCH A-10 USCO AGCH5V(006) 1200 1915 1843 1768 1689 1607 1520 1417 1294 1157
A-11 SIEMENS CBL-2(B02) 1200 2141 2036 1926 1809 1684 1549 1401 1236 1044
A-161 PATTON 8 COOKE V311512 B02 1200 2141 2036 1926 1809 1684 1549 1401 1236 1044
O'GARA 1151KV SUBSTATION G.C.B.A-XXX SIEMENS SPS2S-14540-1 2000 3002 2876 2746 2611 2469 2321 2165 2000 1823
(BENEWAH LINE) CONDUCTOR 3"Al.Pipe(85°C)" 3591 3432 3262 3079 2879 2659 2414 2133 2000
2 x 1272 kCM AAC"Narcissus"(80°C) 3556 3376 3176 2962 2758 2532 2282 1994 1650
CURRENT XFMR. (2)20D0/5 M.R. conn.200015(TRF=2) 4000 4000 4000 4000 4000 4000 4000 4000 4000
(2)20D0/5 M.R. conn.120015(TRF=2) 2400 2400 2400 2400 2400 2400 2400 2400 2400
AIR SWITCH (2)USCO AGCH5V-1 1520(006) 2000 3192 3071 2946 2815 2678 2533 2362 2157 1929
O'GARA 1151KV SUBSTATION G.C.B.A-XXX SIEMENS SPS2S-145-40-1 2000 3002 2876 2746 2611 2469 2321 2165 2000 1823
(115kV LINE TIE) CONDUCTOR 3"Al.Pipe(85'C)" 3591 3432 3262 3079 2879 2659 2414 2133 2000
2 x 1272 kCM AAC"Narcissus"(80°C) 3556 3376 3176 2962 2758 2532 2282 1994 1650
CURRENT XFMR. (4)20D0/5 M.R. conn.120015(TRF=2) 2400 2400 2400 2400 2400 2400 2400 2400 2400
AIR SWITCH (2)USCO AGCH5V-1 1520(006) 2000 3192 3071 2946 2815 2678 2533 2362 2157 1929
O'GARA 115KV SUBSTATION G.C.B.A-XXX SIEMENS SPS2 2000 3002 2876 2746 2611 2469 2321 2165 2000 1823
(ST.MARIES LINE) CONDUCTOR 3"Al.Pipe(85"C)" 3591 3432 3262 3079 2879 2659 2414 2133 2D00
2 x 1272 AAC"Narcissus"(80'C) 3556 3376 3176 2962 2758 2532 2282 1994 1650
CURRENT XFMR. (2)200015 M.R. conn.200015(TRF=2) 4000 4000 4000 4000 4000 4000 4000 4000 4D00
(2)20D0/5 M.R. conn.120015(TRF=2) 2400 2400 2400 2400 2400 2400 2400 2400 2400
AIR SWITCH (2)USCO AGCH5V-11520(DO6) 2000 3192 3071 2946 2815 2678 2533 2362 2157 1929
PROTECTION SEL-421(Z1MP) 3600 30881 30881 30881 30881 30881 30881 30881 30881 30881
(Z2MP) 19004 19004 19004 19004 19004 19004 19004 19004 19004
(ZLF) 2447 2447 2447 2447 2447 2447 2447 2447 2447
(501 1920 1920 1920 1920 1920 1920 1920 1920 1920
(67P2)"' 1920 1920 1920 1920 1920 1920 1920 1920 1920
SEL-311L(Z1 P) 3600 30881 30881 30881 30881 30881 30881 30881 30881 30881
(Z2P) 19004 19004 19004 19004 19004 19004 19004 19004 19004
(ZLF) 2447 2447 2447 2447 2447 2447 2447 2447 2447
(50P1) 1920 1920 1920 1920 1920 1920 1920 1920 1920
67P2-'- 1920 1920 1920 1920 1920 1920 1920 1920 1920
SYSTEM CURRENT LIMIT FOR SPECIFIC TEMPERATURE 549 524 496 466 437 406 371 330 278
Figure 19: Preliminary Benewah - O'Gara 115V SVL
Page 34 of 44

East Coeur d'Alene Lake System Reinforcement 2024
O'GARA-ST. MARIES 115kV
A-XXX,A-XXX A-295
AMBIENT TEMPERATURE (C)
-30 -20 -10 0 10 20 30 40 50.
LOCATION DEVICE TYPE RATING Am AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS
O'GARA 115KV SUBSTATIOI G.C.B.A-XXX SIEMENS SPS2S-145-40-1 2000 3002 2876 2746 2611 2469 2321 2165 2000 1823
(ST MARIES LINE) CONDUCTOR 3"AI.Pipe(85'C)" 3591 3432 3262 3079 2879 2659 2414 2133 2000
2 x 1272 kCM AAC"Narcissus"(80`C) 3556 3376 3176 2962 2758 2532 2282 1994 1650
CURRENT XFMR. (2)200015 M.R. Conn.2000/5(TRF=2) 4000 4000 4000 4000 4000 4000 4000 4000 4000
(2)200015 M.R. conn.1200/5(TRF=2) 2400 2400 2400 2400 2400 2400 2400 2400 2400
AIR SWITCH (2)USCO AGCH5V-11520(DO13) 2000 3192 3071 2946 2815 2678 2533 2362 2157 1929
O'GARA 115KV SUBSTATIOI G.C.B.A-XXX SIEMENS SPS2S-14540-1 2000 3002 2876 2746 2611 2469 2321 2165 2000 1823
(115kV LINE TIE) CONDUCTOR 3"AI.Pipe(85°C)" 3591 3432 3262 3079 2879 2659 2414 2133 2000
2 x 1272 kCM AAC"Narcissus"(80'C) 3556 3376 3176 2962 2758 2532 2282 1994 1650
CURRENT XFMR. (4)2000/5 M.R. conn.1200/5(TRF=2) 2400 2400 2400 2400 2400 2400 2400 2400 2400
AIR SWITCH (2)USCO AGCHSV-11520(D06) 2000 3192 3071 2946 2815 2678 2533 2362 2157 1929
O'GARA 115KV SUBSTATIOFG.C.B.A-XXX SIEMENS SPS2 2000 3002 2876 2746 2611 2469 2321 2165 2000 1823
(BENEWAH LINE) CONDUCTOR 3"AI.Pipe(85'C)" 3591 3432 3262 3079 2879 2659 2414 2133 2000
2 x 1272 AAC"Narcissus"(80'C) 3556 3376 3176 2962 2758 2532 2282 1994 1650
CURRENT XFMR. (2)200015 M.R. conn.2000/5(TRF=2) 4000 4000 4000 4000 4000 4000 4000 4000 4000
(2)200015 M.R. conn.1200/5(TRF=2) 2400 2400 2400 2400 2400 2400 2400 2400 2400
AIR SWITCH (2)USCO AGCH5V-11520(DO6) 2000 3192 3071 2946 2815 2678 2533 2362 2157 1929
PROTECTION SEL421(Z1MP) 3600 30881 30881 30881 30881 30881 30881 30881 30881 30881
(Z2MP) 19004 19004 19004 19004 19004 19004 19004 19004 19004
(ZLF) 2447 2447 2447 2447 2447 2447 2447 2447 2447
(50P1) 1920 1920 1920 1920 1920 1920 1920 1920 1920
(67P2)"' 1920 1920 1920 1920 1920 1920 1920 1920 1920
SEL-311L(Z1 P) 3600 30881 30881 30881 30881 30881 30881 30881 30881 30881
(Z2P) 19004 19004 19004 19004 19004 19004 19004 19004 19004
(ZLF) 2447 2447 2447 2447 2447 2447 2447 2447 2447
(50P1) 1920 1920 1920 1920 1920 1920 1920 1920 1920
67P2"' 1920 1920 1920 1920 1920 1920 1920 1920 1920
TRANSMISSION LINE CONDUCTOR 2/0 ACSR"Quail"(80°C) 412 392 370 346 323 297 269 238 200
ST.MARIES SUB AIR SWITCH A-295 1200 1915 1843 1768 1689 1607 1520 1417 1294 1157
(O'GARA LINE)
SYSTEM CURRENT LIMIT FOR SPECIFIC TEMPERATURE 412 392 370 348 323 297 289 238 200
Figure 20: Preliminary O'Gara - St. Maries 115kV SVL
Page 35 of 44

East Coeur d'Alene Lake System Reinforcement 2024
O'GARA -PINE CREEK 115kV
A-XXX,A-XXX A-292
AMBIENT TEMPERATURE (C)
-20 -1^ 0 10 20 �0 50
LOCATION DEVICE TYPE RATING(Amps.) AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS AMPS
O'GARA 115KV SUBSTATI(G.C.B.A-XXX SIEMENS SPS2S-145-40-1 2000 3002 2876 2746 2611 2469 2321 2165 2000 1823
(PINE CREEK LINE) CONDUCTOR 3"Al.Pipe(85'C)"" 3591 3432 3262 3079 2879 2659 2414 2133 2000
2 z 1272 kCM AAC"Narcissus"(80'C) 3556 3376 3176 2962 2758 2532 2282 1994 1650
CURRENT XFMR. (2)200015 M.R. coon.2000/5(TRF=2) 4000 4000 4000 4000 4000 4000 4000 4000 4000
(2)200015 M.R. coon.1200/5(TRF=2) 2400 2400 2400 2400 2400 2400 2400 2400 2400
AIR SWITCH (2)USCO AGCH5V-11520(DO6) 2000 3192 3071 2946 2815 2678 2533 2362 2157 1929
O'GARA 115KV SUBSTATI(G.C.B.A-XXX SIEMENS SPS2S-14540-1 2000 3002 2876 2746 2611 2469 2321 2165 2000 1823
(115kV LINE TIE) CONDUCTOR 3"Al.Pipe(85'C)" 3591 3432 3262 3079 2879 2659 2414 2133 2000
2 a 1272 kCM AAC"Narcissus"(80'C) 3556 3376 3176 2962 2758 2532 2282 1994 1650
CURRENT XFMR. (4)200015 M.R. corn.120015(TRF=2) 2400 2400 2400 2400 2400 2400 2400 2400 2400
AIR SWITCH (2)USCO AGCH5V-11520(DO6) 2000 3192 3071 2946 2815 2678 2533 2362 2157 1929
O'GARA 115KV SUBSTATI(G.C.B.A-XXX SIEMENS SPS2 2000 3002 2876 2746 2611 2469 2321 2165 2000 1823
(CARLIN BAY LINE) CONDUCTOR 3"Al.Pipe(85'C)" 3591 3432 3262 3079 2879 2659 2414 2133 2000
2 x 1272 AAC"Narcissus"(80"C) 3556 3376 3176 2962 2758 2532 2282 1994 1650
CURRENT XFMR. (2)200015 M.R. coon.2000/5(TRF=2) 4000 4000 4000 4000 4000 4000 4000 4000 4000
(2)200015 M.R. coon.120015(TRF=2) 2400 2400 2400 2400 2400 2400 2400 2400 2400
AIR SWITCH (2)USCO AGCH5V-11520(DO6) 2000 3192 3071 2946 2815 2678 2533 2362 2157 1929
PROTECTION SEL421(Z1MP) 3600 30881 30881 30881 30881 30881 30881 30881 30881 30881
(Z2MP) 19004 19004 19004 19004 19004 19004 19004 19004 19004
(ZLF) 2447 2447 2447 2447 2447 2447 2447 2447 2447
(50P1) 1920 1920 1920 1920 1920 1920 1920 1920 1920
(67P2)"" 1920 1920 1920 1920 1920 1920 1920 1920 1920
SEL-311L(Z1P) 3600 30881 30881 30881 30881 30881 30881 30881 30881 30881
(Z2P) 19004 19004 19004 19004 19004 19004 19004 19004 19004
(ZLF) 2447 2447 2447 2447 2447 2447 2447 2447 2447
(50P1) 1920 1920 1920 1920 1920 1920 1920 1920 1920
67P2'"' 1920 1920 1920 1920 1920 1920 1920 1920 1920
TRANSMISSION LINE CONDUCTOR 413.7 ACSR/AW"Ids"(100'C) 1010 969 924 877 831 782 729 671 607
556.5 ACSR"Parakeet' 100°C 1159 1111 1060 1005 953 896 836 769 695
PINE CREEK SUB. G.C.B.A-292 MITSUBISHI 100SFMT40E 2000 3002 2876 2746 2611 2469 2321 2165 2000 1823
(O'GARA LINE) CONDUCTOR 2"AI.Pipe(85'C) 2196 2099 1995 1883 1762 1629 1481 1313 1114
3"Al.Pipe(85"C)'" 3591 3432 3262 3079 2879 2659 2414 2133 2000
(2)1272 AAC"Narcissus"(80"C) 3556 3376 3176 2962 2758 2532 2282 1994 1650
CURRENT XFMR. (2)200015 M.R. corm 1200/5(TRF=2) 2400 2400 2400 2400 2400 2400 2400 2400 2400
2000/5 M.R. coon 200015(TRF=2) 4000 4000 4000 4000 4000 4000 4000 4000 4000
AIR SWITCH (2)WEST RL(802) 600 1070 1018 963 905 842 775 701 618 522
PROTECTION SEL-321(Z1MP) 3600 2194 2194 2194 2194 2194 2194 2194 2194 2194
(Z2MP) 1853 1853 1853 1853 1853 1853 1853 1853 1853
(Z4MP) 1498 1498 1498 1498 1498 1498 1498 1498 1498
(ZLF) 1145 1145 1145 1145 1145 1145 1145 1145 1145
(50H) 1824 1824 1824 1824 1824 1824 1824 1824 1824
(50MF)"" 1200 1200 1200 1200 1200 1200 1200 1200 1200
SEL-321(Z1MP) 3600 2194 2194 2194 2194 2194 2194 2194 2194 2194
(Z2MP) 1806 1806 1806 1806 1806 1806 1806 1806 1806
(Z3MP) 1498 1498 1498 1498 1498 1498 1498 1498 1498
(ZLF) 1145 1145 1145 1145 1145 1145 1145 1145 1145
(50H) 1824 1824 1824 1824 1824 1824 1824 1824 1824
(50MF)"" 1200 1200 1200 1200 1200 1200 1200 1200 1200
SEL-351 50BF)"- 3600 3600 3600 3600 3600 3600 3600 3600 3600 3600
SYSTEM CURRENT UMIT'FOR'SPECIFIC TEMPERATURE _1010 969 924 877 831 776 701 618 ' 627
Figure 21: Preliminary O'Gara - Pine Creek 115kV SVL
4. Stakeholder Acknowledgement
The Avista stakeholders listed in Table 20 have acknowledged they were informed and
consulted during the development of the proposed project.
Function Name 1.
Substation Engineering Brian Chain 12/5/2024
Transmission Engineering Ken Sweigart 12/5/2024
Distribution Engineering Marshall Law 12/5/2024
Protection Engineering Kevin Damron 12/5/2024
Project Delivery Katie Pru h 12/5/2024
SCADA/EMS Craig Fi art 1/13/2025
Transmission Operations Rich H dzik 1/14/2025
Distribution Operations Kaitl n Richardson/Jill Ham 1/13/2025
Network Engineering - -
Table 20: Avista stakeholder acknowledgement
Page 36 of 44

East Coeur d'Alene Lake System Reinforcement 2024
5. Appendix
5.1 . Project Alternatives
The following information provides the technical analysis results for alternatives
considered. The body of the report contains the preferred alternative to address the
performance issues identified in the problem statement. Providing the alternative
technical analysis results is intended to be informative to System Planners and
demonstrate, in part, how the preferred alternative was selected.
5.1 .1 . Do Nothinr
The expected system performance if no mitigation alternatives are executed were
previously discussed in the Problem Statement in Section 1. 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 station regulators). Providing sufficient voltage regulation is already a
challenge and will become more difficult as load continues to increase. Represented
below are 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 recorded on 1/13/2024. 80T trunk fuses melted
under heavy loading conditions and required 100T fuses to be temporarily
installed to serve load. 100T fuses do not coordinate with midline recloser
settings.
• The winter peak load on 1/14/2024 was 500A.
• Using 500A as a potential pre-outage load, the cold load pickup is expected to be
2.5 x 500A = 1250A. The cold load pickup surpasses the phase pickup setting of
600A for the ZC150R.
The following data was recorded for the OGA611 feeder.
• The winter peak load on 1/13/2024 was 215A.
• Using 215A as a potential pre-outage load, the cold load pickup is expected to be
2.5 x 215A = 537.5A. The potential cold load pickup is more than the phase
pickup of 420A for ZC613R.
The "do nothing" alternative is not valid for the East Coeur d'Alene Lake System
Reinforcement project as protection challenges will continue to increase as load in the
area increases.
5.1 .2. Increase Distribution Voltag(c
Distribution voltage for BLU321 and OGA611 could be increased from 13.8kV, as it
operates today, to 25kV. This option 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. This alternative would not address the 10MVA capacity limit of Avista feeders.
Page 37 of 44

East Coeur d'Alene Lake System Reinforcement 2024
This alternative will address the protection challenges however the significant cost of
this option has deemed the option invalid.
5.1 .3. marlin Bay Station with Tap from O'Gara
A new Carlin Bay Station could be fed from a tap of the Benewah — Pine Creek 115kV
Transmission Line near O'Gara. This option would reduce modifications needed at
O'Gara to just distribution upgrades, thus reducing the overall cost of the project by
almost $10 million. Alternatively, this option increases customer exposure to outages on
the Benewah — Pine Creek 115kV line thus reducing customer reliability in the area. SP-
SPP-02 Facility Interconnection Requirements requires circuit breakers be installed for
tap lines greater than 50% of the existing line length. This is intended to minimize line
exposure to existing customers. The proposed Carlin Bay — O'Gara Transmission Line
exceeds the 50% line-length requirement.
>.1 .4. Carlin Bay Station with O'Gara Switching Station
In addition to 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 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 increased reliability. Equipment
condition concerns at O'Gara are also alleviated with implementation of this option.
Based on benefits described above, a rebuild of the O'Gara Station is the preferred
option therefore the report was developed, and analysis performed based on this option.
5.1 .5. Star Point Configuratiu„ vvith O'Gara Switching Station
The star point configuration at the O'Gara Station was considered in the analysis of the
East Coeur d'Alene Lake System Reinforcement project. Currently the system is
operated with the Benewah — Pine Creek 115kV line section open to reduce customer
exposure to outages. If the Benewah — Pine Creek 115kV line remains normally open,
the resulting Benewah 230/115kV Transformer outage results in 53.8MW of dropped
load in the Heavy Summer scenario and 66.8MW of dropped load in the Heavy Winter
scenario.
Assuming the O'Gara Station will be re-built to a switching station, the customer
exposure concern on the Benewah — Pine Creek 115kV line can be eliminated if the star
point is removed and the Benewah — Pine Creek 115kV line is closed. Under this
configuration, a new P1 voltage performance concern develops in the area based on
our loading assumptions. There are several mitigation options to address this concern
under heavy loading conditions.
• Adjust star point at Garfield to transfer load to Moscow.
• Adjust star point at Latah Tap to transfer load to Ninth & Central.
• Install reactive support at Benewah on the 115kV system.
• Install reactive support at O'Gara on the 115kV system.
• Install a second 230/115 kV Autotransformer at Benewah.
Page 38 of 44

East Coeur d'Alene Lake System Reinforcement 2024
The report was developed, and analysis was performed with both open and closed
configurations for the Benewah — Pine Creek 115kV Transmission Line.
Page 39 of 44

East Coeur d'Alene Lake System Reinforcement 2024
5.2. Distribution Integration
Carlin Bay distribution integration buildout by year - Marshall Law 2024
­54.• v p CDA Lake Crossing-Construction planned for2025
WP
In.. 0 tf}i1000CN15
S ,y - —w-
22 VROM Budgetary Estimate-$625k(Ot Reinf)
s• q
sr 6.111111
� I
Recloserit ZC999R
Fume Normal Open Localim,-
'+ South of Gocter Gi - Moscow Bay-C st cmn planned for 2024
(8.1 mi from sub) / soavci n CPC Jason Stippich
SOLID Doors(Pole#032813) _ Replace 3 600'of 3-35OCN15 with 3-1000CN 15,
CUTOUTSR C1016 `.'ROM Budgetary krstr Estimate-$375(D Reinf)
SOLID Doors
I
i 4
A
CUTOUTStC1015 � -
80T Fusee Burma Road
-Design in 2026(TB.D.)
• -..- -Constmction in 2027
Reonnfgure ked to Burma Road
VROM Budgetxy,Estimate-$1Wk
A SOLID Doors(Pokes 033205)
S 2027 Viper Redcsers ZC1014R f
(3.1 mi from sub) Ixud W laiBMa
z025J Gan os Lane f1.1wi
-Design in 2024(McCauley)
-Constmcfion in 2025
Recondudor3,200'of344ACSR to3-556AA0
':'RnM Budgetary Estimate-$350k gage l3 Road
_r -Design in 20242025(TBD) -
-Construction in 2026 -
2027 Cadin Cove : Construct new double circus line
-Design in 20242025(TBD) )! 3000E of 3-556AAC 14-556AAC
_ -Consbuction in 2027 800E of 3-S6AAC
Recond,dor 4,000'of 3-#4ACSR to 3-556AAC 500E of 3-1000CNIS 60DA UG
VROM Budgetary Estimate-$4001, VROM Budgetary Estimate-$5001,
—s Martin Point- 2027 Carlin Bay Sub-Feeder Exits .. .
- -Design in 2024(Jason Stippich) -Design in 2025/2026(Marshall L:::,
-Construction in 2025 HOG Swrk fh#C1013 -Construction in 2027
- Reconductor 7000'of 244ACSR to 3-556AAC ..
VROM Budgetary Estimate-$650k VROM BWgetary Estimate-$200k -
i New Cad in Bay Feeder Configuration,.
Switch#C644 Carlin Bay Sub CBY641-Tap Circuit
g 115-13.2W 3-556 AAC
(2)13.2kV Feeders -NoM Feeder(toward Go—er)
y CBY642-Bottom Circuit
4-556 AAC-But Ckt&NIT
'
__ -South Feeder(toward Harrison) _
eon Vi r Redoser#ZC645R
PQ
(3.8 mifrom sub)
ena of 556— r �P.2 in,
I
Fix
SOLID Doors C646 l"
., cal �•
ois�o�nea�r c61aD x cfiuD
6oT Fnses ps`s "�•'
Powd rh Constmobon planned for 20" "4
CPC Unassigned
second d 10,30(Y f342ACSR to3-210ACSP
Shared line with KEC
VROM Budgetary Est—u,-$5001r(Distr Reif) Ston Road Construcuonin2024
CPCA fined:(Jason Stipich
;,. Rea d 4000E of 342ACSR to}2/OACSR and}350CN 1-
Shared line
with KEC
Budgelary Estimate-5300k IDisVitiuLon Reinforcement)
zcei:%�oa I
• R #Z_618R "
Fit Finus N rat Opel Locat'o" LIL ter:t.6�4
E f He,.iso
R°nur 07-10 2024 I inch=3,000feet Carlin Bay Sub - Distribution Integration
Route To:Marshall Law
Page 40 of 44

East Coeur d'Alene Lake System Reinforcement 2024
Name BLU321 Lake Crossing Cable
Location Higgins Point to Moscow Bay(Lake Coeur d'Alene)
Normal feeder BLU321
Alternate feeder None
Special Conditions The main feeder trunk of BLU321 crosses the Wolf Lodge arm of Lake Coeur
d'Alene between Higgins Point and the mouth of Beauty Bay underwater, and
then continues as underground cable to its 600A riser near Moscow Bay.
The cable is 350CN15 and the majority was installed in 1992 as direct buried
cable. There is one section that was installed later in 2008 and is in 3-3"
conduit.
Given the critical nature of this section of cable. along with the high loading
levels experienced on this feeder during winter peak conditions, soil
resistivity analysis was performed in 2023 as part of an effort to develop
more refined cable rating values. The following chart summarizes the
calculated winter and summer rating values at 3 separate locations along the
overland cable route. Note that the rating of the cable installed in the lake
itself is assumed to be a higher ampacity than the sections of cable installed
in soil, and as such is not considered to be a limiting factor with the current
configuration.
Winter Rating Summer Rating
(0 deg C ambient) 40 deg C ambient
Cable Section#3 in 2"conduit 440 A 387 A
Cable Section#5(Direct Bury) 560 A 490 A
Cable Section#7(Direct Bury) 422 A 369 A
With the given topology of the feeder, and the fact there is very little load
between the C966D disconnects(600A riser at Cable Section#7) and the
ZC150R midline recloser, a reasonable "worse case" approximation for
loading on the cable is to assume the loading levels observed at ZC150R is
equal to the loading at Cable Section#7. If cable loading levels reach 95%of
the Section#7 rating(400 A for winter or 350 A for summer), then a
contingency plan should be developed to reduce loading below the 95%
levels. Potential contingency options for shedding load would include
temporarily de-energizing customers on the following 1-ph laterals,
depending on which phase(s)were exceeding the rating:
• A-phase: 80T Fuse at Pole#026495 on Arrow Road
Approximately 30 A-this will de-energize 52 customers
• B-phase: 50T Fuse at Pole#026251 at Gozzer& Burma Roads
Approximately 40 A—this will de-energize 55 customers
• C-phase: 80T Fuse at Pole#433473 on Eddyville Road
Approximately 35 A—this will de-energize 135 customers
The load shed plan should not be executed until the loading level measured
at ZC150 reaches 100%of the Cable Section #7 rating, i.e. 422 A on any
phase for winter loading. Prior to executing on a contingency load shed.the
particular loading scenario should be analyzed with SynerGi if possible.to
confirm the identified contingency plan is anticipated to fully address the
loading concerns.
SPECIAL CONDITIONS BLU321 Lake DATE 3/5/2024
!t Crossing Cable PAGE 1 of 2
,dir-4� ISTA Utilities
SPEC SC-CDA-24-001
Page 41 of 44

East Coeur d'Alene Lake System Reinforcement 2024
Special Conditions (continued)
If the elevated loading levels observed at ZC150R are a result of cold load
pickup after a sustained outage downstream of that recloser, then the cable's
emergency rating will allow for exceeding the 422 A rating up to as high as
485 A as long as it is for a short duration. If the cold load pickup loading
hasn't dropped below 422 A within 30 minutes of the outage restoration. then
a load shed contingency plan should be pursued as described above.
The de-energized customers should have their power restored as soon as the
loading level at ZC150R has decreased to a point where the projected load
restoration will not exceed the 422 A winter rating for more than 30 minutes
(with anticipated cold load pickup included).
Page 42 of 44

East Coeur d'Alene Lake System Reinforcement 2024
ay
s yea
CENTENNIAL TRAIL Gpe�T p P epe LaKe ID90-MP20 NTEa�
STATE 00
aPP®m.pry Gr.axer paw lztem
w saM vde pf ws+e trail
3J•waYYfivnwwpaeeaVa - 'NTERSTgT
E90
Exeang Lake Cmaaing CaMe-Appmc 3000'
Riser Poet 121820 to JC 1722
Retain exeting aroaung for felling
.No.—A south side of crossing
one as ememenoy loop 1eee.
New Lake Crossing Co -ApDroximatery 5700'
New Rixr ear Po"121820 to New 600JE3 on Vault
n China Ne[onluty Bay. e mu Ne n a w Bea in oteeapury Bay
_ i4•an xam at omh Soft
31000CN15 pnmary(with 113 ne 1)
e� 8e'
HIGHWAY 97
I
BLU321 - Lake Crossing Cable Replacement / Re-route
NOTICE THIS�L� LmaOwn olMvfa Ua�ies'ficives on Nis map are appmamae only.
IWnISTA ALEGALD GUMENT oe u, e.a� mw is wue l w`o°r'a�°o+�� Printed: 08-05-2024 1 Inch=400 feet
Lai. Rcw rme I..awe.I..o-Na mauve:�a�rmaoo�a o�e cair
eefw.awdawwk. Route To: Jason Stippich
Page 43 of 44

East Coeur d'Alene Lake System Reinforcement 2024
JEl
, Existing 600A JE3
DEEM WILLIAM
91uFEM DON.1lDOETU, 1 -
1
11
1
1 Proposed Route-1600'
4
Fsn Mnlss4t4xa
Proposed new 600A JE3 on vault
- _ Old cabin
JEs Proposed new 600A JE3 on vault
NEIEN F STO W ELL IFNEVOC�BIE iRUer TE
-----------------
Existing BOOA JE3
Existing 1PH Cable Route-1700'
xELEN F srov,Fi�IroeEwe•elE musr mE
JA
A' Nlnted:av-24-2024 ,;Rtn=,sorest BLU321 -600A Cable Route
trMM ......�.... 'n..a...d„d....o."""`Route To:Jeson Stipplch
Page 44 of 44