20220210PAC to Staff Transition Cluster Study.pdf

Generation Interconnection Transition Cluster

Transition Cluster Study Report

Cluster Area 1

March 31, 2021

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Transition Cluster Area 1 Page i March 31, 2021

TABLE OF CONTENTS

1.0 SCOPE OF THE STUDY ................................................................................................................. 1
2.0 STUDY ASSUMPTIONS ................................................................................................................. 1
3.0 GENERATING FACILITY REQUIREMENTS .............................................................................. 3
3.1 Transmission Interconnection Requests ............................................................................................ 3
3.2 Distribution Interconnection Requests .............................................................................................. 6
4.0 CLUSTER AREA DEFINITIONS ................................................................................................... 6
5.0 CLUSTER AREA 1 .......................................................................................................................... 7
5.1 Description of Interconnection Request – TCS-06 ........................................................................... 7
6.0 SITE SPECIFIC GENERATING FACILITY REQUIREMENTS ................................................... 8
7.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS ........................................................ 9
7.1 Transmission System Requirements ................................................................................................. 9
7.2 Distribution System Requirements ................................................................................................... 9
7.3 Transmission Line Requirements ...................................................................................................... 9
7.4 Existing Circuit Breaker Upgrades – Short Circuit ........................................................................... 9
7.5 Protection Requirements ................................................................................................................. 10
7.6 Data (RTU) Requirements .............................................................................................................. 10
7.7 Substation Requirements ................................................................................................................. 11
7.8 Communication Requirements ........................................................................................................ 11
7.9 Metering Requirements ................................................................................................................... 12
8.0 CONTINGENT FACILITIES ......................................................................................................... 12
9.0 COST ESTIMATE .......................................................................................................................... 14
9.1 Interconnection Facilities ................................................................................................................ 14
9.2 Station Equipment ........................................................................................................................... 14
9.3 Network Upgrades .......................................................................................................................... 14
10.0 SCHEDULE .................................................................................................................................... 14
11.0 AFFECTED SYSTEMS ................................................................................................................. 15
12.0 APPENDICES ................................................................................................................................ 15
12.1 Appendix 1: Cluster Area Power Flow and Stability Study Results ............................................... 16
12.2 Appendix 2: Higher Priority Requests ............................................................................................ 18
12.3 Appendix 3: Property Requirements ............................................................................................... 19

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1.0 SCOPE OF THE STUDY
Cluster Area 1 (CA1) generally includes the east Wyoming area and includes the following
Interconnection Request: TCS-06

Consistent with Attachment W, Section 3.4.2 and Section 51.4 of PacifiCorp’s (“Transmission
Provider”) Open Access Transmission Tariff (“OATT”), this interconnection Transition Cluster
Study (“Cluster Study”) evaluated the impact of the proposed interconnections on the reliability
of the Transmission System. The Cluster Study considered the Base Case as well as all generating
facilities (and with respect to (iii) below, any identified Network Upgrades associated with such
higher queued interconnection) that, on the date the Cluster Request Window closes:

(i) are existing and directly interconnected to the Transmission System;
(ii) are existing and interconnected to Affected Systems and may have an impact on the
Interconnection Request;
(iii) have a pending higher queued or higher clustered interconnection request to interconnect
to the transmission system; and
(iv) have executed an LGIA or requested that an unexecuted LGIA be filed with FERC.

The Cluster Study consisted of power flow, stability, and short circuit analyses.

This Cluster Study report provides the following information:
• identification of any circuit breaker short circuit capability limits exceeded as a result of the
interconnection;
• identification of any thermal overload or voltage limit violations resulting from the
interconnection;
• identification of any instability or inadequately damped response to system disturbances
resulting from the interconnection and
• description and non-binding, good faith estimated cost of facilities required to interconnect the
Generating Facilities to the Transmission System and to address the identified short circuit,
instability, and power flow issues.
2.0 STUDY ASSUMPTIONS
• All active higher priority transmission service and/or generator interconnection requests
that were considered in this study are listed in Appendix 2. If any of these requests are
withdrawn, the Transmission Provider reserves the right to restudy this request, and the
results and conclusions could significantly change.
• For study purposes there are two separate queues:
o Transmission Service Queue: to the extent practical, all network upgrades that are
required to accommodate active transmission service requests were modeled in this
study.
o Generation Interconnection Queue: Interconnection Facilities and network
upgrades associated with higher queued or higher clustered interconnection
requests were modeled in this study.
• The Interconnection Customers’ request for energy or network resource interconnection
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service in and of itself does not request or convey transmission service. Only a Network
Customer may make a request to designate a generating resource as a Network Resource.
Because the queue of higher priority transmission service requests may be different when
a Network Customer requests network resource designation for this Generating Facility,
the available capacity or transmission modifications, if any, necessary to provide Network
Integration Transmission Service may be significantly different. Therefore,
Interconnection Customers should regard the results of this study as informational rather
than final.
• Under normal conditions, the Transmission Provider does not dispatch or otherwise
directly control or regulate the output of generating facilities. Therefore, the need for
transmission modifications, if any, that may be required to provide Network Resource
Interconnection Service will be evaluated on the basis of 100 percent deliverability (i.e.,
this study did not model displacement of other resources in the same area).
• This study assumed the Projects will be integrated into the Transmission Provider’s system
at agreed upon and/or proposed Points of Interconnection (“POI” or “POIs”).
• If Interconnection Customers proceed through the interconnection process, they will be
required to construct and own any facilities required between the Point of Change of
Ownership and the Project unless specifically identified by the Transmission Provider.
• Line reconductor or fiber underbuild required on existing poles were assumed to follow the
most direct path on the Transmission Provider’s system. If during detailed design the path
must be modified it may result in additional cost and timing delays for the Interconnection
Customer’s Project.
• Generator tripping either automatic or manual may be required for certain outages to
maintain the reliability of the system under outage conditions.
• All facilities will meet or exceed the minimum Western Electricity Coordinating Council
(“WECC”), North American Electric Reliability Corporation (“NERC”), and the
Transmission Provider’s performance and design standards.
• Power flow analysis requires WECC base cases to reliably balance under peak load
conditions the aggregate of generation in the local area, with the Generating Facility at full
output, to the aggregate of the load in the Transmission Provider’s Transmission System.
As the PacifiCorp East (“PACE”) balancing authority area (“BAA”) has more existing and
proposed generation than load, it is necessary to assume some portion of other remote
resources are displaced by this Project’s output in order to assess the impact of
interconnecting this Project’s generation to transmission system operations. For the
purposes of this study, generation in the Transmission Provider’s southern Utah area was
assumed to be displaced.
• PacifiCorp performed the analysis on 2025 Heavy summer and 2025 Light summer TPL
base cases.
• The following transmission improvements were assumed in-service:
o Transmission Provider’s planned projects:
▪ Energy Gateway South (Aeolus-Clover) 500 kV transmission line project.
(Q4 2024).
▪ A Transmission Provider planned upgrade of the existing Jim Bridger
345/230 kV #2 transformer to 700 MVA (Q3 2021)
o Upgrades assigned to higher priority Interconnection Request Q0835:
▪ A new 230 kV transmission line between Aeolus and Freezeout substations
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(Q4 2024)
▪ Upgrades assigned to higher priority Interconnection Request Q0836:
▪ A Static VAR Compensator at Anticline 345 kV.
▪ Rebuild of the WAPA Casper–Spence 230 kV transmission line.
▪ Replacement of the Jim Bridger 345/230 kV transformers # 1 and #3 with a
single 700 MVA transformer.
• Jim Bridger Unit 1 was assumed offline in the study.
• Spence substation is owned by Western Area Power Administration (“WAPA”) therefore
any requirements in the substation must be coordinated and approved by WAPA.
• All existing and proposed RAS are assumed to be in service for this study.
• This report is based on information available at the time of the study. It is the
Interconnection Customer’s responsibility to check the Transmission Provider’s web site
regularly for Transmission System updates at https://www.oasis.oati.com/ppw
3.0 GENERATING FACILITY REQUIREMENTS
The following requirements are applicable to all Interconnection Requests. The Transmission
Provider will identify any site-specific generating facility requirements in addition to the
following in this report and in facilities studies. Certain Interconnection Requests requesting
service at a voltage level traditionally defined as distribution may be subject to the transmission
interconnection request requirements listed below should the Transmission Provider make that
determination.
3.1 Transmission Voltage Interconnection Requests
All interconnecting synchronous and non-synchronous generators are required to design their
Generating Facilities with reactive power capabilities necessary to operate within the full power
factor range of 0.95 leading to 0.95 lagging. This power factor range shall be dynamic and can be
met using a combination of the inherent dynamic reactive power capability of the generator or
inverter, dynamic reactive power devices and static reactive power devices to make up for losses.

For synchronous generators, the power factor requirement is to be measured at the Point of
Interconnection. For non-synchronous generators, the power factor requirement is to be measured
at the high side of the generator substation.

The Generating Facility must provide dynamic reactive power to the system in support of both
voltage scheduling and contingency events that require transient voltage support and must be able
to provide reactive capability over the full range of real power output.

If the Generating Facility is not capable of providing positive reactive support (i.e., supplying
reactive power to the system) immediately following the removal of a fault or other transient low
voltage perturbations, the facility must be required to add dynamic voltage support equipment.
These additional dynamic reactive devices shall have correct protection settings such that the
devices will remain online and active during and immediately following a fault event.

Generators shall be equipped with automatic voltage-control equipment and normally operated
with the voltage regulation control mode enabled unless written authorization (or directive) from
the Transmission Provider is given to operate in another control mode (e.g. constant power factor
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control). The control mode of generating units shall be accurately represented in operating studies.
The generators shall be capable of operating continuously at their maximum power output at its
rated field current within +/- 5% of its rated terminal voltage.

All generators are required to ensure the primary frequency capability of their Facility by
installing, maintaining, and operating a functioning governor or equivalent controls as indicated
in FERC Order 842.

As required by NERC standard VAR-001-4.2, the Transmission Provider will provide a voltage
schedule for the Point of Interconnection. In general, Generating Facilities should be operated so
as to maintain the voltage at the Point of Interconnection, typically between 1.00 per unit to 1.04
per unit, or other designated point as deemed appropriated by Transmission Provider. The
Transmission Provider may also specify a voltage and/or reactive power bandwidth as needed to
coordinate with upstream voltage control devices such as on-load tap changers. At the
Transmission Provider’s discretion, these values might be adjusted depending on operating
conditions.

Generating Facilities capable of operating with a voltage droop are required to do so. Voltage
droop control enables proportionate reactive power sharing among Generation Facilities. Studies
will be required to coordinate voltage droop settings if there are other facilities in the area. It will
be the Interconnection Customer’s responsibility to ensure that a voltage coordination study is
performed, in coordination with Transmission Provider, and implemented with appropriate
coordination settings prior to unit testing.

For areas with multiple generating facilities additional studies may be required to determine
whether or not critical interactions, including but not limited to control systems, exist. These
studies, to be coordinated with Transmission Provider, will be the responsibility of the
Interconnection Customer. If the need for a master controller is identified, the cost and all related
installation requirements will be the responsibility of the Interconnection Customer. Participation
by the generation facility in subsequent interaction/coordination studies will be required pre- and
post-commercial operation in order ensure system reliability.

Interconnection Requests that are 75 MVA or larger may be required to facilitate collection and
validation of accurate modeling data to meet NERC modeling standards. The Transmission
Provider, in its roles as the Planning Coordinator, requires Phasor Measurement Units (PMUs) at
all new Generating Facilities with an individual or aggregate nameplate capacity of 75 MVA or
greater. In addition to owning and maintaining the PMU, the Generating Facility will be
responsible for collecting, storing (for a minimum of 90 days) and retrieving data as requested by
the Planning Coordinator. Data must be stored for a minimum of 90 days. Data must be collected
and be able to stream to Planning Coordinator for each of the Generating Facility’s step-up
transformers measured on the low side of the GSU at a sample rate of at least 60 samples per
second and synchronized within +/- 2 milliseconds of the Coordinated Universal Time (UTC).
Initially, the following data must be collected:
• Three phase voltage and voltage angle (analog)
• Three phase current (analog)
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Data requirements are subject to change as deemed necessary to comply with local and federal
regulations.

All generators must meet the Federal Energy Regulatory Commission (FERC), North American
Electric Reliability Corporation (NERC) and WECC low voltage ride-through requirements as
specified in the interconnection agreement. Inverters must be designed to stay connected to the
grid in the case of severe faults and may not momentarily cease output within the no-trip area of
the voltage curves. Figure 1 illustrates the voltage ride-through capability as per NERC PRC-
024. Importantly, inverters should be designed such that a trip outside of the curves is a “may-
trip” area (if needed to protect equipment) not a “must-trip” area. Inverters that momentarily cease
active power output for these voltage excursions should be configured to restore output to pre-
disturbance levels in no greater than five seconds, provided the inverter is capable of these changes.
Generators must provide test results to the Transmission Provider verifying that the inverters for
this Project have been programmed to meet all PRC-024 requirements rather than manufacturer
IEEE distribution standards.

Figure 1 – Voltage Ride-Through Curve

As the Transmission Provider cannot submit a user written model to WECC for inclusion in base
cases, a standard model from the WECC Approved Dynamic Model Library is required 180 days
prior to trial operation. The list of approved generator models is continually updated and is
available on the http://www.WECC.biz website.

Interconnection Customer with an Interconnection Request for a Generating Facility that is both
75 MVA or larger as well as being interconnected at a voltage higher than 100 kV shall register
with NERC as the Generator Owner (“GO”) and Generator Operator (“GOP”) for the Large
Generating Facility and provide the Transmission Provider documentation demonstrating
registration in order to be approved for Commercial Operation. This registration must be
maintained throughout the lifetime of the Interconnection Agreement.

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Interconnection Customers are responsible for the protection of transmission lines between the
Generating Facility and the Point of Interconnection substation. For Interconnection Requests that
are smaller than 75 MVA or are interconnected at a voltage less than 100 kV which have a tie line
that is longer than 1,000 feet the Interconnection Customer shall construct and own a tie-line
substation to be located at the change of ownership (separate fenced facility adjacent to the
Transmission Provider’s Point of Interconnection substation). The tie line substation shall include
an Interconnection Customer owned protective device and associated transmission line
relaying/communications. The ground grids of the Transmission Provider’s Point of
Interconnection substation and the Interconnection Customer’s tie-line substation will be
connected to support the use of a bus differential protection scheme which will protect the
overhead bus connection between the two facilities.
3.2 Distribution Voltage Interconnection Requests
The Generating Facility and interconnection equipment owned by the Interconnection Customers
are required to operate under constant power factor mode with a unity power factor setting unless
specifically requested otherwise by the Transmission Provider. The Generating Facilities are
expressly forbidden from actively participating in voltage regulation of the Transmission
Provider’s system without written request or authorization from the Transmission Provider. The
Generating Facilities shall have sufficient reactive capacity to enable the delivery of 100 percent
of the plant output to the applicable POI at unity power factor measured at 1.0 per unit voltage
under steady state conditions.

Generators capable of operating under voltage control with voltage droop are required to do so.
Studies will be required to coordinate the voltage droop setting with other facilities in the area. In
general, the Generating Facility and Interconnection Equipment should be operated so as to
maintain the voltage at the Point of Interconnection between 1.01 pu to 1.04 pu. At the Public
Utility’s discretion, these values might be adjusted depending on the operating conditions. Within
this voltage range, the Generating Facility should operate so as to minimize the reactive
interchange between the Generating Facility and the Public Utility’s system (delivery of power at
the Point of Interconnection at approximately unity power factor). The voltage control settings of
the Generating Facility must be coordinated with the Public Utility prior to energization (or
interconnection). The reactive compensation must be designed such that the discreet switching of
the reactive device (if required by the Interconnection Customer) does not cause step voltage
changes greater than +/-3% on the Public Utility’s system.

All generators must meet applicable WECC low voltage ride-through requirements as specified in
the interconnection agreement.

As per NERC standard VAR-001-1, the Public Utility is required to specify voltage or reactive
power schedule at the Point of interconnection. Under normal conditions, the Public Utility’s
system should not supply reactive power to the Generating Facility.
4.0 CLUSTER AREA DEFINITIONS
The Transmission Provider performed the Transition Cluster Study based on geographically and/or
electrically relevant areas on the Transmission Provider’s Transmission System known as Cluster
Areas. The Transmission Provider has determined that the Interconnection Requests discussed in
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Section 5.0 are located in a geographically and/or electrically relevant area on Transmission
Provider’s Transmission System, and thus, were assigned Cluster Area 1 in the Transition Cluster
Study process.
5.0 CLUSTER AREA 1
Cluster Area 1 (CA1) generally includes the east Wyoming area. The Cluster area includes all
generation interconnection requests in the Wyoming area east of the Jim Bridger West Path and
also east of the Rock Springs – Firehole West cutplane which is shown with the red arrow in the
diagram below. The Jim Bridger West path provides a transmission path to the west into
southeast Idaho and the Rock Springs – Firehole West cutplane traverses through southwest
Wyoming providing a transmission path into northern Utah. The diagram below provides a high-
level description of the Wyoming cluster area.
Figure 2 – Cluster Area 1

5.1 Description of Interconnection Request – TCS-06
The Interconnection Customer has proposed to interconnect 80 MW of new generation to
PacifiCorp’s (“Transmission Provider”) Mustang-Spence 230 kV transmission line located in
Fremont County, Wyoming. The Interconnection Request is proposed to consist of 31 3150 KVA
Sungrow SG3150U solar inverters for a total output of 80 MW at the Point of Interconnection.
The Interconnection Request is also proposed to consist of 80 MW of DC coupled battery storage
with no grid charging capability. The requested commercial operation date is October 31, 2022.
Figure 3 below, is a one-line diagram that illustrates the interconnection of the proposed
Generating Facility to the Transmission Provider’s system.

Interconnection Customer will operate this generator as a Qualified Facility as defined by the
Public Utility Regulatory Policies Act of 1978 (“PURPA”).

The Interconnection Request will be studied for Network Resource Interconnection Service
(“NRIS”).
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The Transmission Provider has assigned the Project Cluster Number “TCS-06”

MUSTANG
230kV
TO
JIM
BRIDGER
69kV
~14.5 mi
~61.5 mi
SPENCE
230kV
(WAPA)
Change of Ownership
New
Facilities
M
34.5kV
PV
ARRAY
BATTERY BANK
PV ARRAY
BATTERY BANK
630V
3150kVA
8 IDENTICAL BANKS
52-F1
PV ARRAY
BATTERY BANK
PV ARRAY
BATTERY BANK
630V
3150kVA
8 IDENTICAL BANKS
52-F2
PV ARRAY
BATTERY BANK
PV ARRAY
BATTERY BANK
630V
3150kVA
8 IDENTICAL BANKS
52-F3
PV ARRAY
BATTERY BANK
PV ARRAY
BATTERY BANK
630V
3150kVA
7 IDENTICAL BANKS
52-F4
230-34.5-13.8 kV
51/68/85 MVA
230kV
TC-06 SOLAR AND
BATTERY STATION
80 MW
52-TP
Meter
TCS-06 POI 230kV(NEW SUBSTATION)
~100ft

Figure 3: Simplified System One Line Diagram

6.0 SITE SPECIFIC GENERATING FACILITY REQUIREMENTS
Based on the model provided by the Interconnection Customer, the study showed that the
Generating Facility was not able to meet the +/- 0.95 power factor in the inductive range as it was
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not able to provide enough capacitive VARs to the POI without exceeding the voltage limit. The
Interconnection Customer needs to ensure that the Generating Facility is capable of maintaining
the +/- 0.95 power factor and provide dynamic VARs at all output levels.
7.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS
7.1 Transmission System Requirements
A three-breaker 230 kV ring bus with associated switches and line terminations on the Spence–
Mustang 230 kV line is required. This new substation, temporarily named as “TCS-06 POI”,
will be built at the Point of Interconnection as shown in the simplified one-line diagram of
Figure 3.

Additionally, the Transmission Provider’s study results have concluded that the
Interconnection Request in this Cluster Area triggers the need for an additional segment of the
Transmission Provider’s planned Energy Gateway transmission project. Construction of the
Gateway West Segment D3 (Anticline/Populus) 500 kV transmission line and all associated
upgrades included in that project are required to be completed before the Interconnection
Customer’s proposed Generating Facility can go into service. For more details on the study
results and the Gateway West Segment D3 project please see Appendix 1. The currently
assumed in service date for the Transmission Provider’s Gateway West Segment D3 is 2027.

The Transmission Provide has concluded that 0 MW can be interconnected prior to the
upgrades described above are complete.
7.2 Distribution System Requirements
No distribution upgrades are required for the Interconnection Request in this Cluster Area.
7.3 Transmission Line Requirements
The Mustang-Spence 230 kV transmission line will be looped through a new POI substation.
It is assumed that the new substation location will be directly adjacent to the Mustang-Spence
230 kV transmission line. New line construction will match the existing line conductor size
and will require four new guyed wood structures.

Approximately 14.5 miles of the existing 230 kV transmission line between Mustang
substation and the new POI substation will have one of the existing shield wires replaced
with OPGW.
7.4 Existing Circuit Breaker Upgrades – Short Circuit
The addition of the TCS-06 Generating Facility at a point in the 230 kV line between
Mustang and Spence substations as indicated in the simplified one line diagram (Figure 3)
with a three-winding transformer of 85 MVA maximum, 23-35.5-13.8 kV, with the
impedances provided by the Interconnection Customer in their Single-Line Diagram drawing
#E-001 of 05/20/2020, and with four collector circuits connected at 34.5kV, will cause an
increase in the system’s fault duty which will not violate the interrupting capacity of any of
the existing interrupting equipment of Mustang or Spence substations.
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7.5 Protection Requirements
The 230kV system around the TCS-06 POI substation will be protected using very fast
redundant schemes, which guarantee a maximum clearing time of five (5) cycles (see Figure
3). The 230 kV transmission line between Mustang substation and the TCS-06 POI substation
will be protected with redundant line differential using communications over fiber optic cable.
When the POI-to-Mustang line is out of service for maintenance, a fault in the POI-to-Spence
line might not be cleared at POI if a non-transfer-trip STEPD scheme is used. Therefore, the
transmission line between the TCS-06 POI substation and Spence substation will be protected
with a redundant POTTD scheme using communications over fiber optic cable and digital
microwave between these sites. New relays will need to be installed in Mustang substation to
be compatible with the relays to be installed in the POI substation. Relay settings changes will
likely be required in Spence substation.

The 230 kV interconnection segment between the TCS-06 POI substation and the
Interconnection Customer will be protected with redundant high impedance bus differential
scheme. The bus differential zone will be extended to the 230 kV BCT located the transformer
side of the 52-PT circuit breaker; therefore the Interconnection Customer must specify two sets
of its current transformers to have the same full-winding ratio as the ones used in BCTs in the
TCS-06 POI substation. The high impedance bus differential scheme will trip the two circuit
breakers of the TCS-06 POI substation and the Interconnection Customer’s 230 kV 52-TP
circuit breaker.

A multifunction directional overcurrent relay set to operate for faults at the 230 kV
interconnection segment will be installed. This relay will have enough overvoltage,
undervoltage, overfrequency and underfrequency elements to implement the supervision
scheme established by the Transmission Provider policy regarding tolerable limits of voltage
and frequency. The lockout relay will trip the two TCS-06 POI 230 kV circuit breakers
associated with the interconnection and the Interconnection Customer’s 52-TP circuit breaker.
7.6 Data (RTU) Requirements
Data for the operation of the Transmission Provider’s system will be needed from the new POI
substation and the Interconnection Customer collector substation. The Interconnection
Customer will hard wire all source devices to a marshalling cabinet to be installed on the POI
substation fence in order to provide this data.

From the collector substation:
Analogs from Customer:
▪ Global Horizontal Irradiance (GHI)
▪ Average Plant Atmospheric Pressure (Bar)
▪ Average Plant Temperature (Celsius)
▪ Max Generator Limit MW (set point control)
▪ Potential Power MW

Status from Customer:
▪ 34.5 kV 52-F1 circuit breaker
▪ 34.5 kV 52-F2 circuit breaker
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▪ 34.5 kV 52-F3 circuit breaker
▪ 34.5 kV 52-F4 circuit breaker
▪ 230kV 52-TP circuit breaker

From the POI substation:
Analogs from PAC Meters:
▪ Net Generation real power MW
▪ Net Generator reactive power MVAR
▪ Energy Register KWH
▪ A-phase 12.5 kV voltage
▪ B-phase 12.5 kV voltage
▪ C-phase 12.5 kV voltage
7.7 Substation Requirements
A new three-breaker 230 kV ring bus substation will need to be constructed to serve as the
Point of Interconnection. The following major equipment has been preliminarily identified for
this project and may change during actual design:

3 – 230 kV, 3000 A Circuit Breakers
2 – 230kV-120/240V, 100KVA, SSVT
8 – 230kV, 3000A, horizontal mount, vertical break switch
3 – 230kV, 3000A, vertical mount, vertical break switch with motor operator
1 – 230kV, 3000A, vertical mount, vertical break switch
6 – 230 kV CCVT
3 – 230 kV CT/VT metering units
1 – 28’ x 40’ control house
6 – 230KV surge arresters

Mustang Substation
A new relay panel will be installed. Communications equipment to support the new fiber
running from the POI substation will be installed.

WAPA Spence Substation
A new relay panel will be installed. Communications equipment will be installed to support
the new microwave system required at this substation.
7.8 Communication Requirements
The communications between Mustang substation and TCS-06 POI will be done via 14.5 miles
of OPGW. Path studies were run to all adjacent locations that have existing communications
and none had a clear line of site to the POI for digital microwave communications. The POI
and Mustang substation will use Carrier Ethernet and channel banks for the transport of line
protection circuits and RTU data to the EMS.

From Mustang substation the communications will be on an existing communications network
to Casper substation. From Casper the Transmission Provider assumes that the signal can be
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sent via WAPA’s network to Spence substation. This arrangement will require an agreement
with WAPA.
7.9 Metering Requirements
Generation Project Metering
This Interconnection Request proposes DC coupled battery and solar facilities. The
Transmission Provider has no approved method to meter battery and solar in this
configuration separately therefore the solar and battery storage will essentially be a single
generating facility from a revenue metering perspective.

The metering will be located at the Point of Interconnection substation and rated for the total
net generation of the Project. The Transmission Provider will specify and order all
interconnection revenue metering, including the instrument transformers, meters, meter panel,
junction box, and secondary metering wire. The primary metering transformers will be
combination 230kV CT/VT units with extended range CTs for high-accuracy metering.
The metering design package will include two revenue quality meters with DNP real time
digital data terminated at a metering interposition block. One meter will be designated as
primary SCADA meter with DNP data delivered to the primary control center. A second meter
will be designated as backup SCADA meter with DNP data delivered to the alternate control
center. The metering data will include bidirectional KWH and KVARH revenue quantities.
The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage,
and per-phase amps data.
An Ethernet connection is required for retail sales and generation accounting via the MV-
90 translation system.

Station Service/Construction Power
The Project is within the Transmission Provider’s service territory. Please note that prior to
back feed, Interconnection Customer must arrange transmission retail meter service for
electricity consumed by the Project that will be drawn from the transmission system when the
Project is not generating. Interconnection Customer must call the Help Desk at 1-800‐625‐
6078 to arrange this service. Approval for back feed is contingent upon obtaining station
service.
8.0 CONTINGENT FACILITIES
The following Interconnection Facilities and/or upgrades to the Transmission Provider’s system
are Contingent Facilities applicable to this Cluster Area.

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Contingent Facilities Table
Potential
Contingent
Facility
Description

Outage(s)
Pre-
Cluster
Overload/
Violation
Level
Post-
Cluster
Overload
/
Violation
Level

%
Change
Contingent
Facility
(Yes/No)

Responsible
Entity

Planned
ISD
Gateway South
and the
anscillary
improvements
Aeolus –
Anticline 500
kV line with
the Aeolus
RAS dropping
627 MW
Non-
conver-
gence
Non-
conver-
gence
N/A Yes PAC Estimated
December
2024
An upgrade of
the existing Jim
Bridger
345/230 kV #2
transformer to
700 MVA
Loss of Jim
Bridger #1 and
# 3 345/230
kV auto
transformer.
129% 141% 9.3% Yes PAC Estimated
September
2021
A new 230 kV
transmission
line between
Aeolus and
Freezeout
substations

Aeolus –
Freezeout 230
kV line with
the RAS to
drop
generation at
Freezeout
100% 100% 0% No Q835 Estimated
December
2024
A Static VAR
Compensator
(SVC) -
125/+350
MVAR at
Anticline 345
kV
Gateway
South 500 kV
line with the
Aeolus RAS
dropping 627
MW
Non-
convergen
ce
Non-
converge
nce
N/A Yes Q0836 Estimated
December
2024
The rebuild of
the Casper –
Spence 230 kV
line with a
bundled 2x954
ACSR
conductor
Casper –
Riverton 230
kV line
106% 101% -4.72% No Q0836 N/A
Jim Bridger
345/230 kV
transformer # 1
and #3 replaced
with a single
700 MVA
transformer
Breaker failure
at Rock
Springs 230
kV (1H132)
losing both
Rock Springs
– Firehole 230
kV and Rock
Springs –
Palisades –
Raven 230 kV
lines.
108% 114% 5.55% Yes Q0836 TBD
Transition Cluster Study Report
Transition Cluster Area 1 Page 14 March 31, 2021

9.0 COST ESTIMATE
The following estimate represents only scopes of work that will be performed by the Transmission
Provider. Costs for any work being performed by the Interconnection Customer and/or Affected
Systems are not included.

9.1 Interconnection Facilities
The following facilities are directly assigned to Interconnection Customer(s) using such
facilities. If multiple Interconnection Requests are utilizing the same Transmission Provider
Interconnection Facilities the costs shall be shared pursuant to Section 39.2.3 of
Transmission Provider’s OATT.

POI Substation $1,200,000
Line termination and metering
9.2 Station Equipment
The following are Network Upgrades which are allocated based on the number of Generating
Facilities interconnecting at an individual station on a per Interconnection Request basis.
Interconnection Requests utilizing the same Interconnection Facilities shall be consider one
request for this allocation.

POI Substation $6,775,000
Build 3-breaker 230 kV substation for interconnection

9.3 Network Upgrades
The funding responsibility for Network Upgrades other than those identified in the previous
section shall be allocated based on the proportional capacity of each individual Generating
Facility.

Mustang Substation $260,000
Install line protection panel and communications

Spence Substation $188,000
Install line protection panel and communications

Mustang-Spence 230 kV Loop and OPGW $1,566,000
Loop line through new POI substation, install fiber

Grand Total $9,990,000
10.0 SCHEDULE
The Transmission Provider estimates it will require approximately 24 months to design, procure
and construct the facilities described in this report following the execution of an Interconnection
Agreement. The schedule will be further developed and optimized during the Facilities Studies.
Transition Cluster Study Report
Transition Cluster Area 1 Page 15 March 31, 2021

11.0 AFFECTED SYSTEMS
Transmission Provider has identified the following affected systems: Western Area Power
Administration and Tri-State Generation and Transmission Association.

A copy of this report will be shared with each Affected System.
12.0 APPENDICES
Appendix 1: Cluster Area Power Flow and Stability Study Results
Appendix 2: Higher Priority Requests
Appendix 3: Property Requirements
Transition Cluster Study Report
Transition Cluster Area 1 Page 16 March 31, 2021

12.1 Appendix 1: Cluster Area Power Flow and Stability Study Results
The cluster study was completed using a PacifiCorp TPL base case representing the 2025 Heavy
Summer and 2025 Light summer case. The studies were completed using PSSE Version 34.8.0.
Each case was studied considering prior generator interconnection queue projects with signed
interconnection agreements and prior queued and granted transmission service requests. Major
system improvements identified in the assumptions section of this report were modeled, regardless
of in-service date, as well as any improvements related to prior generation queue projects.

The following planned capital projects were assumed in-service:
(1) The Energy Gateway South and ancillary improvements associated with the project (in-
service date 12/2024).
(2) Upgrade the Jim Bridger #2 345 230 kV auto transformer (in-service date 09/2021)

Jim Bridger Unit 1 was assumed to be offline. For the cluster study, TPL category P1, P2 and P7
contingencies were simulated. A significant number of outages within the cluster area along with
outages on the neighboring clusters were considered and the system performance was monitored
before and after each contingency.
The generation interconnection projects in CA1 need to ensure that they meet the power factor
range of 0.95 leading to 0.95 lagging. It is the responsibility of the Interconnection Customer to
ensure that the power factor requirement is met.

The following results were observed for the CA1 which had one interconnection project TCS-06
along with the required contingent facilities listed in Section 8.

N-0
With all lines in-service (P0) and assuming facilities identified in the assumption section of this
report are in-service, no thermal overloads or voltage violations were observed.
N-1
The following thermal overloads and voltage issues were observed for the N-1 outages.
Contingency Overloaded Element/
Voltage Violation
Bus
Overload (% Rate C)
or
Voltage Magnitude
Mitigation
Aeolus – Anticline
500 kV line with the
Aeolus RAS
Non-convergence N/A Energy Gateway
Segment D.3
(Anticline – Populus
500 kV line) along
with its ancillary
improvements.
Gateway South with
the Aeolus RAS
Threemile Knoll
Series Capacitor
101% Energy Gateway
Segment D.3
(Anticline – Populus
500 kV line) along
Transition Cluster Study Report
Transition Cluster Area 1 Page 17 March 31, 2021

Contingency Overloaded Element/
Voltage Violation
Bus
Overload (% Rate C)
or
Voltage Magnitude
Mitigation
with its ancillary
improvements.
Latham STATCOM
Transformer
101% Energy Gateway
Segment D.3
(Anticline – Populus
500 kV line) along
with its ancillary
improvements.

The outage of the Gateway West 500 kV D.2 (Aeolus – Anticline 500 kV line) line with the
implementation of the Aeolus RAS results in non-convergence with the generation projects in CA1
in-service at its full output. The non-convergence is occurring due to inadequate voltage support
on the 230 kV transmission system near Latham. The outage of the Gateway South 500 kV line
(Aeolus – Clover 500 kV line) with the Aeolus RAS results in thermal overload of the series
capacitor at Threemile Knoll on the Jim Bridger – Threemile Knoll 345 kV line. In order to
mitigate these issues the Transmission Provider’s planned Energy Gateway West Segment D.3
Anticline – Populus 500 kV line must be constructed which will provide a parallel transmission
path to Populus in addition to the Jim Bridger West path. The D.3 project includes constructing a
204-mile-long series compensated Anticline–Populus 500 kV line along with the following
ancillary improvements
• Two bypassable series compensation segments of approximately 30.18 ohms each. The
bypassable series compensation will be installed at Populus.
• Installation of two bypassable series compensation segments of approximately 21.03 ohms
each, on the existing Aeolus – Anticline 500 kV line in the middle of the line around
Latham.
• Installation of three single phase 525/345 kV transformers (533/597 MVA) at Populus and
one single phase 525/345 kV spare transformer
• One additional 200 MVAr 500 kV capacitor bank at Anticline
• Three 200 MVAr 500 kV each capacitor banks at Populus
• One additional 200 MVAR 500 kV shunt capacitor banks at Aeolus.
• Modify the Aeolus RAS to include the outage of the Anticline–Populus 500 kV line and
the Populus 500/345 kV auto transformer.
Depending on real time outages and system operating conditions, certain N-1-1 (P6) contingencies
may require curtailment of the TCS-06 Project.
There were no double element (P7) contingencies that triggered elements to exceed their
emergency thermal limit as a result of addition of the TCS-06 Project.

Transition Cluster Study Report
Transition Cluster Area 1 Page 18 March 31, 2021

12.2 Appendix 2: Higher Priority Requests
All active higher priority Transmission Provider projects, and transmission service and/or
generator interconnection requests were considered in this cluster area study and are identified
below. If any of these requests are withdrawn, the Transmission Provider reserves the right to
restudy this request, as the results and conclusions contained within this study could significantly
change.

Transmission/Generation Interconnection Queue Requests considered:

Q0409 (320 MW)
Q0713 (350 MW)
Q0719 (280 MW)
Q0783 (30 MW)
Q0784 (80 MW)
Q0785 (100 MW)
Q0789 (74.9 MW)
Q0801 (80 MW)
Q0802 (50 MW)
Q0807 (75.9 MW)
Q0835 (190 MW)
Q0836 (400 MW)
TSR Q2594 (500 MW)

Transition Cluster Study Report
Transition Cluster Area 1 Page 19 March 31, 2021

12.3 Appendix 3: Property Requirements
Property Requirements for Point of Interconnection Substation
Requirements for rights of way easements
Rights of way easements will be acquired by the Interconnection Customer in the Transmission
Provider’s name for the construction, reconstruction, operation, maintenance, repair, replacement
and removal of Transmission Provider’s Interconnection Facilities that will be owned and
operated by PacifiCorp. Interconnection Customer will acquire all necessary permits for the
Project and will obtain rights of way easements for the Project on Transmission Provider’s
easement form.

Real Property Requirements for Point of Interconnection Substation
Real property for a point of interconnection substation will be acquired by an Interconnection
Customer to accommodate the Interconnection Customer’s Project. The real property must be
acceptable to Transmission Provider. Interconnection Customer will acquire fee ownership for
interconnection substation unless Transmission Provider determines that other than fee
ownership is acceptable; however, the form and instrument of such rights will be at Transmission
Provider’s sole discretion. Any land rights that Interconnection Customer is planning to retain as
part of a fee property conveyance will be identified in advance to Transmission Provider and are
subject to the Transmission Provider’s approval.

The Interconnection Customer must obtain all permits required by all relevant jurisdictions for
the planned use including but not limited to conditional use permits, Certificates of Public
Convenience and Necessity, California Environmental Quality Act, as well as all construction
permits for the Project.

If eligible, Interconnection Customer will not be reimbursed through network upgrades for more
than the market value of the property.

As a minimum, real property must be environmentally, physically, and operationally acceptable
to Transmission Provider. The real property shall be a permitted or able to be permitted use in all
zoning districts. The Interconnection Customer shall provide Transmission Provider with a title
report and shall transfer property without any material defects of title or other encumbrances that
are not acceptable to Transmission Provider. Property lines shall be surveyed and show all
encumbrances, encroachments, and roads.

Examples of potentially unacceptable environmental, physical, or operational conditions could
include but are not limited to:

1. Environmental: known contamination of site; evidence of environmental
contamination by any dangerous, hazardous or toxic materials as defined by any
governmental agency; violation of building, health, safety, environmental, fire,
land use, zoning or other such regulation; violation of ordinances or statutes of
any governmental entities having jurisdiction over the property; underground or
above ground storage tanks in area; known remediation sites on property; ongoing
mitigation activities or monitoring activities; asbestos; lead-based paint, etc. A
Transition Cluster Study Report
Transition Cluster Area 1 Page 20 March 31, 2021

phase I environmental study is required for land being acquired in fee by the
Transmission Provider unless waived by Transmission Provider.

2. Physical: inadequate site drainage; proximity to flood zone; erosion issues;
wetland overlays; threatened and endangered species; archeological or culturally
sensitive areas; inadequate sub-surface elements, etc. Transmission Provider may
require Interconnection Customer to procure various studies and surveys as
determined necessary by Transmission Provider.

Operational: inadequate access for Transmission Provider’s equipment and vehicles; existing
structures on land that require removal prior to building of substation; ongoing maintenance for
landscaping or extensive landscape requirements; ongoing homeowner's or other requirements or
restrictions (e.g., Covenants, Codes and Restrictions, deed restrictions, etc.) on property which
are not acceptable to the Transmission Provider.

Generation Interconnection Transition Cluster

Transition Cluster Study Report

Cluster Area 2

March 31, 2021

Transition Cluster Study Report
Transition Cluster Area 2 Page i March 31, 2021

TABLE OF CONTENTS

1.0 SCOPE OF THE STUDY ....................................................................................... 1
2.0 STUDY ASSUMPTIONS ...................................................................................... 1
3.0 GENERATING FACILITY REQUIREMENTS .................................................... 3
3.1 Transmission Voltage Interconnection Requests .................................................... 3
3.2 Distribution Voltage Interconnection Requests ...................................................... 6
4.0 CLUSTER AREA DEFINITIONS ......................................................................... 6
5.0 CLUSTER AREA 2 ................................................................................................ 7
5.1 Description of Interconnection Request – TCS-10 ................................................. 9
5.2 Description of Interconnection Request – TCS-16 ............................................... 10
5.3 Description of Interconnection Request – TCS-17 ............................................... 10
5.4 Description of Interconnection Request – TCS-19 ............................................... 11
5.5 Description of Interconnection Request – TCS-22 ............................................... 12
5.6 Description of Interconnection Request – TCS-26 ............................................... 13
5.7 Description of Interconnection Request – TCS-31 ............................................... 14
5.8 Description of Interconnection Request – TCS-23 ............................................... 16
6.0 SITE SPECIFIC GENERATING FACILITY REQUIREMENTS ...................... 17
7.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS ........................... 17
7.1 Transmission System Requirements ..................................................................... 17
7.2 Distribution System Requirements ....................................................................... 18
7.3 Transmission Line Requirements ......................................................................... 18
7.4 Existing Circuit Breaker Upgrades – Short Circuit .............................................. 20
7.5 Protection Requirements ....................................................................................... 22
7.6 Data (RTU) Requirements .................................................................................... 24
7.7 Substation Requirements ...................................................................................... 27
7.8 Communication Requirements.............................................................................. 34
7.9 Metering Requirements ......................................................................................... 35
8.0 CONTINGENT FACILITIES .............................................................................. 41
9.0 COST ESTIMATE................................................................................................ 61
9.1 Interconnection Facilities ...................................................................................... 61
9.2 Station Equipment ................................................................................................. 63
9.3 Network Upgrades ................................................................................................ 64
9.4 Total Estimated Project Costs ............................................................................... 67
10.0 SCHEDULE .......................................................................................................... 68
11.0 AFFECTED SYSTEMS ....................................................................................... 68
12.0 APPENDICES ...................................................................................................... 68
12.1 Appendix 1: Cluster Area Power Flow and Stability Study Results .................... 69
12.2 Appendix 2: Higher Priority Requests .................................................................. 93
12.3 Appendix 3: Property Requirements ..................................................................... 94

Transition Cluster Study Report
Transition Cluster Area 2 Page 1 March 31, 2021

1.0 SCOPE OF THE STUDY
Cluster Area 2 (CA2) generally covers the geographic area which includes the Trona area (from
Rock Springs & Firehole substations to Monument substation), Naughton area (Southwest
Wyoming, Northeast Utah, Southeast Idaho), Park City area, Ogden area and Northern Utah area.
This Cluster Area includes the following Interconnection Requests: TCS-10, TCS-16, TCS-17,
TCS-19, TCS-22, TCS-23, TCS-26 and TCS-31

Consistent with Attachment W, Section 3.4.2 and Section 51.4 of PacifiCorp’s (“Transmission
Provider”) Open Access Transmission Tariff (“OATT”), this interconnection Transition Cluster
Study (“Cluster Study”) evaluated the impact of the proposed interconnections on the reliability
of the Transmission System. The Cluster Study considered the Base Case as well as all generating
facilities (and with respect to (iii) below, any identified Network Upgrades associated with such
higher queued interconnection) that, on the date the Cluster Request Window closes:

(i) are existing and directly interconnected to the Transmission System;
(ii) are existing and interconnected to Affected Systems and may have an impact on the
Interconnection Request;
(iii) have a pending higher queued or higher clustered interconnection request to interconnect
to the transmission system; and
(iv) have executed an LGIA or requested that an unexecuted LGIA be filed with FERC.

The Cluster Study consisted of power flow, stability, and short circuit analyses.

This Cluster Study report provides the following information:
• identification of any circuit breaker short circuit capability limits exceeded as a result of
the interconnection;
• identification of any thermal overload or voltage limit violations resulting from the
interconnection;
• identification of any instability or inadequately damped response to system disturbances
resulting from the interconnection and
• description and non-binding, good faith estimated cost of facilities required to interconnect
the Generating Facilities to the Transmission System and to address the identified short
circuit, instability, and power flow issues.
2.0 STUDY ASSUMPTIONS
• All active higher priority transmission service and/or generator interconnection requests that
were considered in this study are listed in Appendix 2. If any of these requests are withdrawn,
the Transmission Provider reserves the right to restudy this request, and the results and
conclusions could significantly change.
• For study purposes there are two separate queues:
Transition Cluster Study Report
Transition Cluster Area 2 Page 2 March 31, 2021

o Transmission Service Queue: to the extent practical, all network upgrades that are required
to accommodate active transmission service requests were modeled in this study.
o Generation Interconnection Queue: Interconnection Facilities and network upgrades
associated with higher queued or higher clustered interconnection requests were modeled
in this study.
• The Interconnection Customers’ request for energy or network resource interconnection
service in and of itself does not request or convey transmission service. Only a Network
Customer may make a request to designate a generating resource as a Network Resource.
Because the queue of higher priority transmission service requests may be different when a
Network Customer requests network resource designation for this Generating Facility, the
available capacity or transmission modifications, if any, necessary to provide Network
Integration Transmission Service may be significantly different. Therefore, Interconnection
Customers should regard the results of this study as informational rather than final.
• Under normal conditions, the Transmission Provider does not dispatch or otherwise directly
control or regulate the output of generating facilities. Therefore, the need for transmission
modifications, if any, that may be required to provide Network Resource Interconnection
Service will be evaluated on the basis of 100 percent deliverability (i.e., this study did not
model displacement of other resources in the same area).
• This study assumed the Projects will be integrated into the Transmission Provider’s system at
agreed upon and/or proposed Points of Interconnection (“POI” or “POIs”).
• If Interconnection Customers proceed through the interconnection process, they will be
required to construct and own any facilities required between the Point of Change of
Ownership and the Project unless specifically identified by the Transmission Provider.
• Line reconductor or fiber underbuild required on existing poles were assumed to follow the
most direct path on the Transmission Provider’s system. If during detailed design the path
must be modified it may result in additional cost and timing delays for the Interconnection
Customer’s Project.
• Generator tripping may be required for certain outages.
• All facilities will meet or exceed the minimum Western Electricity Coordinating Council
(“WECC”), North American Electric Reliability Corporation (“NERC”), and the Transmission
Provider’s performance and design standards.
• Power flow analysis requires WECC base cases to reliably balance under peak load conditions
the aggregate of generation in the local area, with the Generating Facility at full output, to the
aggregate of the load in the Transmission Provider’s Transmission System. As the PacifiCorp
East (“PACE”) balancing authority area (“BAA”) has more existing and proposed generation
than load, it is necessary to assume some portion of other remote resources are displaced by
this Project’s output in order to assess the impact of interconnecting this Project’s generation
to transmission system operations. For the purposes of this study, generation in the
Transmission Provider’s southern Utah area was assumed to be displaced.
• The existing proposed Remedial Action Schemes associated with prior queued Generating
Facilities are assumed to be in service for this study.
• The follow transmission system improvements are assumed to be in service.
Transition Cluster Study Report
Transition Cluster Area 2 Page 3 March 31, 2021

o Transmission Provider planned projects:
▪ The Energy Gateway South projects which includes the new 500 kV Aeolus-Clover
transmission line and other associated upgrades. (Q4 2024)
▪ The Jordanelle–Midway 138 kV line will be assumed to be in service. (Q4 2021)
▪ Path C Improvement project. (Q4 2023)
o Separation of the double circuit portion of the Naughton–Ben Lomond and Birch Creek–
Ben Lomond 230 kV transmission lines required as part of higher priority Interconnection
Request Q0810. (ISD Unknown)
• This report is based on information available at the time of the study. It is the Interconnection
Customer’s responsibility to check the Transmission Provider’s web site regularly for
Transmission System updates at https://www.oasis.oati.com/ppw
3.0 GENERATING FACILITY REQUIREMENTS
The following requirements are applicable to all Interconnection Requests. The Transmission
Provider will identify any site-specific generating facility requirements in addition to the
following in this report and in facilities studies. Certain Interconnection Requests requesting
service at a voltage level traditionally defined as distribution may be subject to the transmission
interconnection request requirements listed below should the Transmission Provider make that
determination.
3.1 Transmission Voltage Interconnection Requests
All interconnecting synchronous and non-synchronous generators are required to design their
Generating Facilities with reactive power capabilities necessary to operate within the full
power factor range of 0.95 leading to 0.95 lagging. This power factor range shall be dynamic
and can be met using a combination of the inherent dynamic reactive power capability of the
generator or inverter, dynamic reactive power devices and static reactive power devices to
make up for losses.

For synchronous generators, the power factor requirement is to be measured at the Point of
Interconnection. For non-synchronous generators, the power factor requirement is to be
measured at the high-side of the generator substation.

The Generating Facility must provide dynamic reactive power to the system in support of both
voltage scheduling and contingency events that require transient voltage support, and must be
able to provide reactive capability over the full range of real power output.

If the Generating Facility is not capable of providing positive reactive support (i.e., supplying
reactive power to the system) immediately following the removal of a fault or other transient
low voltage perturbations, the facility must be required to add dynamic voltage support
equipment. These additional dynamic reactive devices shall have correct protection settings
such that the devices will remain on line and active during and immediately following a fault
event.

Generators shall be equipped with automatic voltage-control equipment and normally operated
with the voltage regulation control mode enabled unless written authorization (or directive)
from the Transmission Provider is given to operate in another control mode (e.g. constant
Transition Cluster Study Report
Transition Cluster Area 2 Page 4 March 31, 2021

power factor control). The control mode of generating units shall be accurately represented in
operating studies. The generators shall be capable of operating continuously at their maximum
power output at its rated field current within +/- 5% of its rated terminal voltage.

All generators are required to ensure the primary frequency capability of their Facility by
installing, maintaining, and operating a functioning governor or equivalent controls as
indicated in FERC Order 842.

As required by NERC standard VAR-001-4.2, the Transmission Provider will provide a
voltage schedule for the Point of Interconnection. In general, Generating Facilities should be
operated so as to maintain the voltage at the Point of Interconnection, typically between 1.00
per unit to 1.04 per unit, or other designated point as deemed appropriated by Transmission
Provider. The Transmission Provider may also specify a voltage and/or reactive power
bandwidth as needed to coordinate with upstream voltage control devices such as on-load tap
changers. At the Transmission Provider’s discretion, these values might be adjusted depending
on operating conditions.

Generating Facilities capable of operating with a voltage droop are required to do so. Voltage
droop control enables proportionate reactive power sharing among Generation Facilities.
Studies will be required to coordinate voltage droop settings if there are other facilities in the
area. It will be the Interconnection Customer’s responsibility to ensure that a voltage
coordination study is performed, in coordination with Transmission Provider, and
implemented with appropriate coordination settings prior to unit testing.

For areas with multiple generating facilities additional studies may be required to determine
whether or not critical interactions, including but not limited to control systems, exist. These
studies, to be coordinated with Transmission Provider, will be the responsibility of the
Interconnection Customer. If the need for a master controller is identified, the cost and all
related installation requirements will be the responsibility of the Interconnection Customer.
Participation by the generation facility in subsequent interaction/coordination studies will be
required pre- and post-commercial operation in order ensure system reliability.

Interconnection Requests that are 75 MVA or larger may be required to facilitate collection
and validation of accurate modeling data to meet NERC modeling standards. The Transmission
Provider, in its roles as the Planning Coordinator, requires Phasor Measurement Units (PMUs)
at all new Generating Facilities with an individual or aggregate nameplate capacity of 75 MVA
or greater. In addition to owning and maintaining the PMU, the Generating Facility will be
responsible for collecting, storing (for a minimum of 90 days) and retrieving data as requested
by the Planning Coordinator. Data must be stored for a minimum of 90 days. Data must be
collected and be able to stream to Planning Coordinator for each of the Generating Facility’s
step-up transformers measured on the low side of the GSU at a sample rate of at least 60
samples per second and synchronized within +/- 2 milliseconds of the Coordinated Universal
Time (UTC). Initially, the following data must be collected:
• Three phase voltage and voltage angle (analog)
• Three phase current (analog)
Transition Cluster Study Report
Transition Cluster Area 2 Page 5 March 31, 2021

Data requirements are subject to change as deemed necessary to comply with local and federal
regulations.

All generators must meet the Federal Energy Regulatory Commission (FERC), North
American Electric Reliability Corporation (NERC) and WECC low voltage ride-through
requirements as specified in the interconnection agreement. Inverters must be designed to stay
connected to the grid in the case of severe faults and may not momentarily cease output within
the no-trip area of the voltage curves. Figure 1 illustrates the voltage ride-through capability
as per NERC PRC-024. Importantly, inverters should be designed such that a trip outside of
the curves is a “may-trip” area (if needed to protect equipment) not a “must-trip”
area. Inverters that momentarily cease active power output for these voltage excursions should
be configured to restore output to pre-disturbance levels in no greater than five seconds,
provided the inverter is capable of these changes. Generators must provide test results to the
Transmission Provider verifying that the inverters for this Project have been programmed to
meet all PRC-024 requirements rather than manufacturer IEEE distribution standards.

Figure 1 – Voltage Ride-Through Curve

As the Transmission Provider cannot submit a user written model to WECC for inclusion in
base cases, a standard model from the WECC Approved Dynamic Model Library is required
180 days prior to trial operation. The list of approved generator models is continually updated
and is available on the http://www.WECC.biz website.

Interconnection Customer with an Interconnection Request for a Generating Facility that is
both 75 MVA or larger as well as being interconnected at a voltage higher than 100 kV shall
register with NERC as the Generator Owner (“GO”) and Generator Operator (“GOP”) for the
Large Generating Facility and provide the Transmission Provider documentation
demonstrating registration in order to be approved for Commercial Operation. This registration
must be maintained throughout the lifetime of the Interconnection Agreement.

Transition Cluster Study Report
Transition Cluster Area 2 Page 6 March 31, 2021

Interconnection Customers are responsible for the protection of transmission lines between the
Generating Facility and the Point of Interconnection substation. For Interconnection Requests
that are smaller than 75 MVA or are interconnected at a voltage less than 100 kV which have
a tie line that is longer than 1,000 feet the Interconnection Customer shall construct and own a
tie-line substation to be located at the change of ownership (separate fenced facility adjacent
to the Transmission Provider’s Point of Interconnection substation). The tie line substation
shall include an Interconnection Customer owned protective device and associated
transmission line relaying/communications. The ground grids of the Transmission Provider’s
Point of Interconnection substation and the Interconnection Customer’s tie-line substation will
be connected to support the use of a bus differential protection scheme which will protect the
overhead bus connection between the two facilities.
3.2 Distribution Voltage Interconnection Requests
The Generating Facility and interconnection equipment owned by the Interconnection
Customers are required to operate under constant power factor mode with a unity power factor
setting unless specifically requested otherwise by the Transmission Provider. The Generating
Facilities are expressly forbidden from actively participating in voltage regulation of the
Transmission Provider’s system without written request or authorization from the
Transmission Provider. The Generating Facilities shall have sufficient reactive capacity to
enable the delivery of 100 percent of the plant output to the applicable POI at unity power
factor measured at 1.0 per unit voltage under steady state conditions.

Generators capable of operating under voltage control with voltage droop are required to do
so. Studies will be required to coordinate the voltage droop setting with other facilities in the
area. In general, the Generating Facility and Interconnection Equipment should be operated so
as to maintain the voltage at the Point of Interconnection between 1.01 pu to 1.04 pu. At the
Public Utility’s discretion, these values might be adjusted depending on the operating
conditions. Within this voltage range, the Generating Facility should operate so as to minimize
the reactive interchange between the Generating Facility and the Public Utility’s system
(delivery of power at the Point of Interconnection at approximately unity power factor). The
voltage control settings of the Generating Facility must be coordinated with the Public Utility
prior to energization (or interconnection). The reactive compensation must be designed such
that the discreet switching of the reactive device (if required by the Interconnection Customer)
does not cause step voltage changes greater than +/-3% on the Public Utility’s system.

All generators must meet applicable WECC low voltage ride-through requirements as specified
in the interconnection agreement.

As per NERC standard VAR-001-1, the Public Utility is required to specify voltage or reactive
power schedule at the Point of interconnection. Under normal conditions, the Public Utility’s
system should not supply reactive power to the Generating Facility.
4.0 CLUSTER AREA DEFINITIONS
The Transmission Provider will perform the cluster study based on geographically and/or
electrically relevant areas on the Transmission Provider’s Transmission System known as Cluster
Areas. The Transmission Provider has determined that the Interconnection Requests discussed in
Transition Cluster Study Report
Transition Cluster Area 2 Page 7 March 31, 2021

Section 5.0 are located in a geographically and/or electrically relevant area on Transmission
Provider’s Transmission System, and thus, were assigned Cluster Area 2 in the Transition Cluster
Study process.
5.0 CLUSTER AREA 2
Cluster Area 2 (CA2) generally covers the geographic area which includes the Trona area (from
Rock Springs & Firehole substations to Monument substation), Naughton area (Southwest
Wyoming, Northeast Utah, Southeast Idaho), Park City area, Ogden area and Northern Utah
area. This area is predominantly impacted by Path C and Rock Springs/ Firehole paths.

Transition Cluster Study Report
Transition Cluster Area 2 Page 8 March 31, 2021

Craven Creek
Lima
Ben
Lomond
Birch
Creek
Canyon
Compression
STR
204 Muddy
Creek Mountain
Wind
Hinshaw
Wind
Long
HollowPainter
Naughton
Naughton #1
Naughton #2
Naughton #3
WyomingIdaho
Utah
Franklin
Honeyville
Brigham
City
Wheelon
Populus
Rock
Springs
El
MonteCold
Water
Syracuse
Parrish
Treasureton
Terminal
N/O N/O
Gadsby
Jordan
McClelland
Cottonwood
Snyderville Silver
Creek
Midvalley
90th South
Oquirrh
Tooele Jordanelle
Riverdale Weber Devils
Slide
Henefer
Coalville
Midway
Judge
Spanish
Fork
Parrish Tap
Grace
Park City
N/O Croydon
Railroad
345 kV
138 kV
230 kV
46 kV
12.5 kV
Bridgerland
Jim
Bridger
Point of
Rock
Atlantic
City
Little
Mountain
Firehole
RavenMonument
CA2
Figure 2 – Cluster Area

This Cluster Area shall consist of eight Interconnection Requests as follows.
Transition Cluster Study Report
Transition Cluster Area 2 Page 9 March 31, 2021

5.1 Description of Interconnection Request – TCS-10
The Interconnection Customer has proposed to interconnect 32.75 megawatts (“MW”) of new
generation to PacifiCorp’s (“Transmission Provider”) Promontory 46 kV substation located in
Box Elder County, Utah. The Interconnection Request is proposed to consist of twelve (12)
2.75 MW Sunny Central 2750 EV-US solar inverters for a total output of 32.75 MW at the
Point of Interconnection. The requested commercial operation date is November 1, 2023.
Figure 3 below, is a one-line diagram that illustrates the interconnection of the proposed
Generating Facility to the Transmission Provider’s system.

Interconnection Customer will operate this generator as a Qualified Facility as defined by the
Public Utility Regulatory Policies Act of 1978 (PURPA).

The Interconnection Request will be studied for Network Resource Interconnection Service
(“NRIS”).

The Transmission Provider has assigned the Project Cluster Number “TCS-10”
12.47kV
46-12.47 kV
30/50 MVA
Z=6.25%
TCS-10
BE SOLAR
32.75 MW Max
New
Facilities
Change of
Ownership
PROMONTORY
SUBSTATION
TO
LAMPO
TO
HONEYVILLE
M
Meter
46 kV
46 kV
52-F3
52-F4
52-F2
52-F1
2.75MVA
Z=5.75%, X/R=10
550V
5MVAZ=5.75%, X/R=12
550V
5MVA
Z=5.75%, X/R=12
550V
5MVAZ=5.75%, X/R=12
550V
12.47kV
DISTRIBUTION
Interconnection
SubstationAdjacent to
Promontory
~ 1 mile
Figure 3: Simplified System One Line Diagram for TCS-10
Transition Cluster Study Report
Transition Cluster Area 2 Page 10 March 31, 2021

5.2 Description of Interconnection Request – TCS-16
The Interconnection Customer has proposed to interconnect 80 megawatts (“MW”) of new
generation to PacifiCorp’s (“Transmission Provider”) Naughton–Treasureton 230 kV
transmission line located in Lincoln County, Wyoming. The Interconnection Request is
proposed to consist of twenty (20) 4.2 MW GE LV5 solar inverters for a total output of 80
MW at the Point of Interconnection. The requested commercial operation date is December
31, 2023. Figure 4 below, is a one-line diagram that illustrates the interconnection of the
proposed Generating Facility to the Transmission Provider’s system.

Interconnection Customer will NOT operate this generator as a Qualified Facility as defined
by the Public Utility Regulatory Policies Act of 1978 (PURPA).

The Interconnection Request will be studied for Network Resource Interconnection Service
(“NRIS”).

The Transmission Provider has assigned the Project Cluster Number “TCS-16”

34.5kV
52-C
New
Facilities
52-F1
52-F2
52-F3
7 Transformers/Inverters
7 Transformers/Inverters
+5 Transformers/Inverters
Change of
Ownership
M
230-34.5-19.9 kV
53/70/88 MVA230kV 52-TP
Meter Q0974 POI
PREVIOUSLY
PLANNED 230kV
SUBSTATION
~1 mile
TO NAUGHTON
SUBSTATION
(~26 mi)
TO TREASURETON
SUBSTATION
(~ 52.6 mi)
TCS-16
LINCOLN SOLAR II
80 MW Max
TO LINCOLN SOLAR I
(~ 0.1 mi)
PV ARRAY
550V
4.2MVA
Z=6.5%, X/R=8.5
R
Optical Fiber
Cable
Figure 4: Simplified System One Line Diagram for TCS-16
5.3 Description of Interconnection Request – TCS-17
The Interconnection Customer has proposed to interconnect 80 MW of new generation to
PacifiCorp’s (“Transmission Provider”) 3.3-mile on the Birch Creek – Railroad 230 kV
transmission line from Birch Creek 230 kV substation located in Rich County, Utah. The
Interconnection Request is proposed to consist of twenty-eight (28) 3.15 MVA Sungrow
SC3150U solar inverters for a total output of 80 MW at the Point of Interconnection. The
Interconnection Request also consists of 20 MW of six (6) 3.51 MVA Power Electronics HEM
battery storage with no capability to charge from the Transmission Provider’s grid. The
requested commercial operation date is December 31, 2023. Figure 5 below, is a one-line
diagram that illustrates the interconnection of the proposed Generating Facility to the
Transmission Provider’s system.
Transition Cluster Study Report
Transition Cluster Area 2 Page 11 March 31, 2021

Interconnection Customer will operate this generator as a Qualified Facility as defined by the
Public Utility Regulatory Policies Act of 1978 (PURPA).

The Interconnection Request will be studied for Network Resource Interconnection Service
(“NRIS”).

The Transmission Provider has assigned the Project Cluster Number “TCS-17”

34.5kV
New
Facilities
52-F1
52-F2
52-F3
7 Transformers/Inverters
+6 Transformers/Inverters
Change of
Ownership
230-34.5-??? kV
53/70/88 MVA
230kV52-TP
Meter
TCS-17 POI
230kV
SUBSTATION
~0.5 mile
TO RAILROAD
SUBSTATION
230kV
(15.91 mi)
TO BIRCH CREEK
SUBSTATION
230kV
(~ 3.3 mi)
PV ARRAY
550V
4.2MVA
Z=6.5%, X/R=8.5
TCS-17
Francis Road Solar I
80 MW Max
Optical Fiber
Cable
RM
M
7 Transformers/Inverters
52-C
Figure 5: Simplified System One Line Diagram for TCS-17
5.4 Description of Interconnection Request – TCS-19
The Interconnection Customer has proposed to interconnect 80 MW of new generation to
PacifiCorp’s (“Transmission Provider”) Chimney Butte 230 kV substation located in Sublette
County, Wyoming. The Interconnection Request is proposed to consist of twenty-five (25) 3.6
MW Sungrow SG3600UD-MV solar inverters for a total output of 80 MW at the Point of
Interconnection. The requested commercial operation date is October 1, 2023. Figure 6 below,
is a one-line diagram that illustrates the interconnection of the proposed Generating Facility to
the Transmission Provider’s system.

Interconnection Customer will operate this generator as a Qualified Facility as defined by the
Public Utility Regulatory Policies Act of 1978 (PURPA).

The Interconnection Request will be studied for Network Resource Interconnection Service
(“NRIS”).

The Transmission Provider has assigned the Project Cluster Number “TCS-19”

Transition Cluster Study Report
Transition Cluster Area 2 Page 12 March 31, 2021

34.5kV
New
Facilities
52-F1
52-C1
+7 Transformers/Inverters
Change of
Ownership
M
230-34.5-13.2 kV
52.8/70.4/88 MVA
230kV
52G1
Meter
CHIMNEY BUTTE
230kV
SUBSTATION
~0.25 miles
TO CIMAREX VIA
RILEY RIDGE SUBSTATION
230kV
(16 mi)
TCS-19 Piney Flats
Solar
80 MW Max
PV
ARRAY
2.5MVA
Z=5.75%
Optical Fiber
Cable
R
8 Transformers/Inverters
8 Transformers/Inverters
8 Transformers/Inverters
52-F2
TO CHAPPEL CREEK SUBSTATION 230kV
(18.6 mi)
PARADISE(FUTURE)
Figure 6: Simplified System One Line Diagram for TCS-19
5.5 Description of Interconnection Request – TCS-22
The Interconnection Customer has proposed to interconnect 80 MW of new generation to the
PacifiCorp’s (“Transmission Provider”) 3.3-mile on the Birch Creek – Railroad 230 kV
transmission line from Birch Creek 230 kV substation located in Rich County, Utah. The
Interconnection Request is proposed to consist of twenty-two (22) 4200 KVA GE LV5 solar
inverters for a total output of 80 MW at the Point of Interconnection. The Interconnection
Request also consists of 50 MW of nineteen (19) 2.84 MW Power Electronics FP2800 battery
storage with no capability to charge from the Transmission Provider’s grid. The requested
commercial operation date is December 31, 2022. Figure 7 below, is a one-line diagram that
illustrates the interconnection of the proposed Generating Facility to the Transmission
Provider’s system.

Interconnection Customer will operate this generator as a Qualified Facility as defined by the
Public Utility Regulatory Policies Act of 1978 (PURPA).

The Interconnection Request will be studied for Network Resource Interconnection Service
(“NRIS”).

The Transmission Provider has assigned the Project Cluster Number “TCS-22”

Transition Cluster Study Report
Transition Cluster Area 2 Page 13 March 31, 2021

34.5kV
New
Facilities
52-F1
52-F2
52-F3
19 BATTERY BLOCKS
7 Transformers/Inverters
+6 Transformers/Inverters
Change of
Ownership
230-34.5-??? kV105/140/175 MVA
230kV52-TP
Meter
~0.5 mile
TO RAILROAD
SUBSTATION
230kV
(15.91 mi)
TO BIRCH CREEK
SUBSTATION230kV
(~ 3.3 mi)
PV
ARRAY
550V
4.2MVAZ=6.5%, X/R=8.5
TCS-17 Francis Road Solar I
80 MW Max(Previous request)
Optical Fiber Cable
RM
M
M
MM
52-F6
52-F5
52-F4
7 Transformers/Inverters
+6 Transformers/Inverters
TCS-22 Francis Road Solar II 80 MW MaxPV ARRAY
550V
4.2MVA
Z=6.5%, X/R=8.5
M
M
MM
7 Transformers/Inverters
52-C
Figure 7: Simplified System One Line Diagram for TCS-22
5.6 Description of Interconnection Request – TCS-26
The Interconnection Customer has proposed to interconnect 50 MW of new generation to the
PacifiCorp’s (“Transmission Provider”) 6.7-mile on the Railroad – Croydon 138 kV
transmission line from Railroad 138 kV substation located in Uinta County, Wyoming. The
Interconnection Request is proposed to consist of eighteen (18) 2.82 MW Power Electronics
FS 2800 PV solar inverters with Sungrow SC3150U conversion system for a total output of 50
MW at the Point of Interconnection. The Interconnection Request also consists of 30 MW of
Power Electronics DC-DC battery storage with no capability to charge from the Transmission
Provider’s grid. The requested commercial operation date is December 31, 2022. Figure 8
below, is a one-line diagram that illustrates the interconnection of the proposed Generating
Facility to the Transmission Provider’s system.

Interconnection Customer will operate this generator as a Qualified Facility as defined by the
Public Utility Regulatory Policies Act of 1978 (PURPA).

The Interconnection Request will be studied for Network Resource Interconnection Service
(“NRIS”).

The Transmission Provider has assigned the Project Cluster Number “TCS-26”

Transition Cluster Study Report
Transition Cluster Area 2 Page 14 March 31, 2021

TCS-26 Uinta Solar and
Battery I
55 MW Max
34.5kV
New
Facilities
52-1 52-2 52-3
+7 Transformers
/Inverters/
PV+Batteries
Change of
Ownership
138-34.5-?? kV
55MVA
138kV
52G1
Meter
TCS-26 POI 138kV
SUBSTATION
~700ft
TO RAILROAD
SUBSTATION
138kV
(16 mi)
TO CROYDON
SUBSTATION
138kV
(18.6 mi)
3.2MVA
Z = 6%
R
138kV
8 Transformers
/Inverters/
PV+Batteries
8 Transformers
/Inverters/
PV+Batteries
M
M
MMM
Figure 8: Simplified System One Line Diagram for TCS-26
5.7 Description of Interconnection Request – TCS-31
The Interconnection Customer has proposed to interconnect 30 MW of new generation to the
PacifiCorp’s (“Transmission Provider”) 6.7-mile on the Railroad – Croydon 138 kV
transmission line from Railroad 138 kV substation located in Uinta County, Wyoming. The
Interconnection Request is proposed to consist of twelve (12) 2.55 MW Power Electronics FS
2800 PV solar inverters with Sungrow SC3150U conversion system for a total output of 30
MW at the Point of Interconnection. The Interconnection Request also consists of 15 MW of
Transition Cluster Study Report
Transition Cluster Area 2 Page 15 March 31, 2021

Power Electronics DC-DC battery storage with no capability to charge from the Transmission
Provider’s grid. The requested commercial operation date is December 31, 2022. Figure 9
below, is a one-line diagram that illustrates the interconnection of the proposed Generating
Facility to the Transmission Provider’s system.

Interconnection Customer will operate this generator as a Qualified Facility as defined by the
Public Utility Regulatory Policies Act of 1978 (PURPA).

The Interconnection Request will be studied for Network Resource Interconnection Service
(“NRIS”).

The Transmission Provider has assigned the Project Cluster Number “TCS-31”

TCS-26 Uinta Solar and
Battery II
45 MW Max
34.5kV
New
Facilities
52-1 52-2
+7 Transformers
/Inverters/PV+Batteries
Change of
Ownership
138-34.5-?? kV
55/72/90 MVA
138kV
52G1
Meter
TCS-26 POI 138kV
SUBSTATION
~700ft
TO RAILROAD
SUBSTATION
138kV
(16 mi)
TO CROYDON
SUBSTATION
138kV
(18.6 mi)
3.2MVA
Z = 6%
R
138kV
8 Transformers
/Inverters/
PV+Batteries
M
M
MM
52-3
M
52-4
12 Transformers
/Inverters/PV+Batteries
M
8 Transformers
/Inverters/
PV+Batteries Figure 9: Simplified System One Line Diagram for TCS-31
Transition Cluster Study Report
Transition Cluster Area 2 Page 16 March 31, 2021

5.8 Description of Interconnection Request – TCS-23
The Interconnection Customer has proposed to interconnect 50 megawatts (“MW”) of new
generation to PacifiCorp’s (“Transmission Provider”) Raven 34.5 kV substation located in
Sweetwater County, Wyoming. The Interconnection Request is proposed to consist of twenty-
two (22) 3.665 MW GE LV5 solar inverters for a total output of 50 MW at the Point of
Interconnection. The Interconnection Request also consists of 26.8 MW of Power Electronics
FP2800 battery storage with no capability to charge from the Transmission Provider’s grid.
The requested commercial operation date is December 31, 2022. Figure 10 below, is a one-
line diagram that illustrates the interconnection of the proposed Generating Facility to the
Transmission Provider’s system.

Interconnection Customer will NOT operate this generator as a Qualified Facility as defined
by the Public Utility Regulatory Policies Act of 1978 (PURPA).

The Interconnection Request will be studied for Network Resource Interconnection Service
(“NRIS”).

The Transmission Provider has assigned the Project Cluster Number “TCS-23”

Change of
Ownership
MeterM
34.5kV
52-F1
RAVEN
SUBSTATION
TCS-23 RAVEN SOLAR
AND BATTERY
STATION
50 MW Max
52MAIN
~1.5 mi
8 IDENTICAL BLOCKS
52-F2
3.51MVAZ=6%X/R=6.8
34.5kV
TR #2TR #1
230kV
Interconnection
Substation by Customer
Grounding
Transformer
TO BLACKS FORK
VIA WESTVACO
TO ROCK SPRINGS
VIA PALISADES
N
New
Facilities
R
52-F2
8 IDENTICAL BLOCKS
+7 IDENTICAL BLOCKS
PV ARRAY
BATTERY BANK
630 V

Figure 10: Simplified System One Line Diagram for TCS-23

Transition Cluster Study Report
Transition Cluster Area 2 Page 17 March 31, 2021

6.0 SITE SPECIFIC GENERATING FACILITY REQUIREMENTS
No additional Generating Facility specific requirements have been identified.
7.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS
7.1 Transmission System Requirements
The following transmission system improvements are required to accommodate the
Interconnection Requests in this Cluster Area:

• Rebuild 1.4 miles of the Silver Creek–Snyderville 138 kV transmission line and replace
the existing jumpers with higher ratings.
• Rebuild 17 miles of the Snyderville–Cottonwood 138 kV transmission line.
• Rebuild 23 miles of the Oneida–Ovid 138 kV transmission line.
• Replace the existing Ovid substation 138/69 kV 75/75/75 MVA transformer with 100
MVA transformer.
• Install 80 MVAR or larger cap banks at the Croydon 138 kV substation.
• Upgrade the existing Ben Lomond substation 345/230 kV 448/502/502 MVA transformer
#1 to a 700 MVA transformer.
• Upgrade the existing Ben Lomond substation 345/230 kV 448/502/502 MVA transformer
#2 to a 700 MVA transformer.
• Rebuild 14 miles of the Wheelon–Honeyville 138 kV transmission line.
• Rebuild 16 miles of the Ben Lomond–Honeyville 138 kV transmission line.
• Rebuild 16 miles of the Ben Lomond–Plain City 138 kV transmission line.
• Rebuild 43 miles of the Ovid–Sage Junction 69 kV transmission line.
• Rebuild 3 miles of the Birch Creek–TCS-17 POI 230 kV transmission line.
• Rebuild 53 miles of the Treasureton – Q974 POI 230 kV transmission line.
• Rebuild 55 miles of the Ben Lomond–Birch Creek 230 kV transmission line.
• Rebuild 16 miles of the Naughton–Craven Creek 230 kV transmission line.
• Replace the existing wavetraps and CTs on Naughton–Lima 230 kV transmission line
• Rebuild 1 mile of the Canyon Compression–Canyon Compression Tap 138 kV
transmission line.
• Rebuild 0.4 miles of the Canyon Compression Tap–Q715 POI 138 kV transmission line.
• Rebuild 5 miles of the Naughton–Glenco Tap 138 kV transmission line
• Rebuild 17 miles of the Glenco Tap–Structure (STR) 204 138 kV transmission line.
• Rebuild 0.4 miles of the Raven–Westvaco 230 kV transmission line.
• Rebuild 10 miles of the Westvaco–Blacks Fork 230 kV transmission line.
• Rebuild 7 miles of the Blacks Fork–Monument 230 kV transmission line.
• Modify a RAS associated with the Transmission Provider’s planned Path C Improvement
project to monitor the Populus–Bridgerland 345 kV line.

Refer to Appendix 1 for more details regarding the necessity for these required upgrades.

TCS-10
Transition Cluster Study Report
Transition Cluster Area 2 Page 18 March 31, 2021

Expand the Promontory 46 kV substation and install a new four breaker ring bus including
four circuit breakers. The existing bus work will need to be removed. A new 46 kV transrupter
will need to be installed to protect the existing transformers.

TCS-16
Expand the proposed Q0974 POI substation to a breaker and a half configuration in order to
create a new line position to serve as the POI including three 230 kV circuit breakers and six
230 kV circuit switches.

TCS-17 and TCS-22
Construct a new 230 kV three breaker ring bus substation to serve as the POI. Loop the Birch
Creek-Railroad transmission line in/out of the new substation.

TCS-19
Install one 230 kV circuit breaker and two 230 kV circuit switches in Chimney Butte substation
to create a new line position which will serve as the POI.

TCS-23
Expand the Raven substation 34.5 kV bus by installing six 34.5 kV switches, two 34.5kV
breakers, and a new line position.

TCS-26 and TCS-31
Construct a new 138 kV three breaker ring bus substation to serve as the POI. Loop the
Croydon-Railroad transmission line in/out of the new substation.
7.2 Distribution System Requirements
No improvements to the Transmission Provider’s distribution system have been determined
as necessary for this Cluster Area.
7.3 Transmission Line Requirements
The following transmission lines require upgraded conductor.

Silver Creek – Snyderville 138 kV
Approximately 1.413 miles requires the existing 397.5 ACSR conductor to be replaced with
1272 ACSR conductor. This reconductor will require the full rebuild of the double circuit
line segment.

Cottonwood – Silver Snyderville 138 kV
Approximately 0.54 miles requires the existing 500 AAC conductor to be replaced with 1272
ACSR conductor. This reconductor will require the full rebuild of the double circuit line
segment supporting this circuit. The existing conductor of the other side of the double circuit
would be transferred to the new poles.

Oneida – Ovid 138 kV
Transition Cluster Study Report
Transition Cluster Area 2 Page 19 March 31, 2021

Approximately 22.85 miles requires the existing mix of 336.4 ACSR and 397.5 ACSR
conductor to be replaced with 795 ACSR conductor. This reconductor will require the full
rebuild of the existing line.

Ben Lomond – Honeyville – Wheelon 138 kV
Approximately 30.22 miles requires the existing 250 Copper conductor to be replaced with
795 ACSR conductor. The reconductor of this line will require the full rebuild of the existing
line.

Ben Lomond – Plain City 138 kV
Approximately 1.87 miles requires the existing 250 Copper conductor to be replaced with
795 ACSR conductor. The reconductor of this line will require the full rebuild of the existing
line.

Ovid – Sage 138 kV
Approximately 43.46 miles requires the existing 397.5 ACSR conductor to be replaced with
795 ACSR conductor. The reconductor of this line will require the full rebuild of the existing
line.

Birch Creek - Railroad 230 kV
Approximately 3.3-mile segment requires the existing 954 ACSR conductor from Birch
Creek to the new TCS-17 POI substation to be replaced with 2x1272 ACSR conductor. The
reconductor of this line will require the full rebuild of this line segment.

Naughton - Treasureton 230 kV
Approximately 52.58-mile segment requires the existing single 1272 ACSR conductor from
Treasureton to the new Q974 POI substation to be replaced with 2x1272 ACSR conductor.
The reconductor of this line will require the full rebuild of this line segment.

Ben Lomond - Birch Creek 230 kV
Approximately 55.13 miles requires the existing 2x795 ACSR conductor (existing double
bundle) to be replaced with 2x1272 ACSR conductor. The reconductor of this line will
require the full rebuild of the existing line.

Naughton - Craven Creek 230 kV
Approximately 15.88 miles requires the existing 954 ACSR conductor to be replaced with
1272 ACSR conductor. Review of this line shows that the existing tangent structures have
the required strength to accommodate the larger conductor size. Existing deadend and angle
structures are assumed to need replacement due to increased conductor tension of the larger
conductor. It is also assumed that approximately ten of the existing tangent structures will
need to be replaced to provide additional ground clearance as required for the larger
conductor size and increased conductor sag.

Canyon Compression - Railroad 138 kV
Approximately 1.41-mile segment requires the existing 795 ACSR conductor from Canyon
Compression to the new Q0715 POI substation to be replaced with 1272 ACSR conductor.
Transition Cluster Study Report
Transition Cluster Area 2 Page 20 March 31, 2021

Several the existing tangent structures in this line segment will accommodate the increased
conductor size while the existing deadend structures will need to be replaced due to increased
conductor tension of the larger conductor.

Naughton – Glenco Tap – Evanston 138 kV
Approximately 22.3-mile segment requires the existing 795 ACSR conductor from Naughton
south to the tap to Canyon Compression (Str 204) to be replaced with 1272 ACSR conductor.
The reconductor of this line segment will require the full rebuild of this line segment.

Raven – Westvaco – Blacks Fork – Monument 230 kV
Approximately 17.04 miles requires the existing 795 ACSR conductor to be replaced with
2x795 ACSR conductor. The reconductor of this line will require a full line rebuild.

Connection of two new POI substations will require transmission lines to be looped in/out of
the new substations.

The Birch Creek – Railroad 230 kV line will loop through a new TCS-17 POI substation.
This new substation is assumed to be approximately 0.5 miles from the existing transmission
line.

The Croydon – Railroad 138kV line will loop through a new TCS-26 POI substation. This
new substation is assumed to be at the POI location requested by the TCS-26 Interconnection
Customer. To avoid a new transmission line crossing over I-80 it is assumed that the existing
transmission line will be tapped where it crosses to the south side of I-80, west of the
Utah/Wyoming state line. This will require approximately 0.75 miles of double circuit 138kV
transmission line to connect to the POI substation located in Wyoming.

Coordination of the exact location for each POI substation will be required and the exact line
route/length and resulting cost for the new transmission line could vary.

Each of the Interconnection Requests in this Cluster Area shall construct its last structure and
span/bus connection into the POI substation to Transmission Provider standards. The
Transmission Provider will review the design of the Interconnection Customer line for the
last span into the POI substations. The Interconnection Customers shall coil enough fiber and
conductor on the last deadend structure to make the span into the POI substations. The
Transmission Provider shall construct the final terminations into the POI substations.

If the Interconnection Customer’s tie line is required to cross a Transmission Provider line,
the Interconnection Custer shall make application with the Transmission Provider to do so.
The Customer’s line shall cross below the Transmission Provider’s line in all cases unless is
Customer’s line is of a higher voltage.
7.4 Existing Circuit Breaker Upgrades – Short Circuit
TCS-10
The addition of the TCS-10 generation facility with 7 transformer-inverter blocks, with
transformers of 2.75MVA MVA, Z=5.75% transformers, in Figure 3, will cause an increase
Transition Cluster Study Report
Transition Cluster Area 2 Page 21 March 31, 2021

in the system’s fault duty which will not violate the interrupting capacity of any of the existing
interrupting equipment at or around Promontory substation.

TCS-16
The addition of the TCS-16 generation facility with 20 transformer-inverter blocks, with
transformers of 4.2 MVA, Z=6.5% transformers, and a main 230-34.5kV, 88MVA three-
winding transformer as shown in Figure 4, will cause an increase in the system’s fault duty
which will not violate the interrupting capacity of any of the existing interrupting equipment
of Naughton, Treasureton, or the Q0974 POI 138kV substations.

TSC-17
The addition of the TCS-17 generation facility with 21 transformer-inverter blocks, with
transformers of 4.2 MVA, Z=6.5% transformers, and a main 230-34.5kV, 88MVA three-
winding transformer as shown in Figure 5, will cause an increase in the system’s fault duty
which will not violate the interrupting capacity of any of the existing interrupting equipment
in the neighborhood of Birch Creek and Railroad 230 kV substations.

TCS-19
The addition of the TCS-19 generation facility with 24 transformer-inverter blocks, with
transformers of 2.5 MVA, Z=5.75% transformers, and a main 230-34.5kV, 88MVA three-
winding transformer as shown in Figure 6, will cause an increase in the system’s fault duty
which will not violate the interrupting capacity of any of the existing interrupting equipment
in the neighborhood of Chimney, Chappell Creek and Riley Ridge 230 kV substations.

TCS-22
The addition of the TCS-22 generation facility with 14 transformer-inverter blocks, with
transformers of 4.2 MVA, Z=6.5% transformers, and a main 230-34.5kV, 175MVA three-
winding transformer as shown in Figure 7, will cause an increase in the system’s fault duty
which will not violate the interrupting capacity of any of the existing interrupting equipment
in the neighborhood of Birch Creek and Railroad 230 kV substations.

TCS-26
The addition of the TCS-26 generation facility with 24 transformer-inverter blocks, with
transformers of 3.2 MVA, Z=6.%, and a main 138-34.5kV, 55MVA three-winding transformer
as shown in Figure 8, will cause an increase in the system’s fault duty which will not violate
the interrupting capacity of any of the existing interrupting equipment in the neighborhood of
Croydon and Railroad 138 kV substations.

TCS-31
The addition of the TCS-26 generation facility with 24 transformer-inverter blocks, with
transformers of 3.2 MVA, Z=6.%, and a main 230-34.5kV, upgraded to 55/72/90 MVA three-
winding transformer as shown in Figure 9, will cause an increase in the system’s fault duty
which will not violate the interrupting capacity of any of the existing interrupting equipment
in the neighborhood of Croydon and Railroad 138 kV substations.

TCS-23
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Transition Cluster Area 2 Page 22 March 31, 2021

The addition of the TCS-23 generation facility with 24 transformer-inverter blocks, with
transformers of 3.51 MVA, Z=6% transformers, including a 20 ohms grounding transformer
as shown in Figure 10, will cause an increase in the system’s fault duty which will not violate
the interrupting capacity of any of the existing interrupting equipment of Raven, 34.5kV or
230kV.
7.5 Protection Requirements
Relay settings will be updated for all of the transmission lines that are required to be
reconductored. This will include updates at the following substations.
• Silver Creek
• Snyderville
• Cottonwood
• Oneida
• Ovid
• Wheelon
• Honeyville
• Ben Lomond
• Plain City
• Sage Junction
• Birch Creek
• Treasureton
• Naughton
• Craven Creek
• Canyon Compression
• Westvaco
• Blacks Fork
• Monument

Relay settings will be created/modified for the new Ovid substation transformer, Croydon
substation capacitor banks and Ben Lomond substation transformer.

TCS-10
Expand the Promontory 46 kV substation and install a new four breaker ring bus including
four circuit breakers.

Since the POI and the collector substations will be adjacent to each other, the ground mats of
the two substations can be tied together. This will permit the use of metallic control cables
between the substations. The line between POI substation and the Interconnection Customer’s
collector substation will be protected with a bus differential relay system. The maximum ratio
of the bushing CTs associated with the customer’s circuit breaker must be the same as the one
for the new ring in the Promontory substation.

Relay elements in the line relays at the Promontory substation will monitor the line voltages.
If the voltage, magnitude or frequency, is outside of the normal operation range these relay
elements will trip open the 46 kV tie line breakers.
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Line differential relays will be updated for the lines to Lampo and Honeyville substation.
Overcurrent protection will be applied for the transformer.

TCS-16
Line current differential relay systems will be applied for 230 kV tie line. The Transmission
Provider will install, own, and maintain a relay panel at the TCS-16 collector substation with
line relays that will be compatible with the line relays to be installed at POI Substation. The
line relays at the collector substation will communicate with the line relays at POI substation
over a communication path. The relays on this panel will be connected to monitor the current
through the 230 kV transformer breaker at the collector and the voltage on the 230 kV line.
For faults on the tie line the line breakers at the POI Substation and the transformer breaker at
the collector substation will be tripped.

Relay elements in the line relays at the POI substation will monitor the line voltages. If the
voltage, magnitude or frequency, is outside of the normal operation range these relay elements
will trip open the 230 kV tie line breakers at the POI Substation.

TCS-17 and TCS-22
Redundant line current differential relay systems will be applied for 230 kV tie line. The
Transmission Provider will install, own, and maintain a relay panel at the shared TCS-17/22
collector substation with line relays that will be compatible with the line relays to be installed
at POI Substation. The line relays at the collector substation will communicate with the line
relays at POI substation over a communication path. The relays on this panel will be connected
to monitor the current through the 230 kV transformer breaker at the collector and the voltage
on the 230 kV line. For faults on the tie line the line breakers at the POI Substation and the
transformer breaker at the collector substation will be tripped.

Relay elements in the line relays at the POI substation will monitor the line voltages. If the
voltage, magnitude or frequency, is outside of the normal operation range these relay elements
will trip open the 230 kV tie line breakers at the POI Substation.

POTT line protection scheme will be applied for the 15.9-miles 230 kV line to Railroad
substation. Line current differential protection will be applied for the 230 kV line to
Birchcreek. This requires a replacement of the line protection panel at Birch Creek with a new
panel with new relays set for line differential.

TCS-19
Line current differential relay systems will be applied for 230 kV tie line. The Transmission
Provider will install, own, and maintain a relay panel at the TCS-16 collector substation with
line relays that will be compatible with the line relays to be installed at POI Substation. The
line relays at the collector substation will communicate with the line relays at POI substation
over a communication path. The relays on this panel will be connected to monitor the current
through the 230 kV transformer breaker at the collector and the voltage on the 230 kV line.
For faults on the tie line the line breakers at the POI Substation and the transformer breaker at
the collector substation will be tripped.
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Relay elements in the line relays at the POI substation will monitor the line voltages. If the
voltage, magnitude or frequency, is outside of the normal operation range these relay elements
will trip open the 230 kV tie line breakers at the POI Substation.

TCS-26 and TCS-31
Since the POI and the collector substations will be adjacent to each other, the ground mats of
the three substations can be tied together. This will permit the use of metallic control cables
between the substations. The line between POI substation and the Interconnection
Customers’ collector substations will be protected with a bus differential relay system. The
maximum ratio of the bushing CTs associated with the customer’s circuit breaker must be the
same as the one for the new ring in the Promontory substation.

Relay elements in the line relays at the Promontory substation will monitor the line voltages.
If the voltage, magnitude or frequency, is outside of the normal operation range these relay
elements will trip open the 46 kV tie line breakers.

POTT line protection scheme will be applied for the lines to Railroad and Croydon
substations. The new relays must be time-synchronized with the existing relay at Railroad
and Croydon. Communications with the POI substation must be added.

TCS-23
The Interconnection Customer will be required to build a tie line substation adjacent to the POI
substation with a 34.5 kV breaker. The ground mats of the POI substation and the
Interconnection Customer’s tie line substation will be tie together so that metallic control
cables can be used for protection and control circuits between the two substations. The
Interconnection Customer will be responsible for the line relays to detect faults on the 34.5 kV
tie line between its tie line substation and collector substation. The tie line between the POI
substation the Interconnection Customer’s tie line substation will be protected with a bus
differential relay system. The Interconnection Customer will need to provide the output from
a set of current transformers from the 34.5 kV tie line breaker. These currents will be fed into
the bus differential relays. If a fault is detected both the 34.5 kV breakers in the POI substation
and the 34.5 kV breaker in the tie line substation will be tripped. A set of line relays set in a
backup mode will be installed in POI substation to monitor the current and voltages on the tie
line. Relay elements in the line relays monitor the line voltages. If the voltage, magnitude or
frequency, is outside of the normal operation range these relay elements will trip open the 34.5
kV tie line breaker.
7.6 Data (RTU) Requirements
The Transmission Provider will update its EMS system to provide data from the new/upgraded
equipment required for this Cluster Area including the new Ovid substation transformer,
Croydon substation capacitor banks and Ben Lomond substation transformers

Status points of all Interconnection Customer equipment including breakers, transformers,
capacitor, etc. will be required. A detailed list of points will be developed during the facilities
study.
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TCS-10
The Interconnection Customer will hard wire its source devices from its collector substation to
a marshalling cabinet to be installed on the POI substation fence line. The following points
will be required for this Interconnection Request.

Analogs
• Irradiance
• Ambient temperature
• Average Plant Atmospheric Pressure (Bar)
• Max Gen Limit MW Set Point Feed Back
• Potential Power MW

Send analog quantities
• Max Gen Limit MW Set Point

TCS-16
The Interconnection Customer will hard wire its source devices from its collector substation to
the Transmission Provider’s data concentrator to be installed in the Transmission Provider’s
collector substation control building. The following points will be required for this
Interconnection Request.

Analogs
• Irradiance
• Ambient temperature
• Average Plant Atmospheric Pressure (Bar)
• Max Gen Limit MW Set Point Feed Back
• Potential Power MW

Send analog quantities
• Max Gen Limit MW Set Point

TCS-17
The Interconnection Customer will hard wire its source devices from its collector substation to
the Transmission Provider’s data concentrator to be installed in the Transmission Provider’s
collector substation control building. The following points will be required for this
Interconnection Request.

Analogs
• Irradiance
• Ambient temperature
• Average Plant Atmospheric Pressure (Bar)
• Max Gen Limit MW Set Point Feed Back
• Potential Power MW

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Transition Cluster Area 2 Page 26 March 31, 2021

Send analog quantities
• Max Gen Limit MW Set Point

TCS-19
The Interconnection Customer will hard wire its source devices from its collector substation to
the Transmission Provider’s data concentrator to be installed in the Transmission Provider’s
collector substation control building. The following points will be required for this
Interconnection Request.

Analogs
• Irradiance
• Ambient temperature
• Average Plant Atmospheric Pressure (Bar)
• Max Gen Limit MW Set Point Feed Back
• Potential Power MW

Send analog quantities
• Max Gen Limit MW Set Point

TCS-22
The Interconnection Customer will hard wire its source devices from its collector substation to
the Transmission Provider’s data concentrator to be installed in the Transmission Provider’s
collector substation control building. The following points will be required for this
Interconnection Request.

Analogs
• Irradiance
• Ambient temperature
• Average Plant Atmospheric Pressure (Bar)
• Max Gen Limit MW Set Point Feed Back
• Potential Power MW

Send analog quantities
• Max Gen Limit MW Set Point

TCS-26
The Interconnection Customer will hard wire its source devices from its collector substation to
a marshalling cabinet to be installed on the POI substation fence line. The following points
will be required for this Interconnection Request.

Analogs
• Irradiance
• Ambient temperature
• Average Plant Atmospheric Pressure (Bar)
• Max Gen Limit MW Set Point Feed Back
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• Potential Power MW

Send analog quantities
• Max Gen Limit MW Set Point

TCS-31
The Interconnection Customer will hard wire its source devices from its collector substation to
a marshalling cabinet to be installed on the POI substation fence line. The following points
will be required for this Interconnection Request.

Analogs
• Irradiance
• Ambient temperature
• Average Plant Atmospheric Pressure (Bar)
• Max Gen Limit MW Set Point Feed Back
• Potential Power MW

Send analog quantities
• Max Gen Limit MW Set Point

TCS-23
The Interconnection Customer will install a Transmission Provider approved data concentrator
in its collector substation and hard wire its source devices to the data concentrator. The data
points are to be brought back to the POI substation by the Interconnection Customer. The
following points will be required for this Interconnection Request.

Analogs
• Irradiance
• Ambient temperature
• Average Plant Atmospheric Pressure (Bar)
• Max Gen Limit MW Set Point Feed Back
• Potential Power MW

Send analog quantities
• Max Gen Limit MW Set Point
7.7 Substation Requirements
Ben Lomond Substation
To meet the new transmission line ratings, the substation conductors on the 230 kV line to
Birch Creek will be replaced and the bay equipment will be upgraded. Two, 345-230 kV
autotransformers will be replaced with larger units. The fault duty is increasing above the
interrupting capability of the 138 kV breakers. The substation fence will be expanded to
encompass a new 138 kV breaker and a half yard to the west of the existing substation. A
new control house will be installed for the protection and control, metering, communication,
and SCADA equipment. A CDEGS grounding analysis will be performed. The following
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major equipment has been identified as being required and may change during detailed
design.
• 2 – 345-230 kV, autotransformer
• 3 – 230 kV, circuit breaker
• 6 – 230 kV, switch, breaker disconnect
• 30 – 138 kV, circuit breaker
• 72 – 138 kV, switch
• 40 – 138 kV, CCVT
• 30 – 138 kV, arrester

Birch Creek Substation
The new transmission line ratings push the existing substation equipment and conductors
above their current ratings and will be replaced. A CDEGS grounding analysis will be
performed. The following equipment has been identified as being required and may change
during detailed design.
• 3 – 230 kV, circuit breaker
• 10 – 345 kV, switch, breaker disconnect

Blacks Fork Substation
To meet the new transmission line ratings, the substation jumpers on the 230 kV line to
Monument will be replaced. Some of the 230 kV bay equipment and conductor will be
upgraded. A CDEGS grounding analysis will be performed. The following equipment has
been identified as being required and may change during detailed design.
• 1 – 230 kV, switch

Canyon Compression Substation
To meet the new transmission line ratings, the substation jumpers on the 138 kV line to
Railroad will be replaced. A CDEGS grounding analysis will be performed.

Cottonwood Substation
To meet the new transmission line ratings, the substation jumpers on the 138 kV line to
Snyderville will be replaced. A CDEGS grounding analysis will be performed.

Croydon Substation
The east and west 138 kV busses will be expanded to the north. Four, 138 kV shunt
capacitors will be installed. The substation fence will be expanded to support the project. A
CDEGS grounding analysis will be performed. New relay panels will be installed. The
following equipment has been identified as being required and may change during detailed
design.
• 4 – 138 kV, circuit breaker
• 4 – 138 kV, switch
• 4 – 138 kV, shunt capacitor, with current limiting reactor

Honeyville Substation
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To meet the new transmission line ratings, the substation jumpers on the 138 kV line to Ben
Lomond and the 138 kV line to Wheelon will be replaced. A CDEGS grounding analysis
will be performed.

Monument Substation
To meet the new transmission line ratings, the substation jumpers on the 230 kV line to
Blacks Fork will be replaced. Some of the 230 kV bay equipment and conductor will be
upgraded. A CDEGS grounding analysis will be performed. The following equipment has
been identified as being required and may change during detailed design.
• 5 – 230 kV, switch
• 3 – 230 kV, arrester

Naughton Substation
To meet the new transmission line ratings, the substation jumpers on the 230 kV line to
Craven Creek and the 138 kV line to Glenco Tap will be replaced. A CDEGS grounding
analysis will be performed.

Oneida Substation
To meet the new transmission line ratings, the substation jumpers on the 138 kV line to Ovid
will be replaced. A CDEGS grounding analysis will be performed.

Ovid Substation
To meet the new transmission line ratings, the substation jumpers on the 138 kV line to
Oneida and the 69 kV line to Sage Junction will be replaced. One, 138-69 kV transformer
will be replaced with a higher rated unit. A CDEGS grounding analysis will be performed.

Plain City Substation
A CDEGS grounding analysis will be performed.

Raven Substation
To meet the new transmission line ratings, the substation jumpers on the 230 kV line to
Westvaco will be replaced. Some of the 230 kV bay equipment and conductor will be
upgraded. A CDEGS grounding analysis will be performed. The following equipment has
been identified as being required and may change during detailed design.
• 5 – 230 kV, switch
• 3 – 230 kV, arrester

Silver Creek Substation
To meet the new transmission line ratings, the substation jumpers on the 138 kV line to
Snyderville will be replaced. A CDEGS grounding analysis will be performed.

Snyderville Substation
A CDEGS grounding analysis will be performed.

Treasureton Substation
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To meet the new transmission line ratings, the substation jumpers on the 230 kV line to
Naughton will be replaced. The 230 kV bay equipment and conductor will be upgraded. A
CDEGS grounding analysis will be performed. The following equipment has been identified
as being required and may change during detailed design.
• 3 – 230 kV, circuit breaker
• 6 – 230 kV, switch, breaker disconnect

Westvaco Substation
The substation will be expanded to support the installation of a three breaker, 230 kV ring
bus adjacent to the existing substation yard. A new control house will be installed for the
protection and control, metering, communication, and SCADA equipment. A CDEGS
grounding analysis will be performed. The following equipment has been identified as being
required and may change during detailed design.
• 3 – 230 kV, breaker
• 10 – 230 kV, switch
• 6 – 230 kV, CCVT
• 9 – 230 kV, arrester

Wheelon Substation
To meet the new transmission line ratings, the substation jumpers on the 138 kV line to
Honeyville will be replaced. The breaker disconnect switches for CB 114 will be replaced.
A CDEGS grounding analysis will be performed.

Honeyville Substation
A new relay panel will be installed; relay settings will be developed. A CDEGS grounding
analysis will be performed.

Lampo Substation
A new relay panel will be installed; relay settings will be developed. A CDEGS grounding
analysis will be performed.

Birch Creek Substation
One relay panel will be replaced; relay settings will be developed. A CDEGS grounding
analysis will be performed.

Railroad Substation
One relay panel will be replaced; relay settings will be developed. A CDEGS grounding
analysis will be performed.

TCS-10
TCS-10 Collector Substation
The TCS-10 collector substation and the Promontory substation ground grids will be tied
together. All conduit and cable to the marshalling cabinet inside Promontory Substation will
be the responsibility of the Customer. A CDEGS grounding analysis will be provided by the
Customer.

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Promontory Substation
The substation fence will be expanded to support the installation of a four breaker 46 kV ring
bus. A new control house will be installed for the protection and control, metering,
communication, and SCADA equipment. The Promontory Substation and TCS-10
interconnection station ground grids will be tied together. A CDEGS grounding analysis will
be performed. A marshalling cabinet will be installed to facilitate the control cable transition
between the two yards. The following major equipment has been identified as being required
and may change during detailed design.
• 4 – 69 kV, circuit breaker
• 19 – 69 kV, switch
• 3 – 46 kV, combined CT/VT metering instrument transformer
• 9 – 46 kV, CCVT
• 1 – 69 kV, transrupter
• 9 – 46 kV, arrester
• 1 – Marshalling cabinet

TCS-16
TCS-16 Collector Station
The Interconnection Customer will provide a separate graded, grounded and fenced area
along the perimeter of the Interconnection Customer’s Generating Facility for the
Transmission Provider to install a control house for any required metering, protection and/or
communication equipment. This area will share a fence and ground grid with the Generating
Facility and have separate, unencumbered access for the Transmission Provider. The
Customer shall perform and provide a CDEGS grounding analysis. AC and DC power for
the control house will be supplied by the Transmission Provider.

Q0974 POI Substation
A new 230 kV line position to the TCS-16 Collector station will be added to the Q0974 POI
substation. The following equipment has been identified as being required and may change
during detailed design.
• 1 – 230 kV, circuit breaker
• 3 – 230 kV, switch
• 3 – 230 kV, CT/VT metering instrument transformer
• 3 – 230 kV, arrester

TCS-17 and TCS-22
TCS-17 and TCS-22 Shared Collector Station
The Interconnection Customer will provide a separate graded, grounded and fenced area
along the perimeter of the Interconnection Customer’s Generating Facility for the
Transmission Provider to install a control house for any required metering, protection and/or
communication equipment. This area will share a fence and ground grid with the Generating
Facility and have separate, unencumbered access for the Transmission Provider. The
Customer shall perform and provide a CDEGS grounding analysis. AC and DC power for
the control house will be supplied by the Transmission Provider. Twenty-Four, 34.5 kV
combined CT/VT metering instrument transformers will be installed. The Customer shall
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provide a disconnect switch on each side of each instrument transformer. Metering panels
will be installed in the control house.

POI Substation
A new 230 kV, three breaker ring bus substation will be constructed in the existing 230 kV
line between Railroad and Birch Creek substations. A new control house will be installed for
the protection and control, metering, communication, and SCADA equipment. A CDEGS
grounding analysis will be performed. The following major equipment has been identified as
being required and may change during detailed design.
• 3 – 230 kV, circuit breaker
• 12 – 230 kV, switch
• 3 – 138 kV, combined CT/VT metering instrument transformer
• 6 – 138 kV, CCVT
• 9 – 138 kV, arrester
• 1 – 138 kV, SSVT
• 1 – Emergency generator

TCS-19
TCS-19 Collector Substation
The Interconnection Customer will provide a separate graded, grounded and fenced area
along the perimeter of the Interconnection Customer’s Generating Facility for the
Transmission Provider to install a control house for any required metering, protection and/or
communication equipment. This area will share a fence and ground grid with the Generating
Facility and have separate, unencumbered access for the Transmission Provider. The
Customer shall perform and provide a CDEGS grounding analysis. AC and DC power for
the control house will be supplied by the Transmission Provider.

Chimney Butte Substation
The east and west 230 kV bus will be expanded to the south to construct a third 230 kV bay.
The substation fence will be expanded. The Chappel Creek 230 kV line position and the
future Paradise 230 kV line position will each be moved one bay to the south to
accommodate the new 230 kV line to the TCS-19 collector station. The TCS-19 line will
enter the substation in the former position for the future line to Paradise. A CDEGS
grounding analysis will be performed. New relay panels will be installed. The following
major equipment has been identified as being required and may change during detailed
design.

• 2 – 230 kV, circuit breaker
• 3 – 230 kV, combined CT/VT metering instrument transformer
• 3 – 230 kV, CCVT
• 3 – 230 kV, arrester
• 6 – 230 kV, switch, breaker disconnect
• 2 – 230 kV, switch, line disconnect
• 1 – 230 kV, switch, metering instrument transformer disconnect

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TCS-26 and TCS-31
TCS-26 Collector Station
The TCS-26 POI and TCS-26 collector substation ground grids will be tied together. All
conduit and cable to the marshalling cabinet inside the TCS-26 POI substation will be the
responsibility of the Interconnection Customer. Twelve, 34.5 kV combined CT/VT metering
instrument transformers will be installed. The Interconnection Customer shall provide a
disconnect switch on each side of each instrument transformer. Metering panels will be
installed in the control house.

POI Substation
A new 138 kV, three breaker ring bus substation will be constructed in the existing 138 kV
line between Railroad and Croydon substations. A new control house will be installed for the
protection and control, metering, communication, and SCADA equipment. A CDEGS
grounding analysis will be performed. A marshalling cabinet will be installed to facilitate the
control cable transition between the two yards. The following major equipment has been
identified as being required and may change during detailed design.
• 3 – 138 kV, circuit breaker
• 13 – 138 kV, switch
• 3 – 138 kV, combined CT/VT metering instrument transformer
• 6 – 138 kV, CCVT
• 9 – 138 kV, arrester
• 1 – 138 kV, SSVT
• 1 – Emergency generator
• 1 – Marshalling cabinet

TCS-23
TCS-23 Tie Line Substation
The TCS-23 tie line substation and the Raven substation ground grids will be tied together.
All conduit and cable to the marshalling cabinet inside Raven substation will be the
responsibility of the Interconnection Customer. A CDEGS grounding analysis will be
provided by the Interconnection Customer.

Raven Substation
The Raven Substation fence will be expanded to install an additional 34.5 kV bay on the
north side of the substation. The TCS-23 interconnection substation and the Raven
Substation ground grids will be tied together. A CDEGS grounding analysis will be
performed. A marshalling cabinet will be installed to facilitate the control cable transition
between the two yards. The following major equipment has been identified as being required
and may change during detailed design.
• 2 – 34.5 kV, circuit breaker
• 7 – 34.5 kV, switch
• 3 – 34.5 kV, combined CT/VT metering instrument transformer
• 3 – 34.5 kV, arrester
• 1 – Marshalling cabinet
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7.8 Communication Requirements
Approximately 3.1 miles of OPGW will be installed between Lampo substation and
Promontory substation. Relaying between Promontory and Lampo substations will be direct
fiber. Communications equipment will be installed at both substations.

Install approximately 53 miles of OPGW between Treasureton substation and the Q0974 POI
substation. Communications equipment will be installed at both substations.

Install approximately 18.6 miles of OPGW between Croydon substation and the TCS-26 POI
substation. Communications equipment will be installed at both substations.

TCS-10
Communications equipment will be installed in the POI substation to support the metering
and SCADA communications.

TCS-16
The Interconnection Customer will install Transmission Provider approved fiber optic cable
on its tie line between its collector substation and the POI substation. This fiber will be
owned and maintained by the Transmission Provider and used to provide relaying and data
signals. The Transmission Provider will terminate the fiber in its control buildings at both
sites. Communications equipment will be installed in the POI substation to support the
metering and SCADA communications.

TCS-17 and TCS-22
The Interconnection Customers will install Transmission Provider approved fiber optic cable
on the tie line between the shared collector substations and the POI substation. This fiber
will be owned and maintained by the Transmission Provider and used to provide relaying and
data signals. The Transmission Provider will terminate the fiber in its control buildings at
both sites. Communications equipment will be installed in the POI substation to support the
metering and SCADA communications.

TCS-19
The Interconnection Customer will install Transmission Provider approved fiber optic cable
on its tie line between its collector substation and the POI substation. This fiber will be
owned and maintained by the Transmission Provider and used to provide relaying and data
signals. The Transmission Provider will terminate the fiber in its control buildings at both
sites. Communications equipment will be installed in the POI substation to support the
metering and SCADA communications.

TCS-26 and TCS-31
Communications equipment will be installed in the POI substation to support the metering
and SCADA communications.

TCS-23
The Interconnection Customer will install Transmission Provider approved fiber optic cable
on its tie line between its collector substation and the POI substation in order to provide the
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Transmission Provider the required data. The Transmission Provider will terminate the fiber
in the POI substation. Communications equipment will be installed in the POI substation to
support the metering and SCADA communications.
7.9 Metering Requirements
Ovid Substation
Update CT ratio on existing meter at Ovid.

Q0974 POI substation
Update CT ratio on state line meter at Q0974.

Birch Creek substation
CT ratio on state line meter at Birch Creek substation.

Naughton substation
Update existing metering at Naughton on this line for the new CTs.

Birch Creek
The existing state line meter at Birch Creek may be affected by the rebuild of the Ben
Lomond–Birch Creek 230 kV transmission line. The CT ratio for the state line meter should
be revised, if needed.

TCS-10
Interchange Metering
The overall project metering will be located at the Point of Interconnection at Promontory
substation and rated for the total net generation of the Project. The Transmission Provider
will specify and order all interconnection revenue metering, including the instrument
transformers, meters, meter panel, junction box, and secondary metering wire. The primary
metering transformers will be combination 46kV CT/VT units with extended range CTs for
high-accuracy metering.

The metering design package will include two revenue quality meters with DNP real time
digital data terminated at a metering interposition block. One meter will be designated as
primary SCADA meter with DNP data delivered to the primary control center. A second
meter will be designated as backup SCADA meter with DNP data delivered to the alternate
control center. The metering data will include bidirectional KWH and KVARH revenue
quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-
phase voltage, and per-phase amps data.

An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.

Station Service
The Project is within the Transmission Provider’s service territory. Please note that prior to
back feed, Interconnection Customer must arrange transmission retail meter service for
electricity consumed by the Project that will be drawn from the transmission system when the
Transition Cluster Study Report
Transition Cluster Area 2 Page 36 March 31, 2021

Project is not generating. Interconnection Customer must call the Help Desk at 1-800‐625‐
6078 to arrange this service. Approval for back feed is contingent upon obtaining station
service.

TCS-16
Interchange Metering
The overall project metering will be located at the Q0974 Point of Interconnection substation
and rated for the total net generation of the Project. The Transmission Provider will specify
and order all interconnection revenue metering, including the instrument transformers,
meters, meter panel, junction box, and secondary metering wire. The primary metering
transformers will be combination 230kV CT/VT units with extended range CTs for high-
accuracy metering.

The metering design package will include two revenue quality meters with DNP real time
digital data terminated at a metering interposition block. One meter will be designated as
primary SCADA meter with DNP data delivered to the primary control center. A second
meter will be designated as backup SCADA meter with DNP data delivered to the alternate
control center. The metering data will include bidirectional KWH and KVARH revenue
quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-
phase voltage, and per-phase amps data.

An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.

Station Service
The Project is within the Transmission Provider’s service territory. Please note that prior to
back feed, Interconnection Customer must arrange transmission retail meter service for
electricity consumed by the Project that will be drawn from the transmission system when the
Project is not generating. Interconnection Customer must call the Help Desk at 1-800‐625‐
6078 to arrange this service. Approval for back feed is contingent upon obtaining station
service.

TCS-17 and TCS-22
Note: The customer’s revised application materials led us to assume the two facilities are
basically identical, and that they both share a power transformer.

Interchange Metering
The overall project metering will be located at the Point of Interconnection and rated for the
total net generation of the two projects. The Transmission Provider will specify and order all
interconnection revenue metering, including the instrument transformers, meters, meter
panel, junction box, and secondary metering wire. The primary metering transformers will be
combination 230kV CT/VT units with extended range CTs for high-accuracy metering.
The metering design package will include two revenue quality meters with DNP real time
digital data terminated at a metering interposition block. One meter will be designated as
primary SCADA meter with DNP data delivered to the primary control center. A second
meter will be designated as backup SCADA meter with DNP data delivered to the alternate
Transition Cluster Study Report
Transition Cluster Area 2 Page 37 March 31, 2021

control center. The metering data will include bidirectional KWH and KVARH revenue
quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-
phase voltage, and per-phase amps data.

An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.

Project Metering
The TCS-17 and TCS-22 projects share the low side of the same power transformer and must
be measured separately. This will require two metering points. The metering will be located
at the customer’s collector substation, and each metering point will be rated for its individual
project. The Transmission Provider will specify and order all interconnection revenue
metering, including the instrument transformers, meters, meter panels, junction boxes, and
secondary metering wire. The primary metering transformers will be combination 34.5kV
CT/VT units with extended range CTs for high-accuracy metering.

The metering design package will include two revenue quality meters for each meter point
with DNP real time digital data terminated at a metering interposition block. One meter will
be designated as primary SCADA meter with DNP data delivered to the primary control
center. A second meter will be designated as backup SCADA meter with DNP data
delivered to the alternate control center. The metering data will include bidirectional KWH
and KVARH revenue quantities. The meter data will also include instantaneous PF, MW,
MVAR, MVA, per-phase voltage, and per-phase amps data.

An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.

TCS-17 Generator Metering
The solar generator and battery storage are to be separately metered. Specifically, the two
breakers for the solar generator, and the one breaker for the battery storage will be metered.
This will require three metering points.

The metering will be located at the customer’s collector substation, and each metering point
will be rated for its individual circuit on the Project. The Transmission Provider will specify
and order all interconnection revenue metering, including the instrument transformers,
meters, meter panels, junction boxes, and secondary metering wire. The primary metering
transformers will be combination 34.5kV CT/VT units with extended range CTs for high-
accuracy metering.

The metering design package will include two revenue quality meters for each meter point
with DNP real time digital data terminated at a metering interposition block. One meter will
be designated as primary SCADA meter with DNP data delivered to the primary control
center. A second meter will be designated as backup SCADA meter with DNP data
delivered to the alternate control center. The metering data will include bidirectional KWH
and KVARH revenue quantities. The meter data will also include instantaneous PF, MW,
MVAR, MVA, per-phase voltage, and per-phase amps data.
Transition Cluster Study Report
Transition Cluster Area 2 Page 38 March 31, 2021

An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.

TCS-22 Generator Metering
The solar generator and battery storage are to be separately metered. Specifically, the two
breakers for the solar generator, and the one breaker for the battery storage will be metered.
This will require three metering points.

The metering will be located at the customer’s collector substation, and each metering point
will be rated for its individual circuit on the Project. The Transmission Provider will specify
and order all interconnection revenue metering, including the instrument transformers,
meters, meter panels, junction boxes, and secondary metering wire. The primary metering
transformers will be combination 34.5kV CT/VT units with extended range CTs for high-
accuracy metering.

The metering design package will include two revenue quality meters for each meter point
with DNP real time digital data terminated at a metering interposition block. One meter will
be designated as primary SCADA meter with DNP data delivered to the primary control
center. A second meter will be designated as backup SCADA meter with DNP data
delivered to the alternate control center. The metering data will include bidirectional KWH
and KVARH revenue quantities. The meter data will also include instantaneous PF, MW,
MVAR, MVA, per-phase voltage, and per-phase amps data.

An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.

Station Service
The Project is within the Transmission Provider’s service territory. Please note that prior to
back feed, Interconnection Customer must arrange transmission retail meter service for
electricity consumed by the Project that will be drawn from the transmission system when the
Project is not generating. Interconnection Customer must call the Help Desk at 1-800‐625‐
6078 to arrange this service. Approval for back feed is contingent upon obtaining station
service.

TCS-19
Interchange Metering
The overall project metering will be located at Chimney Butte Substation and rated for the
total net generation of the Project. The Transmission Provider will specify and order all
interconnection revenue metering, including the instrument transformers, meters, meter
panel, junction box, and secondary metering wire. The primary metering transformers will be
combination 230kV CT/VT units with extended range CTs for high-accuracy metering.
The metering design package will include two revenue quality meters with DNP real time
digital data terminated at a metering interposition block. One meter will be designated as
primary SCADA meter with DNP data delivered to the primary control center. A second
meter will be designated as backup SCADA meter with DNP data delivered to the alternate
Transition Cluster Study Report
Transition Cluster Area 2 Page 39 March 31, 2021

control center. The metering data will include bidirectional KWH and KVARH revenue
quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-
phase voltage, and per-phase amps data.

An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.

Station Service
The Project is within the Transmission Provider’s service territory. Please note that prior to
back feed, Interconnection Customer must arrange transmission retail meter service for
electricity consumed by the Project that will be drawn from the transmission system when the
Project is not generating. Interconnection Customer must call the Help Desk at 1-800‐625‐
6078 to arrange this service. Approval for back feed is contingent upon obtaining station
service

TCS-23
This Interconnection Request proposes DC coupled battery and solar facilities. The
Transmission Provider has no approved method to meter battery and solar in this
configuration separately therefore the solar and battery storage will essentially be a single
generating facility from a revenue metering perspective.

Interchange Metering
The overall project metering will be located at the Raven substation and rated for the total net
generation. The Transmission Provider will specify and order all interconnection revenue
metering, including the instrument transformers, meters, meter panel, junction box, and
secondary metering wire. The primary metering transformers will be combination 34.5kV
CT/VT units with extended range CTs for high-accuracy metering.
The metering design package will include two revenue quality meters with DNP real time
digital data terminated at a metering interposition block. One meter will be designated as
primary SCADA meter with DNP data delivered to the primary control center. A second
meter will be designated as backup SCADA meter with DNP data delivered to the alternate
control center. The metering data will include bidirectional KWH and KVARH revenue
quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-
phase voltage, and per-phase amps data.

An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.

Station Service
The Project is within the Transmission Provider’s service territory. Please note that prior to
back feed, Interconnection Customer must arrange transmission retail meter service for
electricity consumed by the Project that will be drawn from the transmission system when the
Project is not generating. Interconnection Customer must call the Help Desk at 1-800‐625‐
6078 to arrange this service. Approval for back feed is contingent upon obtaining station
service.

Transition Cluster Study Report
Transition Cluster Area 2 Page 40 March 31, 2021

TCS-26 and TCS-31
This Interconnection Request proposes DC coupled battery and solar facilities. The
Transmission Provider has no approved method to meter battery and solar in this
configuration separately therefore the solar and battery storage will essentially be a single
generating facility from a revenue metering perspective.

Interchange Metering
The overall project metering will be located at the Point of Interconnection and rated for the
total net generation of the two projects. The Transmission Provider will specify and order all
interconnection revenue metering, including the instrument transformers, meters, meter
panel, junction box, and secondary metering wire. The primary metering transformers will be
combination 138kV CT/VT units with extended range CTs for high-accuracy metering.
The metering design package will include two revenue quality meters with DNP real time
digital data terminated at a metering interposition block. One meter will be designated as
primary SCADA meter with DNP data delivered to the primary control center. A second
meter will be designated as backup SCADA meter with DNP data delivered to the alternate
control center. The metering data will include bidirectional KWH and KVARH revenue
quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-
phase voltage, and per-phase amps data.

An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.

Project Metering
TCS-26 and TCS-31 share the low side of the same power transformer and must be metered
separately. This will require four metering points.

The metering will be located at the customer’s collector substation and each metering point
will be rated for its individual circuit on the Project. The Transmission Provider will specify
and order all interconnection revenue metering, including the instrument transformers,
meters, meter panels, junction boxes, and secondary metering wire. The primary metering
transformers will be combination 34.5kV CT/VT units with extended range CTs for high-
accuracy metering.

The metering design package will include two revenue quality meters for each meter point
with DNP real time digital data terminated at a metering interposition block. One meter will
be designated as primary SCADA meter with DNP data delivered to the primary control
center. A second meter will be designated as backup SCADA meter with DNP data
delivered to the alternate control center. The metering data will include bidirectional KWH
and KVARH revenue quantities. The meter data will also include instantaneous PF, MW,
MVAR, MVA, per-phase voltage, and per-phase amps data.

An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.

State Line Metering
Transition Cluster Study Report
Transition Cluster Area 2 Page 41 March 31, 2021

Th customer’s chosen Point of Interconnection is between the Wyoming state line and the
existing state line metering at Railroad substation. Therefore, new state line metering will
need to be installed. This will require one metering point at the Point of Interconnection
substation on the Croydon line.

The Transmission Provider will specify and order all interconnection revenue metering,
including the transformers, meters, meter panel, junction box, and secondary metering wire.
The primary metering transformers are expected to be breaker CTs and line VTs from relay.
The metering design package will include one revenue quality meter with bidirectional KWH
and KVARH quantities.

Cellular or Ethernet connection is required for retail sales and generation accounting via the
MV-90 translation system.

Station Service
The Project is within the Transmission Provider’s service territory. Please note that prior to
back feed, Interconnection Customer must arrange transmission retail meter service for
electricity consumed by the Project that will be drawn from the transmission system when the
Project is not generating. Interconnection Customer must call the Help Desk at 1-800‐625‐
6078 to arrange this service. Approval for back feed is contingent upon obtaining station
service.
8.0 CONTINGENT FACILITIES
The following Interconnection Facilities and/or upgrades to the Transmission Provider’s system
are Contingent Facilities applicable to this Cluster Area.

Table 1. Contingent Facilities Table for Path C improvement
Potential
Contingent
Facility
Description
Outage(s)
Pre-CA2
Overload/
Violation
Level
Post-CA2
Overload/
Violation
Level
%
Change
Contingent
Facility
(Yes/No)
Responsible
Entity
Planned
ISD
Path C
improvement
Wheelon
138 kV bus
fault (P2-2)
Overload on
Franklin -
Green
Canyon Tap
138 kV line
to 114% of
its 30-
minute
emergency
rating
Overload on
Franklin -
Green
Canyon Tap
138 kV line
to 120% of
its 30-minute
emergency
rating
9.6 Yes
PacifiCorp 2023
Overload on
Green
Canyon Tap
- Green
Canyon 138
kV line to
114% of its
30-minute
Overload on
Green
Canyon Tap -
Green
Canyon 138
kV line to
120% of its
30-minute
9.6 Yes
Transition Cluster Study Report
Transition Cluster Area 2 Page 42 March 31, 2021

emergency
rating
emergency
rating
N-2 of
Treasureton
- Grace 138
kV #1 & #2
lines (P7)
No issues on
Grace -
Oneida 138
kV line
Overload on
Grace -
Oneida 138
kV line to
107% of its
30-minute
emergency
rating
22.9 Yes
It is observed that P2-2 contingency exacerbate the overload issues on the Franklin – Green
Canyon Tap – Green Canyon 138 kV line without Path C improvement during peak load stressed
condition. Additionally, P7 contingency also causes the overload issue on the Grace – Oneida 138
kV line without Path C improvement during off-peak load stressed condition. Path C improvement
project will mitigate these issues on Table 1. Therefore, Path C improvement project is a
Contingent Facility for the CA2 cluster.

Table 2. Contingent Facilities Table for Wheelon – Bridgerland 138 kV line
Potential
Contingent
Facility
Description
Outage(s)
Pre-CA2
Overload/
Violation
Level
Post-CA2
Overload/
Violation
Level
%
Change
Contingent
Facility
(Yes/No)
Responsible
Entity
Planned
ISD
Wheelon -
Bridgerland
138 kV line
N-1 of Ben
Lomond -
Birch
Creek 230
kV line
(P1-2)
No issues on
Wheelon -
Bridgerland
138 kV line
Overload on
Franklin -
Green
Canyon Tap
138 kV line
to 100% of
its 30-minute
emergency
rating
19.8 Yes
Q799 TBD
N-1 of Ben
Lomond -
Honeyville
138 kV line
(P1-2)
No issues on
Wheelon -
Bridgerland
138 kV line
Overload on
Wheelon -
Bridgerland
138 kV line
to 110% of
its 30-minute
emergency
rating
19.0 Yes
Ben
Lomond
138 kV east
bus fault
(P2-2)
No issues on
Wheelon -
Bridgerland
138 kV line
Overload on
Wheelon -
Bridgerland
138 kV line
to 104% of
its 30-minute
emergency
rating
19.0 Yes
Transition Cluster Study Report
Transition Cluster Area 2 Page 43 March 31, 2021

Internal
circuit
breaker
fault CB
245 at Ben
Lomond
230 kV
(P2-3)
No issues on
Wheelon -
Bridgerland
138 kV line
Overload on
Wheelon -
Bridgerland
138 kV line
to 102% of
its 30-minute
emergency
rating
20.0 Yes
Internal
circuit
breaker
fault CB
L135, CB
L110 & CB
111 at Ben
Lomond
138 kV
(P2-3)
No issues on
Wheelon -
Bridgerland
138 kV line
Overload on
Wheelon -
Bridgerland
138 kV line
to 103% of
its 30-minute
emergency
rating
19.2 Yes
Internal
circuit
breaker
fault CB
102 at Ben
Lomond
138 kV
(P2-3)
No issues on
Wheelon -
Bridgerland
138 kV line
Overload on
Wheelon -
Bridgerland
138 kV line
to 103% of
its 30-minute
emergency
rating
19.2 Yes
Internal
circuit
breaker
fault CB
107 & CB
C149 at
Ben
Lomond
138 kV
(P2-3)
No issues on
Wheelon -
Bridgerland
138 kV line
Overload on
Wheelon -
Bridgerland
138 kV line
to 103% of
its 30-minute
emergency
rating
18.6 Yes
Internal
circuit tie
breaker
fault CB
131I at Ben
Lomond
138 kV
(P2-4)
No issues on
Wheelon -
Bridgerland
138 kV line
Overload on
Wheelon -
Bridgerland
138 kV line
to 104% of
its 30-minute
emergency
rating
19.0 Yes
N-2 of Ben
Lomond -
Honeyville
& Ben
Lomond -
Rocky
Point -
Wheelon
138 kV
lines (P7)
Overload on
Wheelon -
Bridgerland
138 kV line
to 108% of
its 30-
minute
emergency
rating
Overload on
Wheelon -
Bridgerland
138 kV line
to 128% of
its 30-minute
emergency
rating
18.6 Yes
Transition Cluster Study Report
Transition Cluster Area 2 Page 44 March 31, 2021

N-2 of
Populus -
Bridgerland
& Populus
- Ben
Lomond
345 kV
lines (P7)
No issues on
Wheelon -
Bridgerland
138 kV line
Overload on
Wheelon -
Bridgerland
138 kV line
to 117% of
its 30-minute
emergency
rating
22.0 Yes

It is observed that some P1-2, P2-2, P2-3, P2-4 and P7 contingencies exacerbate the overload
issues on the Wheelon – Bridgerland 138 kV line during off-peak load and peak load stressed
conditions. Rebuilding 1.118-mile 795 ACSR section, which is a limiting factor, on the Wheelon
– Bridgerland 138 kV line with 1272 ACSR is required to mitigate the issues on Table 2. This
project will be responsible for a prior queue customer. Therefore, rebuilding 1.118-mile 795 ACSR
section on the Wheelon – Bridgerland 138 kV line with 1272 ACSR is a Contingent Facility for
the CA2 cluster.

Table 3. Contingent Facilities Table for El Monte RAS
Potential
Contingent
Facility
Description
Outage(s)
Pre-CA2
Overload/
Violation
Level
Post-CA2
Overload/
Violation
Level
%
Change
Contingent
Facility
(Yes/No)
Responsible
Entity
Planned
ISD
El Monte
RAS
Ben
Lomond
138 kV
east bus
fault (P2-2)
Overload on
Ben
Lomond - El
Monte 138
kV line to
104% of its
30-minute
emergency
rating
Overload on
Ben Lomond
- El Monte
138 kV line
to 107% of
its 30-minute
emergency
rating
2.0 Yes
PacifiCorp 2029
Internal
circuit
breaker
fault CB
L135, CB
L110 & CB
111 at Ben
Lomond
138 kV
(P2-3)
Overload on
Ben
Lomond - El
Monte 138
kV line to
100% of its
30-minute
emergency
rating
Overload on
Ben Lomond
- El Monte
138 kV line
to 103% of
its 30-minute
emergency
rating
1.6 Yes
Internal
circuit
breaker
fault CB
102 at Ben
Lomond
138 kV
(P2-3)
Overload on
Ben
Lomond - El
Monte 138
kV line to
100% of its
30-minute
emergency
rating
Overload on
Ben Lomond
- El Monte
138 kV line
to 103% of
its 30-minute
emergency
rating
1.6 Yes
Transition Cluster Study Report
Transition Cluster Area 2 Page 45 March 31, 2021

Internal
circuit
breaker
fault CB
105 at Ben
Lomond
138 kV
(P2-3)
Overload on
Ben
Lomond - El
Monte 138
kV line to
100% of its
30-minute
emergency
rating
Overload on
Ben Lomond
- El Monte
138 kV line
to 103% of
its 30-minute
emergency
rating
1.6 Yes
Internal
circuit tie
breaker
fault CB
131I at Ben
Lomond
138 kV
(P2-4)
Overload on
Ben
Lomond - El
Monte 138
kV line to
104% of its
30-minute
emergency
rating
Overload on
Ben Lomond
- El Monte
138 kV line
to 107% of
its 30-minute
emergency
rating
2.0 Yes

It is observed that some P2-2, P2-3 and P2-4 contingencies exacerbate the overload issues on the
Ben Lomond – El Monte 138 kV line during peak load stressed condition. There is a proposed
RAS called El Monte RAS which mitigate these issues in Table 3. However, this RAS was
proposed in 2029. This RAS should be expedited before the cluster. Therefore, El Monte RAS is
a Contingent Facility for the CA2 cluster.

Table 4. Contingent Facilities Table for Naughton - Ben Lomond & Birch Creek - Ben Lomond
230 kV lines
Potential
Contingent
Facility
Description
Outage(s)
Pre-CA2
Overload/
Violation
Level
Post-CA2
Overload/
Violation
Level
%
Change
Contingent
Facility
(Yes/No)
Responsible
Entity
Planned
ISD
Naughton -
Ben Lomond
& Birch
Creek - Ben
Lomond 230
kV lines
(sharing the
same
structures)
Naughton -
Ben
Lomond &
Birch
Creek -
Ben
Lomond
230 kV
lines (P7)
No overload
issues
Overload on
Silver Creek -
Snyderville
138 kV line
to 111% of its
30-minute
emergency
rating
27.5
Yes Q0810 TBD
No overload
issues
Overload on
Snyderville -
Cottonwood
138 kV line
to 113% of its
30-minute
emergency
rating
32.0
Transition Cluster Study Report
Transition Cluster Area 2 Page 46 March 31, 2021

No overload
issues
Overload on
Treasureton -
Q0974 POI
230 kV line
to 108% of its
30-minute
emergency
rating
29.8
No voltage
issues
Low voltage
(less than 0.9
pu) in
Croydon and
Coalville
areas
10.9

It is observed that N-2 of Naughton – Ben Lomond and Birch Creek – Ben Lomond 230 kV lines
causes the overload and voltage issues during off-peak load condition. The Contingent Facility
analysis confirm that the generation additions in CA2 do exacerbate the voltage and thermal
overload. Therefore, separation of Naughton – Ben Lomond and Birch Creek – Ben Lomond 230
kV lines is a Contingent Facility for the CA2 cluster.

Table 5. Contingent Facilities Table for 2.35-mile 795 ACSR rebuild project on Railroad –
Croydon 138 kV line
Potential
Contingent
Facility
Description
Outage(s)
Pre-CA2
Overload/
Violation
Level
Post-CA2
Overload/
Violation
Level
%
Change
Contingent
Facility
(Yes/No)
Responsible
Entity
Planned
ISD
Rebuild 2.35-
mile 795
ACSR
section with
1272 ACSR
on Railroad -
Croydon 138
kV line
Birch
Creek -
Q1083
(TCS-17)
POI 230
kV line
(P1-2)
No overload
issues
Overload on
Railroad -
Q1116 (TCS-
26) 138 kV
line to 104%
of its 30-
minute
emergency
rating
27.6 Yes
Q786 TBD
Internal
circuit
breaker
fault CB
224 at
Birch
Creek 230
kV (P2-3)
No overload
issues
Overload on
Railroad -
Q1116 (TCS-
26) 138 kV
line to 115%
of its 30-
minute
emergency
rating
25.9 Yes
Internal
circuit
breaker
fault CB
244 at
Birch
Creek 230
kV (P2-3)
No overload
issues
Overload on
Railroad -
Q1116 (TCS-
26) 138 kV
line to 115%
of its 30-
minute
25.9 Yes
Transition Cluster Study Report
Transition Cluster Area 2 Page 47 March 31, 2021

emergency
rating
Internal
circuit
breaker
fault CB
264 at
Birch
Creek 230
kV (P2-3)
No overload
issues
Overload on
Railroad -
Q1116 (TCS-
26) 138 kV
line to 115%
of its 30-
minute
emergency
rating
25.9 Yes
The location of the 795 ACSR section on the Railroad–Croydon 138 kV line starts 1.74-miles from
the Railroad substation. The cluster queues TCS-26 and TCS-31 are interconnected 6.7 miles south
from the Railroad substation on the Railroad–Croydon 138 kV line. Due to the point of
interconnection, power flows on the Railroad – TCS-26 POI 138 kV line are decreasing whereas
power flows on the Croydon–TCS-26 POI 138 kV line are increasing. With TCS-26 and TCS-31
in service there are no overload issues identified. However, it is observed that some of
contingencies described in Table 5 above during off-peak and peak conditions cause the thermal
overload issues considering out of service of TCS26 and TCS-31 due to overhaul, for example.
The Contingent Facility analysis confirms that the generation additions in CA2 do exacerbate the
thermal overload. Therefore, rebuilding 2.35-mile 795 ACSR section with 1272 ACSR on the
Railroad – Croydon 138 kV line is a Contingent Facility for the CA2 cluster.

Table 6. Contingent Facilities Table for replacing the existing relays and jumper on Naughton –
PM Mine 138 kV line with higher ratings
Potential
Contingent
Facility
Description
Outage(s)
Pre-CA2
Overload/
Violation
Level
Post-CA2
Overload/
Violation
Level
%
Change
Contingent
Facility
(Yes/No)
Responsible
Entity
Planned
ISD
Replace the
existing
relays and
jumpers on
Naughton -
PM Mine
138 kV line
Birch
Creek -
Railroad
230 kV line
(Birch
Creek -
Q1083 POI
230 kV
line) (P1-2)
No issues
on
Naughton -
PM Mine
138 kV line
Overload on
Naughton -
PM Mine
138 kV line
to 133% of
its 30-
minute
emergency
rating
51.0 Yes
Higher Priority
Interconnection
Request
TBD
Railroad
138 kV bus
fault (P2-2)
Overload
on
Naughton -
PM Mine
138 kV line
to 109% of
its 30-
minute
Overload on
Naughton -
PM Mine
138 kV line
to 109% of
its 30-
minute
0.0 No
Transition Cluster Study Report
Transition Cluster Area 2 Page 48 March 31, 2021

emergency
rating
emergency
rating
Internal
circuit
breaker
fault CB
224 at
Birch
Creek 230
kV (P2-3)
No issues
on
Naughton -
PM Mine
138 kV line
Overload on
Naughton -
PM
Mine138 kV
line to 126%
of its 30-
minute
emergency
rating
55.8 Yes
Internal
circuit
breaker
fault CB
244 at
Birch
Creek 230
kV (P2-3)
No issues
on
Naughton -
PM Mine
138 kV line
Overload on
Naughton -
PM Miner
138 kV line
to 126% of
its 30-
minute
emergency
rating
55.8 Yes
Internal
circuit
breaker
fault CB
264 at
Birch
Creek 230
kV (P2-3)
No issues
on
Naughton -
PM Mine
138 kV line
Overload on
Naughton -
PM Mine
138 kV line
to 126% of
its 30-
minute
emergency
rating
55.8 Yes
Internal
circuit
breaker
fault CB
132, CB
133,
CB134 or
CB 135 at
Railroad
138 kV
(P2-3)
Overload
on
Naughton -
PM Mine
138 kV line
to 109% of
its 30-
minute
emergency
rating
Overload on
Naughton -
PM Mine
138 kV line
to 109% of
its 30-
minute
emergency
rating
0.0 No
It is observed that some P1-2 and P2-3 contingencies exacerbate the overload issues on the
Naughton–PM Mine 138 kV line during off-peak and peak load conditions. In order to get higher
ratings, replacing the existing relays and jumpers on the Naughton–PM Mine 138 kV line is
required because the first and second limiting factors on the Naughton–PM Mine 138 kV line are
relays and jumpers respectively. Therefore, replacing the existing relays and jumpers on the
Naughton–PM Mine 138 kV line is a Contingent Facility for the CA2 cluster.

Table 6. Contingent Facilities Table for replacing the existing relays and jumper on PM Mine –
Carter 138 kV line with higher ratings
Transition Cluster Study Report
Transition Cluster Area 2 Page 49 March 31, 2021

Potential
Contingent
Facility
Description
Outage(s)
Pre-CA2
Overload/
Violation
Level
Post-CA2
Overload/
Violation
Level
%
Change
Contingent
Facility
(Yes/No)
Responsible
Entity
Planned
ISD
Replace the
existing
relays and
jumpers on
PM Mine -
Carter 138
kV line
Birch
Creek -
Railroad
230 kV line
(Birch
Creek -
Q1083 POI
230 kV
line) (P1-2)
Overload
on PM
Mine -
Carter 138
kV line to
111% of its
30-minute
emergency
rating
Overload on
PM Mine -
Carter 138
kV line to
169% of its
30-minute
emergency
rating
51.0 Yes
Higher Priority
Interconnection
Request
TBD
Birch
Creek -
Railroad
230 kV line
(Railroad -
Q1083 POI
230 kV
line) (P1-2)
Overload
on PM
Mine -
Carter 138
kV line to
111% of its
30-minute
emergency
rating
Overload on
PM Mine -
Carter 138
kV line to
125% of its
30-minute
emergency
rating
12.9 Yes
Railroad
230/138 kV
transformer
(P1-3)
Overload
on PM
Mine -
Carter 138
kV line to
111% of its
30-minute
emergency
rating
Overload on
PM Mine -
Carter 138
kV line to
125% of its
30-minute
emergency
rating
14.8 Yes
Internal
circuit
breaker
fault CB
224 at
Birch
Creek 230
kV (P2-3)
Overload
on PM
Mine -
Carter 138
kV line to
105% of its
30-minute
emergency
rating
Overload on
PM Mine -
Carter 138
kV line to
167% of its
30-minute
emergency
rating
56.5 Yes
Internal
circuit
breaker
fault CB
244 at
Birch
Creek 230
kV (P2-3)
Overload
on PM
Mine -
Carter 138
kV line to
105% of its
30-minute
emergency
rating
Overload on
PM Mine -
Carter 138
kV line to
167% of its
30-minute
emergency
rating
56.5 Yes
Internal
circuit
breaker
fault CB
264 at
Birch
Overload
on PM
Mine -
Carter 138
kV line to
105% of its
Overload on
PM Mine -
Carter 138
kV line to
167% of its
30-minute
56.5 Yes
Transition Cluster Study Report
Transition Cluster Area 2 Page 50 March 31, 2021

Creek 230
kV (P2-3)
30-minute
emergency
rating
emergency
rating
It is observed that some P1-2, P1-3 and P2-3 contingencies exacerbate the overload issues on the
PM Mine–Carter 138 kV line during off-peak and peak load conditions. In order to get higher
ratings, replacing the existing relays and jumpers on the PM Mine–Carter 138 kV line is required
because the first and second limiting factors on the PM Mine–Carter 138 kV line are relays and
jumpers respectively. Therefore, replacing the existing relays and jumpers on the PM Mine–Carter
138 kV line 138 kV line is a Contingent Facility for the CA2 cluster.

Table 8. Contingent Facilities Table for replacing the existing relays and jumper on Carter –
Canyon Compression 138 kV line with higher ratings
Potential
Contingent
Facility
Description
Outage(s)
Pre-CA2
Overload/
Violation
Level
Post-CA2
Overload/
Violation
Level
%
Change
Contingent
Facility
(Yes/No)
Responsible
Entity
Planned
ISD
Replace the
existing
relays and
jumpers on
Carter -
Canyon
Compression
138 kV line
Birch
Creek -
Railroad
230 kV line
(Birch
Creek -
Q1083 POI
230 kV
line) (P1-2)
No issues on
Carter -
Canyon
Compression
138 kV line
Overload on
Carter -
Canyon
Compression
138 kV line
to 143% of
its 30-
minute
emergency
rating
47.2 Yes
Higher Priority
Interconnection
Request
TBD
Birch
Creek -
Railroad
230 kV line
(Railroad -
Q1083 POI
230 kV
line) (P1-2)
No issues on
Carter -
Canyon
Compression
138 kV line
Overload on
Carter -
Canyon
Compression
138 kV line
to 107% of
its 30-
minute
emergency
rating
11.3 Yes
Railroad
230/138 kV
transformer
(P1-3)
No issues on
Carter -
Canyon
Compression
138 kV line
Overload on
Carter -
Canyon
Compression
138 kV line
to 107% of
its 30-
minute
emergency
rating
11.3 Yes
Transition Cluster Study Report
Transition Cluster Area 2 Page 51 March 31, 2021

Railroad
138 kV bus
fault (P2-2)
Overload on
Carter -
Canyon
Compression
138 kV line
to 123% of
its 30-
minute
emergency
rating
Overload on
Carter -
Canyon
Compression
138 kV line
to 123% of
its 30-
minute
emergency
rating
0.0 No
Internal
circuit
breaker
fault CB
224 at
Birch
Creek 230
kV (P2-3)
No issues on
Carter -
Canyon
Compression
138 kV line
Overload on
Carter -
Canyon
Compression
138 kV line
to 141% of
its 30-
minute
emergency
rating
51.0 Yes
Internal
circuit
breaker
fault CB
244 at
Birch
Creek 230
kV (P2-3)
No issues on
Carter -
Canyon
Compression
138 kV line
Overload on
Carter -
Canyon
Compression
138 kV line
to 141% of
its 30-
minute
emergency
rating
51.0 Yes
Internal
circuit
breaker
fault CB
264 at
Birch
Creek 230
kV (P2-3)
No issues on
Carter -
Canyon
Compression
138 kV line
Overload on
Carter -
Canyon
Compression
138 kV line
to 141% of
its 30-
minute
emergency
rating
51.0 Yes
Internal
circuit
breaker
fault CB
132, CB
133,
CB134 or
CB 135 at
Railroad
138 kV
(P2-3)
Overload on
Carter -
Canyon
Compression
138 kV line
to 123% of
its 30-
minute
emergency
rating
Overload on
Carter -
Canyon
Compression
138 kV line
to 123% of
its 30-
minute
emergency
rating
0.0 No
It is observed that some P1-2, P1-3, P2-2 and P2-3 contingencies exacerbate the overload issues
on the Carter–Canyon Compression 138 kV line during off-peak and peak load conditions. In order
to get higher ratings, replacing the existing relays and jumpers on the Carter–Canyon Compression
Transition Cluster Study Report
Transition Cluster Area 2 Page 52 March 31, 2021

138 kV line is required because the first and second limiting factors on the Carter–Canyon
Compression 138 kV line are relays and jumpers respectively. Therefore, replacing the existing
relays and jumpers on the Carter–Canyon Compression 138 kV line is a Contingent Facility for
the CA2 cluster.

Table 9. Contingent Facilities Table for replacing the existing Naughton 230/138 kV transformer
#10 with a new 450 MVA transformer
Potential
Contingent
Facility
Description
Outage(s)
Pre-CA2
Overload/
Violation
Level
Post-CA2
Overload/
Violation
Level
%
Change
Contingent
Facility
(Yes/No)
Responsible
Entity
Planned
ISD
Replace
Naughton
230/138 kV
transformer
#10 with
new 450
MVA
transformer
Birch
Creek -
Railroad
230 kV line
(Birch
Creek -
Q1083 POI
230 kV
line) (P1-2)
No issues on
Naughton
230/138 kV
transformer
#10
Overload
on
Naughton
230/138 kV
transformer
#10 to
133% of its
30-minute
emergency
rating
51.0 Yes
Higher Priority
Interconnection
Request
TBD
Railroad
138 kV bus
fault (P2-2)
Overload on
Naughton
230/138 kV
transformer
#10 to 124%
of its 30-
minute
emergency
rating
Overload
on
Naughton
230/138 kV
transformer
#10 to
124% of its
30-minute
emergency
rating
0.0 No
Internal
circuit
breaker
fault CB
224 at
Birch
Creek 230
kV (P2-3)
No issues on
Naughton
230/138 kV
transformer
#10
Overload
on
Naughton
230/138 kV
transformer
#10 to
131% of its
30-minute
emergency
rating
56.7 Yes
Internal
circuit
breaker
fault CB
244 at
Birch
Creek 230
kV (P2-3)
No issues on
Naughton
230/138 kV
transformer
#10
Overload
on
Naughton
230/138 kV
transformer
#10 to
131% of its
30-minute
emergency
rating
56.7 Yes
Transition Cluster Study Report
Transition Cluster Area 2 Page 53 March 31, 2021

Internal
circuit
breaker
fault CB
264 at
Birch
Creek 230
kV (P2-3)
No issues on
Naughton
230/138 kV
transformer
#10
Overload
on
Naughton
230/138 kV
transformer
#10 to
131% of its
30-minute
emergency
rating
56.7 Yes
Internal
circuit
breaker
fault CB
132, CB
133,
CB134 or
CB 135 at
Railroad
138 kV
(P2-3)
Overload on
Naughton
230/138 kV
transformer
#10 to 124%
of its 30-
minute
emergency
rating
Overload
on
Naughton
230/138 kV
transformer
#10 to
124% of its
30-minute
emergency
rating
0.0 No
It is observed that some P1-2, P2-2 and P2-3 contingencies exacerbate the overload issues on the
Naughton 230/138 kV transformer #10 during off-peak and peak load conditions. In order to get
higher ratings, replacing the Naughton 230/138 kV transformer #10 with a new transformer is
required. Therefore, replacing the Naughton 230/138 kV transformer #10 with a new 450 MVA
transformer is a Contingent Facility for the CA2 cluster.

Table 10. Contingent Facilities Table for replacing the existing Ben Lomond 230/138 kV
transformer #1 with a new 700 MVA transformer
Potential
Contingent
Facility
Description
Outage(s)
Pre-CA2
Overload/
Violation
Level
Post-CA2
Overload/
Violation
Level
%
Change
Contingent
Facility
(Yes/No)
Responsible
Entity
Planned
ISD
Replace Ben
Lomond
230/138 kV
transformer
#1 with new
700 MVA
transformer
Treasureton
- Q974 POI
230 kV line
(P1-2)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 102%
of its 30-
minute
emergency
rating
18.9 Yes
Higher Priority
Interconnection
Request
TBD
Ben
Lomond
230/138 kV
transformer
#2 (P1-3)
Overload on
Ben
Lomond
230/138 kV
transformer
#1 to 102%
of its 30-
minute
emergency
rating
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 122%
of its 30-
minute
emergency
rating
20.2 Yes
Transition Cluster Study Report
Transition Cluster Area 2 Page 54 March 31, 2021

Ben
Lomond
345/230 kV
transformer
#1 (P1-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 102%
of its 30-
minute
emergency
rating
22.3 Yes
Ben
Lomond
345/230 kV
transformer
#2 (P1-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 103%
of its 30-
minute
emergency
rating
22.6 Yes
Ben
Lomond
138 kV
west bus
(P2-2)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 116%
of its 30-
minute
emergency
rating
18.6 Yes
Internal
circuit
breaker
fault CB
230 at
Treasureton
230 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 102%
of its 30-
minute
emergency
rating
22.5 Yes
Internal
circuit
breaker
fault CB
240 at
Treasureton
230 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 102%
of its 30-
minute
emergency
rating
22.9 Yes
Transition Cluster Study Report
Transition Cluster Area 2 Page 55 March 31, 2021

Internal
circuit
breaker
fault CB
329 at Ben
Lomond
345 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 102%
of its 30-
minute
emergency
rating
25.4 Yes
Internal
circuit
breaker
fault CB
349 at Ben
Lomond
345 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 102%
of its 30-
minute
emergency
rating
25.4 Yes
Internal
circuit
breaker
fault CB
328 at Ben
Lomond
345 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 102%
of its 30-
minute
emergency
rating
25.4 Yes
Internal
circuit
breaker
fault CB
368 at Ben
Lomond
345 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 102%
of its 30-
minute
emergency
rating
25.4 Yes
Internal
circuit
breaker
fault CB
327 at Ben
Lomond
345 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 102%
of its 30-
minute
emergency
rating
22.1 Yes
Transition Cluster Study Report
Transition Cluster Area 2 Page 56 March 31, 2021

Internal
circuit
breaker
fault CB
367 at Ben
Lomond
345 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 102%
of its 30-
minute
emergency
rating
22.1 Yes
Internal
circuit
breaker
fault CB
326 at Ben
Lomond
345 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 104%
of its 30-
minute
emergency
rating
23.8 Yes
Internal
circuit
breaker
fault CB
366 at Ben
Lomond
345 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 102%
of its 30-
minute
emergency
rating
25.4 Yes
Internal
circuit
breaker
fault CB
323 at Ben
Lomond
345 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 104%
of its 30-
minute
emergency
rating
22.5 Yes
Internal
circuit
breaker
fault CB
343 at Ben
Lomond
345 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 104%
of its 30-
minute
emergency
rating
22.8 Yes
Transition Cluster Study Report
Transition Cluster Area 2 Page 57 March 31, 2021

Internal
circuit
breaker
fault CB
242 at Ben
Lomond
230 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 102%
of its 30-
minute
emergency
rating
25.7 Yes
Internal
circuit
breaker
fault CB
205 at Ben
Lomond
230 kV
(P2-3)
Overload on
Ben
Lomond
230/138 kV
transformer
#1 to 121%
of its 30-
minute
emergency
rating
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 151%
of its 30-
minute
emergency
rating
25.5 Yes
Internal
circuit
breaker
fault CB
L125, CB
L120 & CB
108 at Ben
Lomond
138 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 116%
of its 30-
minute
emergency
rating
18.6 Yes
Internal
circuit
breaker
fault CB
103 at Ben
Lomond
138 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 116%
of its 30-
minute
emergency
rating
18.3 Yes
Internal
circuit
breaker
fault CB
113 at Ben
Lomond
138 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 116%
of its 30-
minute
emergency
rating
18.3 Yes
Transition Cluster Study Report
Transition Cluster Area 2 Page 58 March 31, 2021

Internal
circuit
breaker
fault CB
115 at Ben
Lomond
138 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 115%
of its 30-
minute
emergency
rating
18.8 Yes
Internal tie
circuit
breaker
fault CB
B130 at
Ben
Lomond
138 kV
(P2-4)
No issues on
Ben
Lomond
230/138 kV
transformer
#1
Overload
on Ben
Lomond
230/138 kV
transformer
#1 to 116%
of its 30-
minute
emergency
rating
18.6 Yes
It is observed that some P1-2, P1-3, P2-2, P2-3 and P2-4 contingencies exacerbate the overload
issues on the Ben Lomond 230/138 kV transformer #1 during peak load, peak load stressed off-
peak load stressed conditions. In order to get higher ratings, replacing the Ben Lomond 230/138
kV transformer #1 with a new transformer is required. Therefore, replacing the Ben Lomond
230/138 kV transformer #1 with a new 700 MVA transformer is a Contingent Facility for the CA2
cluster.

Table 8. Contingent Facilities Table for replacing the existing Ben Lomond 230/138 kV
transformer #2 with a new 700 MVA transformer
Potential
Contingent
Facility
Description
Outage(s)
Pre-CA2
Overload/
Violation
Level
Post-CA2
Overload/
Violation
Level
%
Change
Contingent
Facility
(Yes/No)
Responsible
Entity
Planned
ISD
Replace Ben
Lomond
230/138 kV
transformer
#2 with new
700 MVA
transformer
Ben
Lomond
230/138 kV
transformer
#1 (P1-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#2
Overload
on Ben
Lomond
230/138 kV
transformer
#2 to 117%
of its 30-
minute
emergency
rating
20.3 Yes
Higher Priority
Interconnection
Request
TBD
Ben
Lomond
138 kV
east bus
(P2-2)
No issues on
Ben
Lomond
230/138 kV
transformer
#2
Overload
on Ben
Lomond
230/138 kV
transformer
#2 to 109%
of its 30-
minute
emergency
rating
14.0 Yes
Transition Cluster Study Report
Transition Cluster Area 2 Page 59 March 31, 2021

Internal
circuit
breaker
fault CB
343 at Ben
Lomond
345 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#2
Overload
on Ben
Lomond
230/138 kV
transformer
#2 to 135%
of its 30-
minute
emergency
rating
35.6 Yes
Internal
circuit
breaker
fault CB
204 at Ben
Lomond
230 kV
(P2-3)
Overload on
Ben
Lomond
230/138 kV
transformer
#2 to 118%
of its 30-
minute
emergency
rating
Overload
on Ben
Lomond
230/138 kV
transformer
#2 to 146%
of its 30-
minute
emergency
rating
25.8 Yes
Internal
circuit
breaker
fault CB
L135, CB
L110 & CB
111 at Ben
Lomond
138 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#2
Overload
on Ben
Lomond
230/138 kV
transformer
#2 to 113%
of its 30-
minute
emergency
rating
13.9 Yes
Internal
circuit
breaker
fault CB
102 at Ben
Lomond
138 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#2
Overload
on Ben
Lomond
230/138 kV
transformer
#2 to 113%
of its 30-
minute
emergency
rating
13.9 Yes
Internal
circuit
breaker
fault CB
107 & CB
C107 at
Ben
Lomond
138 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#2
Overload
on Ben
Lomond
230/138 kV
transformer
#2 to 111%
of its 30-
minute
emergency
rating
14.4 Yes
Transition Cluster Study Report
Transition Cluster Area 2 Page 60 March 31, 2021

Internal
circuit
breaker
fault CB
105 at Ben
Lomond
138 kV
(P2-3)
No issues on
Ben
Lomond
230/138 kV
transformer
#2
Overload
on Ben
Lomond
230/138 kV
transformer
#2 to 112%
of its 30-
minute
emergency
rating
14.3 Yes
Internal tie
circuit
breaker
fault CS
131I at Ben
Lomond
138 kV
(P2-4)
No issues on
Ben
Lomond
230/138 kV
transformer
#2
Overload
on Ben
Lomond
230/138 kV
transformer
#2 to 109%
of its 30-
minute
emergency
rating
14.0 Yes
It is observed that some P1-3, P2-2, P2-3 and P2-4 contingencies exacerbate the overload issues
on the Ben Lomond 230/138 kV transformer #2 during peak load, peak load stressed and off-peak
stressed conditions. In order to get higher ratings, replacing the Ben Lomond 230/138 kV
transformer #2 with a new transformer is required. Therefore, replacing the Ben Lomond 230/138
kV transformer #2 with a new 700 MVA transformer is a Contingent Facility for the CA2 cluster.

Table 9. Contingent Facilities Table for El Monte RAS
Potential
Contingent
Facility
Description
Outage(s)
Pre-CA2
Overload/
Violation
Level
Post-CA2
Overload/
Violation
Level
%
Change
Contingent
Facility
(Yes/No)
Responsible
Entity
Planned
ISD
El Monte
RAS
Ben
Lomond
138 kV
east bus
fault (P2-2)
Overload on
Ben
Lomond - El
Monte 138
kV line to
104% of its
30-minute
emergency
rating
Overload on
Ben Lomond
- El Monte
138 kV line
to 107% of
its 30-minute
emergency
rating
2.0 Yes
PacifiCorp 2029 Internal
circuit
breaker
fault CB
L135, CB
L110 & CB
111 at Ben
Lomond
138 kV
(P2-3)
Overload on
Ben
Lomond - El
Monte 138
kV line to
100% of its
30-minute
emergency
rating
Overload on
Ben Lomond
- El Monte
138 kV line
to 103% of
its 30-minute
emergency
rating
1.6 Yes
Transition Cluster Study Report
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Internal
circuit
breaker
fault CB
102 at Ben
Lomond
138 kV
(P2-3)
Overload on
Ben
Lomond - El
Monte 138
kV line to
100% of its
30-minute
emergency
rating
Overload on
Ben Lomond
- El Monte
138 kV line
to 103% of
its 30-minute
emergency
rating
1.6 Yes
Internal
circuit
breaker
fault CB
105 at Ben
Lomond
138 kV
(P2-3)
Overload on
Ben
Lomond - El
Monte 138
kV line to
100% of its
30-minute
emergency
rating
Overload on
Ben Lomond
- El Monte
138 kV line
to 103% of
its 30-minute
emergency
rating
1.6 Yes
Internal
circuit tie
breaker
fault CB
131I at Ben
Lomond
138 kV
(P2-4)
Overload on
Ben
Lomond - El
Monte 138
kV line to
104% of its
30-minute
emergency
rating
Overload on
Ben Lomond
- El Monte
138 kV line
to 107% of
its 30-minute
emergency
rating
2.0 Yes
It is observed that some P2-2, P2-3 and P2-4 contingencies exacerbate the overload issues on the
Ben Lomond – El Monte 138 kV line during peak load stressed condition. There is a proposed
RAS called El Monte RAS which mitigate these issues in Table 9. However, this RAS was
proposed in 2029. This RAS should be expedited before the cluster. Therefore, El Monte RAS is
a Contingent Facility for the CA2 cluster.

The thermal overload issue on the Syracuse – Clint East Tap 138 kV line is observed during peak
load and peak load stressed conditions. However, this line is not considered a Contingent Facility
because this overload issue is mitigated by the existing Operating Procedure PCC-919.

The Jordanelle – Midway 138 kV line is planned to be in-service in October 2021. This line is not
considered a Contingent Facility because it will be in service before the cluster queues start to be
constructed.
9.0 COST ESTIMATE
The following estimate represents only scopes of work that will be performed by the Transmission
Provider. Costs for any work being performed by the Interconnection Customer and/or Affected
Systems are not included.

9.1 Interconnection Facilities
The following facilities are directly assigned to Interconnection Customer(s) using such
facilities. If multiple Interconnection Requests are utilizing the same Transmission Provider
Transition Cluster Study Report
Transition Cluster Area 2 Page 62 March 31, 2021

Interconnection Facilities the costs shall be shared pursuant to Section 39.2.3 of
Transmission Provider’s OATT.

TCS-10
TCS-10 Collector Substation $54,000
Relay coordination

Promontory Substation $557,000
Line termination and metering
Total: $6,441,000

TCS-16
TCS-Collector Substation $494,000
Control building, protection and communications equipment

Q0974 POI Substation $812,000
Line termination and metering
Total: $2,885,000

TCS-17
TCS-17 Collector Substation $1,025,000
Control building, protection and communications equipment

TCS-17 POI Substation $958,000
Line termination and metering

Total: $9,750,000

TCS-19
TCS-19 Collector Substation $542,000
Control building, protection and communications equipment

Chimney Butte Substation $545,000
Line termination and metering
Total: $1,087,000

TCS-22
TCS-17/TCS-22 Collector Substation $718,000
Metering equipment

TCS-17 POI Substation $14,000
Install communications
Total: $732,000

TCS-23
TCS-23 Collector Substation $62,000
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Relay coordination

Raven Substation $781,000
Line termination and metering
Total: 843,000

TCS-26
TCS-26 Collector Substation $1,055,000
Metering and relaying equipment

TCS-26 POI Substation $553,000
Line termination and metering
Total: $1,608,000

TCS-31
TCS-31 Collector Substation $164,000
Metering equipment

TCS-26 POI Substation $13,000
Install communications
Total: $177,000

9.2 Station Equipment
The following are Network Upgrades which are allocated based on the number of Generating
Facilities interconnecting at an individual station on a per Interconnection Request basis.
Interconnection Requests utilizing the same Interconnection Facilities shall be consider one
request for this allocation.

TCS-10
Promontory Substation $5,682,000
Substation expansion and line positions

TCS-16
Q0974 POI Substation $1,578,000
Substation expansion and line position

TCS-17 and TCS-22
TCS-17 POI Substation $7,457,000
Build new three-breaker 230kV substation

TCS-19
Chimney Butte Substation $4,056,000
Expand substation and construct line position

TCS-23
Transition Cluster Study Report
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Raven Substation $1,374,000
Expand substation and line position

TCS-26 and TCS-31
TCS-26 POI Substation $4,412,000
Build new three-breaker ring 138kV substation

9.3 Network Upgrades
The funding responsibility for Network Upgrades other than those identified in the previous
section shall be allocated based on the proportional capacity of each individual Generating
Facility.

Ben Lomond-Honeyville-Wheelon 138kV Line $36,750,000
Rebuild ~20.72 miles of line

Ben Lomond-Honeyville-Wheelon 138kV Line $1,780,000
Reconductor of ~4.75 miles of line

Ben Lomond-Plain City 138kV Line $2,670,000
Rebuild ~1.87 miles of line

Cottonwood-Snyderville 138kV Line $2,860,000
Rebuild ~1.4 miles of line

Cottonwood-Snyderville 138kV Line $890,000
Rebuild ~0.5 miles of line

Oneida-Ovid 138kV Line $17,740,000
Rebuild ~22.9 miles of line

Ovid-Sage 69kV Line $30,000,000
Rebuild ~43.46 miles of line

Ben Lomond-Birch Creek 230kV Line $85,630,000
Rebuild ~55.13 miles of line

Birch Creek-Railroad 230kV and Loop to TCS-17 POI $6,030,000
Rebuild ~3.3 miles of line

Canyon Compression-Q0715 POI 138kV Line $1,380.000
Reconductor of ~1.41 miles of line

Craven Creek-Naughton 230kV Line $10,500,000
Reconductor of ~15.88 miles, replace ~20 structures
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Naughton-Evanston 138 kV Line $21,960,000
Rebuild ~22.3 miles of line

Treasureton-Q0974 230kV Line $90,800,000
Rebuild ~52.6 miles of line

Monument-Raven 230kV Line $18,070,000
Rebuild ~17 miles of line

Ben Lomond Substation $43,740,000
Replace transformers with 700 MVA units, rebuild 138 kV yard

Birch Creek Substation $1,830,000
Replace three 230kV breakers and switches

Black Fork Substation $100,000
Replace one 230kV switch and conductor

Canyon Compression Substation $30,000
Replace jumpers on 138kV line to Railroad substation

Cottonwood Substation $30,000
Replace jumpers on 138kV line to Snyderville substation

Croydon Substation $5,260,000
Install four 20 Mvar Shunt Cap Banks, yard expansion

Honeyville Substation $60,000
Replace jumpers on 138kV lines to Ben Lomond and Wheelon substations

Monument Substation $280,000
Replace five switches, add motor operator and three arrestors

Naughton Substation $$60,00
Replace jumpers on lines to Craven Creek and Glenco Tap

Oneida Substation $30,000
Replace jumpers on line to Ovid Substation

Ovid Substation $2,070,000
Replace 138/69 transformer with 100 MVA unit

Raven Substation $280,000
Replace five switches, add motor operator and three arrestors

Transition Cluster Study Report
Transition Cluster Area 2 Page 66 March 31, 2021

Silver Creek Substation $30,000
Replace jumpers on 138kV line to Snyderville Substation

Treasureton Substation $1,380,000
Replace three 230kV breakers and six switches

Westvaco Substation $8,920,000
New 230kV Ring bus yard

Wheelon Substation $60,000
Replace jumpers and disconnect switches

Honeyville Substation $134,000
Replace line protection panel

Lampo Substation $163,000
Replace line protection panel

Honeyville-Lampo transmission line $245,000
Loop in/out of Promontory expansion

ADSS for Lampo to Promontory substation $164,000
Install ~3.1 miles of ADSS fiber

Birch Creek Substation $175,000
Replace line protection panel

Railroad Substation $134,000
Replace line protection panel

Chappel Creek-Paradise transmission line $169,000
Loop in/out of Chimney Creek substation

Croydon Substation $99,000
Adapt protective relay settings

Railroad Substation $46,000
Adapt protective relay settings

Croydon-Railroad transmission line $2,169,000
Loop line in/out of TCS-26 POI substation, install fiber

Network Upgrades Total: $394,718,000
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9.4 Total Estimated Project Costs

TCS-10
Interconnection Facilities $611,000
Station Equipment $5,125,000
Network Upgrades $26,778,000

Total: $32,514,000

TCS-16
Interconnection Facilities $1,306,000
Station Equipment $1,578,000
Network Upgrades $65,412,000

Total: $68,296,000

TCS-17
Interconnection Facilities $1,983,000
Station Equipment $3,729,000
Network Upgrades $65,412,000

Total: $71,123,000

TCS-19
Interconnection Facilities $1,087,000
Station Equipment $4,056
Network Upgrades $65,412,000

Total: $70,555,000

TCS-22
Interconnection Facilities $732,000
Station Equipment $3,729,000
Network Upgrades $65,412,000

Total: $69,872,000

TCS-23
Interconnection Facilities $843,000
Station Equipment $1,374,000
Network Upgrades $40,882,000

Total: $43,099,000

TCS-26
Interconnection Facilities $1,608,000
Transition Cluster Study Report
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Station Equipment $2,206,000
Network Upgrades $40,882,000

Total: $44,696,000

TCS-31
Interconnection Facilities $177,000
Station Equipment $2,206,000
Network Upgrades $24,529,000

Total: $26,912,000

10.0 SCHEDULE
The Transmission Provider estimates it will require approximately 72 months to design, procure
and construct the facilities described in this report following the execution of Interconnection
Agreements. The schedule will be further developed and optimized during the Facilities Studies.
11.0 AFFECTED SYSTEMS
Transmission Provider has identified the following affected systems: None

A copy of this report will be shared with each Affected System.
12.0 APPENDICES
Appendix 1: Cluster Area Power Flow and Stability Study Results
Appendix 2: Higher Priority Requests
Appendix 3: Property Requirements
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12.1 Appendix 1: Cluster Area Power Flow and Stability Study Results
The Western Electricity Coordinating Council (WECC) approved 2020 Heavy Summer case
was used to perform the power flow studies using PSS/E version 34.8. The 2020 Heavy
Summer case was modified for the study year, 2025. The local 345 kV, 230 kV and 138 kV
transmission system outages were considered during the study.

Different conditions were considered for the cluster CA2:
1. Normal conditions (peak and off-peak load conditions)
2. Rock Springs/ Firehole and Path C paths stressed conditions (peak and off-peak load
conditions)
3. Rock Springs/ Firehole and Bridger West paths stressed conditions (peak and off-peak load
conditions)

Rock Springs/ Firehole path
The Rock Springs/ Firehole path is defined as the sum of the flows on the Rock Springs –
Raven 230 kV line and the Firehole – Mansface 230 kV line. In order to push the power flow
on the Rock Springs/ Firehole path to its maximum, the Monument phase shifters must be in
service. The path rating is 640 MW.

Bridger West path
The Bridger West, which is a WECC rated path, is defined as the sum of the flows on the Jim
Bridger – 3 Mile Knoll 345 kV line, Jim Bridger – Populus 345 kV #1 line and Jim Bridger –
Populus 345 kV #2 line. This path is a major passageway for the power flows from east to
west, from Wyoming to Idaho. The path rating is 2400 MW.

Path C path
The Path C, which is a WECC rated path, is defined as the sum of the flows on the Malad –
American Falls 138 kV line, Ben Lomond – Populus 345 kV #1 line and Ben Lomond –
Populus 345 kV #2 line, Populus – Terminal 345 kV line, Sunbeam – Brady 230 kV line, Fish
Creek – Goshen 161 kV line, Three Mile Knoll 345/138 kV transformer and Three Mile Knoll
138/115 kV transformer. This path is a major passageway for the power flows from north to
south, from Idaho to Utah. The path ratings are 1600 MW and 1250 MW for southbound and
northbound respectively.

N-0 Results:
No outage (P0 contingency)
• Overload on 0.42-mile of the Raven – Westvaco 230 kV line to 105% of its normal rating
during off-peak load with high Rock Springs/ Firehole path stressed (mitigation: Rebuild
0.42-mile of the Raven – Westvaco 230 kV line with 2 x 795 ACSR)
• Overload on 9.94-mile of the Westvaco – Blacks Fork 230 kV line to 105% of its normal
rating during off-peak load with high Rock Springs/ Firehole path stressed (mitigation:
Rebuild 9.94-mile of the Westvaco – Blacks Fork 230 kV line with 2 x 795 ACSR)

Transition Cluster Study Report
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Figure 11: No outage condition (P0) during off-peak load with Rock Springs/ Firehole path
stressed

• Overload on 3.3-mile of the Birch Creek–TCS-17 POI 230 kV line to 110% of its normal
rating during off-peak load (mitigation: Rebuild 3.3-mile Birch Creek – Q1083 (TCS-17)
POI 230 kV line with 2 x 1272 ACSR)
Figure 12: No outage condition (P0) during off-peak load

• Overload on 52.85-mile of the Treasureton – Q974 POI 230 kV line to 105% of its normal
rating during off-peak load with high Rock Springs/ Firehole path stressed (mitigation:
Rebuild 52.58-mile Treasureton – Q974 (prior cluster queue) POI 230 kV line with 2 x
1272 ACSR)
Transition Cluster Study Report
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Figure 13: No outage condition (P0) during off-peak load with Rock Springs/ Firehole path
stressed

P1, P2 & P7 Results:

Opening the Firehole – Mansface 230 kV line at Firehole (P2-1 contingency)
• Overload on 0.42-mile of the Raven – Westvaco 230 kV line to 112% of its 30-minute
emergency rating during off-peak load with high Rock Springs/ Firehole path stressed
(mitigation: Rebuild 0.42-mile of the Raven – Westvaco 230 kV line with 2 x 795 ACSR)
• Overload on 9.94-mile of the Westvaco – Blacks Fork 230 kV line to 111% of its 30-minute
emergency rating during off-peak load with high Rock Springs/ Firehole path stressed
(mitigation: Rebuild 9.94-mile of the Westvaco – Blacks Fork 230 kV line with 2 x 795
ACSR)
• Overload on 6.68-mile of the Blacks Fork – Monument 230 kV line to 111% of its 30-
minute emergency rating during off-peak load with high Rock Springs/ Firehole path
stressed (mitigation: Rebuild 6.68-mile of the Blacks Fork – Monument 230 kV line with
2 x 795 ACSR)

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Figure 14: Open the Firehole – Mansface 230 kV line at Firehole 230 kV (P2-1) during off-peak
load with Rock Springs/ Firehole path stressed

• Overload on the Oneida – Ovid 138 kV line
Contingency % of Overload Worst Case Mitigation
N-1 of Treasureton - Q974
POI 230 kV line (P1-2)
118% of its 30-
minute rating
Light Load Stress -
Path C: N1250 &
RS/F: 640
Rebuild 22.85-mile
Oneida – Ovid 138
kV line with 795
ACSR because the
limiting factor on
this line is 336.4
ACSR conductor
N-1 of Naughton - Q974 POI
230 kV line (P1-2)
108% of its 30-
minute rating
Light Load Stress -
Path C: N1250 &
RS/F: 640
N-1 of Naughton - Ben
Lomond 230 kV line (P1-2)
104% of its 30-
minute rating
Light Load Stress -
Path C: N1250 &
RS/F: 640
N-1 of Birch Creek - Ben
Lomond 230 kV line (P1-2)
106% of its 30-
minute rating
Light Load Stress -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 230 at Treasureton 230 kV
(P2-3)
116% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 240 at Treasureton 230 kV
(P2-3)
118% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 224 at Ben Lomond 230
kV (P2-3)
104% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Transition Cluster Study Report
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Internal circuit breaker fault
CB 244 at Ben Lomond 230
kV (P2-3)
105% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 225 at Ben Lomond 230
kV (P2-3)
107% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 245 at Ben Lomond 230
kV (P2-3)
107% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Bus-tie circuit breaker fault
CB B232 at Ben Lomond 230
kV (P2-3)
102% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 224 at Birch Creek 230 kV
(P2-3)
106% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 244 at Birch Creek 230 kV
(P2-3)
106% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 264 at Birch Creek 230 kV
(P2-3)
106% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640

• Overload on the Ovid 138/69 kV transformer
Contingency % of Overload Worst Case Mitigation
N-1 of Treasureton - Q974 POI
230 kV line (P1-2)
107% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Replace the existing
Ovid 138/69 kV
75/75/75 MVA
transformer with 150
MVA emergency
rating Internal circuit breaker fault
CB 230 at Treasureton 230 kV
(P2-3)
106% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 240 at Treasureton 230 kV
(P2-3)
107% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
• Overload on the Ovid – Sage Junction 69 kV line

Transition Cluster Study Report
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Contingency % of Overload Worst Case Mitigation
N-1 of Treasureton - Q974 POI
230 kV line (P1-2)
101% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Rebuild 43.46-mile
397.5 ACSR Ovid –
Sage Junction 69 kV
line with 795 ACSR

Figure 15: outage of Treasureton – Q974 POI 230 kV line (P1-2) during off-peak load with Path
C northbound and Rock Springs/ Firehole path stressed

• Overload on Silver Creek – Snyderville 138 kV line
Contingency % of Overload Worst Case Mitigation
N-1 of Birch Creek - Q1083
POI 230 kV line (P1-2)
101% of its 30-
minute rating Light Load Rebuild 1.413-mile
of 397 ACSR
section on Silver
Creek – Snyderville
138 kV line with
1272 ACSR and
replace the existing
jumpers with higher
N-1 of Birch Creek - Ben
Lomond 230 kV line (P1-2)
106% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
N-1 of Jordanelle - Midway
138 kV line (P1-2)
102% of its 30-
minute rating Light Load
Transition Cluster Study Report
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Open Jordanelle - Heber Tap
138 kV line at Jordanelle (P2-
1)
101% of its 30-
minute rating Light Load
ratings because the
limiting factors on
this line are 397
ACSR conductor
and jumpers Internal circuit breaker fault
CB 224 at Birch Creek 230 kV
(P2-3)
118% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 244 at Birch Creek 230 kV
(P2-3)
118% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 264 at Birch Creek 230 kV
(P2-3)
118% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 225 at Ben Lomond 230
kV (P2-3)
106% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 245 at Ben Lomond 230
kV (P2-3)
107% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640

• Overload on Snyderville – Cottonwood 138 kV line
Contingency % of Overload Worst Case Mitigation
N-1 of Birch Creek - Ben
Lomond 230 kV line (P1-2)
101% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Rebuild 16.853-mile
of 500 AAC (0.54
miles), 397 ACSR
(1.413 miles) and
397.5 ACSR (14.9
miles) sections on
Snyderville –
Cottonwood 138 kV
line with 1272
ACSR because the
limiting factor on
this line are 500
AAC, 397 ACSR
and 397.5 ACSR
conductors
Internal circuit breaker fault
CB 224 at Birch Creek 230 kV
(P2-3)
113% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 244 at Birch Creek 230 kV
(P2-3)
113% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 264 at Birch Creek 230 kV
(P2-3)
113% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 225 at Ben Lomond 230
kV (P2-3)
101% of its 30-
minute rating
Light Load
Stressed -
Transition Cluster Study Report
Transition Cluster Area 2 Page 76 March 31, 2021

Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 245 at Ben Lomond 230
kV (P2-3)
101% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640

• Low voltage in Croydon and Coalville areas
Contingency Worst Case Mitigation
N-1 of Birch Creek - Q1083 POI
230 kV line (P1-2) Light Load
At least 80 Mvar cap
banks at Croydon 138 kV
are required to mitigate
the low voltage issues.
The optimal shunt
capacitor bank size is 4 x
20 Mvar.
Internal circuit breaker fault CB
224 at Birch Creek 230 kV (P2-3)
Light Load Stressed -
Path C: N1250 & RS/F: 640
Internal circuit breaker fault CB
244 at Birch Creek 230 kV (P2-3)
Light Load Stressed -
Path C: N1250 & RS/F: 640
Internal circuit breaker fault CB
264 at Birch Creek 230 kV (P2-3)
Light Load Stressed -
Path C: N1250 & RS/F: 640

Transition Cluster Study Report
Transition Cluster Area 2 Page 77 March 31, 2021

Figure 16: Internal Breaker Fault CB 244 at Birch Creek 230 kV (P2-3) during off-peak load
with Path C northbound and Rock Springs/ Firehole path stressed

• Overload on Ben Lomond 345/230 kV transformer #1
Contingency % of Overload Worst Case Mitigation
Ben Lomond 345/230 kV
transformer #2 (P1-3)
107% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Upgrade the existing
Ben Lomond
345/230 kV
448/502/502 MVA
transformer #1 to
700 MVA rating Internal circuit breaker fault
CB 349 at Ben Lomond 345
kV (P2-3)
106% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 368 at Ben Lomond 345
kV (P2-3)
102% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 367 at Ben Lomond 345
kV (P2-3)
113% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 366 at Ben Lomond 345
kV (P2-3)
102% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 343 at Ben Lomond 345
kV (P2-3)
109% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 242 at Ben Lomond 230
kV (P2-3)
106% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640

Transition Cluster Study Report
Transition Cluster Area 2 Page 78 March 31, 2021

Figure 17: Internal Breaker Fault CB 367 at Ben Lomond 345 kV (P2-3) during off-peak load
with Path C northbound and Rock Springs/ Firehole path stressed

• Overload on Ben Lomond 345/230 kV transformer #2
Contingency % of Overload Worst Case Mitigation
Ben Lomond 345/230 kV
transformer #1 (P1-3)
108% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Upgrade the existing
Ben Lomond
345/230 kV
448/502/502 MVA
transformer #2 to
700 MVA rating Internal circuit breaker fault
CB 329 at Ben Lomond 345
kV (P2-3)
108% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 328 at Ben Lomond 345
kV (P2-3)
108% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 327 at Ben Lomond 345
kV (P2-3)
115% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Transition Cluster Study Report
Transition Cluster Area 2 Page 79 March 31, 2021

Internal circuit breaker fault
CB 326 at Ben Lomond 345
kV (P2-3)
108% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 323 at Ben Lomond 345
kV (P2-3)
113% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 204 at Ben Lomond 230
kV (P2-3)
134% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 205 at Ben Lomond 230
kV (P2-3)
131% of its 30-
minute rating
Light Load
Stressed -
Path C: N1250 &
RS/F: 640
Internal circuit breaker fault
CB 205 at Ben Lomond 230
kV (P2-3)
103% of its 30-
minute rating
Heavy Load
Stressed - Path
C:1560 & RS/F:
640

Transition Cluster Study Report
Transition Cluster Area 2 Page 80 March 31, 2021

Figure 18: Internal Breaker Fault CB 204 at Ben Lomond 230 kV (P2-3) during off-peak load
with Path C northbound and Rock Springs/ Firehole path stressed

• Overload on Wheelon – Honeyville 138 kV line
Contingency % of Overload Worst Case Mitigation
N-1 of Ben Lomond -
Honeyville 138 kV line (P1-2)
102% of its 30-
minute rating Light Load Rebuild 13.76-mile
250 CUHD section
on Wheelon –
Honeyville 138 kV
line with 795 ACSR
Bus fault at Ben Lomond 138
kV east bus (P2-2)
102% of its 30-
minute rating Light Load
Bus fault at Wheelon 138 kV
bus (P2-2)
102% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB L135, CB L110 & CB 111
at Ben Lomond 138 kV (P2-3)
102% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 102 at Ben Lomond 138
kV (P2-3)
102% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 107 & CB C149 at Ben
Lomond 138 kV (P2-3)
102% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 105 at Ben Lomond 138
kV (P2-3)
102% of its 30-
minute rating Light Load
Internal bus-tie circuit breaker
fault CS 131I at Ben Lomond
138 kV (P2-4)
102% of its 30-
minute rating Light Load
N-2 of Ben Lomond -
Honeyville & Ben Lomond -
Rocky Point - Wheelon 138
kV lines (P7)
102% of its 30-
minute rating Light Load

Transition Cluster Study Report
Transition Cluster Area 2 Page 81 March 31, 2021

Figure 19: N-2 of Ben Lomond – Honeyville and Ben Lomond – Rocky Point – Wheelon 138 kV
lines (P7) during off-peak load

• Overload on Ben Lomond – Plain City 138 kV line
Contingency % of Overload Worst Case Mitigation
N-2 of Ben Lomond -
Syracuse & Ben Lomond -
Terminal 345 kV lines (P7)
101% of its 30-
minute rating
Heavy Load
Stressed -
Path C: S1560 &
RS/F: 640
Rebuild 16.46-mile 2
x 250 CUHD section
on Ben Lomond –
Plain City 138 kV
line with 1272 ACSR

Transition Cluster Study Report
Transition Cluster Area 2 Page 82 March 31, 2021

Figure 20: N-2 of Ben Lomond – Syracuse and Ben Lomond – Terminal 345 kV lines (P7) during
peak load with Path C southbound and Rock Springs/ Firehole path stressed

• Overload on Ben Lomond – Honeyville 138 kV line
Contingency % of Overload Worst Case Mitigation
Internal circuit breaker fault
CB 103, CB 104, CB 105, CB
107, CB 112, CB 114 & CB
115 at Wheelon 138 kV (P2-3)
102% of its 30-
minute rating Light Load
Rebuild 16.46-mile
250 CUHD section
on Ben Lomond –
Honeyville 138 kV
line with 795 ACSR Internal circuit breaker fault
CB 102 at Wheelon 138 kV
(P2-3)
102% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 116 at Wheelon 138 kV
(P2-3)
102% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 113 at Wheelon 138 kV
(P2-3)
102% of its 30-
minute rating Light Load
N-2 of Bridgerland - Wheelon
& Ben Lomond - Rocky Point
- Wheelon 138 kV lines (P7)
109% of its 30-
minute rating Light Load
Transition Cluster Study Report
Transition Cluster Area 2 Page 83 March 31, 2021

N-2 of Bridgerland - Ben
Lomond & Populus - Ben
Lomond 345 kV #2 lines (P7)
109% of its 30-
minute rating
Heavy Load
Stressed -
Path C: S1600 &
RS/F: 575

• Overload on Wheelon – Rocky Point 138 kV line
Contingency % of Overload Worst Case Mitigation
N-2 of Bridgerland - Ben
Lomond & Populus - Ben
Lomond 345 kV #2 lines (P7)
100% of its 30-
minute rating
Heavy Load
Stressed -
Path C:1600 &
RS/F: 575
Modify a RAS
associated with the
Transmission
Provider’s planned
Path C Improvement
project to monitor the
Populus–Bridgerland
345 kV line

• Overload on Bridgerland – Brigham City 138 kV line
Contingency % of Overload Worst Case Mitigation
N-2 of Bridgerland - Ben
Lomond & Populus - Ben
Lomond 345 kV #2 lines (P7)
103% of its 30-
minute rating
Heavy Load
Stressed -
Path C:1600 &
RS/F: 575
Modify a RAS
associated with the
Transmission
Provider’s planned
Path C Improvement
project to monitor the
Populus–Bridgerland
345 kV line

Transition Cluster Study Report
Transition Cluster Area 2 Page 84 March 31, 2021

Figure 21: N-2 of Ben Lomond – Bridgerland and Ben Lomond – Populus #2 345 kV lines (P7)
during peak load with Path C southbound and Rock Springs/ Firehole path stressed

• Overload on the Birch Creek–TSC-17 POI 230 kV line
Contingency % of Overload Worst Case Mitigation
N-1 of Naughton - Glenco -
STR 204 - Ricky Man -
Canyon Compression 138 kV
line (P1-2)
102% of its 30-
minute rating Light Load
Rebuild 3.3-mile
Birch Creek – Q1083
(TCS-17) POI 230
kV line with 2 x 1272
ACSR because the
limiting factor on this
line is 954 ACSR
conductor
N-1 of Railroad - Q1116 POI
138 kV line (P1-2)
105% of its 30-
minute rating Light Load
N-1 of Croydon - Q1116 POI
138 kV line (P1-2)
116% of its 30-
minute rating Light Load
N-1 of Croydon - Coalville -
Silver Creek 138 kV line (P1-
2)
115% of its 30-
minute rating Light Load
N-1 of Naughton 230/138 kV
transformer #1 (P1-3)
100% of its 30-
minute rating Light Load
Open Silver Creek - Lost
Canyon Pump 138 kV line at
Silver Creek (P2-1)
114% of its 30-
minute rating Light Load
Transition Cluster Study Report
Transition Cluster Area 2 Page 85 March 31, 2021

Open Croydon - Coalville 138
kV line at Croydon (P2-1)
115% of its 30-
minute rating Light Load
Open Naughton - Glenco 138
kV line at Naughton (P2-1)
100% of its 30-
minute rating Light Load
Bus fault at Silver Creek 138
kV (P2-2)
114% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 139 at Canyon
Compression 138 kV (P2-3)
103% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 135 at Canyon
Compression 138 kV (P2-3)
103% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 137 at Canyon
Compression 138 kV (P2-3)
123% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 131 at Silver Creek 138 kV
(P2-3)
115% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 7A3 at Croydon 138 kV
(P2-3)
115% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 7A13 at Croydon 138 kV
(P2-3)
116% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 7A17 at Croydon 138 kV
(P2-3)
116% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 7A25 at Croydon 138 kV
(P2-3)
116% of its 30-
minute rating Light Load

Transition Cluster Study Report
Transition Cluster Area 2 Page 86 March 31, 2021

Figure 22: Internal Breaker Fault CB 137at Canyon Compression 138 kV (P2-3) during off-peak
load

• Overload on Treasureton – Q974 POI 230 kV line
Contingency % of Overload Worst Case Mitigation
N-1 of Naughton - Ben
Lomond 230 kV line (P1-2)
106% of its 30-
minute rating
Light Load
Stressed
Rebuild 52.58-mile
Treasureton – Q974
(prior cluster queue)
POI 230 kV line with
2 x 1272 ACSR
because the limiting
factor on this line is 1
x 1272 ACSR
conductor
N-1 of Birch Creek - Ben
Lomond 230 kV line (P1-2)
110% of its 30-
minute rating
Light Load
Stressed
Internal circuit breaker fault
CB 224 at Ben Lomond 230
kV (P2-3)
107% of its 30-
minute rating
Light Load
Stressed
Internal circuit breaker fault
CB 244 at Ben Lomond 230
kV (P2-3)
107% of its 30-
minute rating
Light Load
Stressed
Internal circuit breaker fault
CB 225 at Ben Lomond 230
kV (P2-3)
110% of its 30-
minute rating
Light Load
Stressed
Internal circuit breaker fault
CB 245 at Ben Lomond 230
kV (P2-3)
111% of its 30-
minute rating
Light Load
Stressed

Transition Cluster Study Report
Transition Cluster Area 2 Page 87 March 31, 2021

Figure 23: Internal Breaker Fault CB 245at Ben Lomond 230 kV (P2-3) during off-peak load
with Rock Springs/ Firehole path stressed

• Overload on Ben Lomond – Birch Creek 230 kV line
Contingency % of Overload Worst Case Mitigation
N-1 of Naughton - Ben
Lomond 230 kV line (P1-2)
103% of its 30-
minute rating
Light Load
Stressed
Rebuild 55.13-mile
Ben Lomond – Birch
Creek 230 kV line
with 2 x 1272 ACSR
because the limiting
factor on this line is 2
x 795 ACSR
conductor
Internal circuit breaker fault
CB 224 at Ben Lomond 230
kV (P2-3)
102% of its 30-
minute rating
Light Load
Stressed
Internal circuit breaker fault
CB 244 at Ben Lomond 230
kV (P2-3)
102% of its 30-
minute rating
Light Load
Stressed
Transition Cluster Study Report
Transition Cluster Area 2 Page 88 March 31, 2021

Figure 24: Outage of Naughton – Ben Lomond 230 kV line (P1-2) during off-peak load with
Rock Springs/ Firehole path stressed

• Overload on Naughton – Craven Creek230 kV line
Contingency % of Overload Worst Case Mitigation
N-1 of Naughton - Lima 230
kV line (P1-2)
110% of its 30-
minute rating
Light Load
Stressed
Rebuild 15.88-mile
Naughton – Craven
Creek 230 kV line
with 1272 ACSR
because the limiting
factor on this line is
795 ACSR conductor
N-1 of Monument - Lima 230
kV line (P1-2)
109% of its 30-
minute rating
Light Load
Stressed

Transition Cluster Study Report
Transition Cluster Area 2 Page 89 March 31, 2021

Figure 25: Outage of Naughton – Lima 230 kV line (P1-2) during off-peak load with Rock
Springs/ Firehole path stressed

• Overload on Naughton – Lima 230 kV line
Contingency % of Overload Worst Case Mitigation
N-1 of Monument - Craven
Creek 230 kV line (P1-2)
109% of its 30-
minute rating
Light Load
Stressed
Replace the existing
wavetraps and CTs
on Naughton – Lima
230 kV line with the
higher ratings
because the limiting
factors on this line
are wavetraps and
CTs
N-1 of Naughton - Craven
Creek 230 kV line (P1-2)
111% of its 30-
minute rating
Light Load
Stressed
Internal circuit breaker fault
CB 1H632 at Craven Creek
230 kV (P2-3)
108% of its 30-
minute rating
Light Load
Stressed
Transition Cluster Study Report
Transition Cluster Area 2 Page 90 March 31, 2021

Figure 26: Outage of Naughton – Craven Creek 230 kV line (P1-2) during off-peak load with
Rock Springs/ Firehole path stressed

• Overload on Canyon Compression – Canyon Compression Tap 138 kV line
Contingency % of Overload Worst Case Mitigation
N-1 of Birch Creek - Q1083
POI 230 kV line (P1-2)
125% of its 30-
minute rating Light Load Rebuild 1.07-mile
Canyon Compression
– Canyon
Compression Tap 138
kV line with 1272
ACSR because the
limiting factor on this
line is 795 ACSR
conductor
Internal circuit breaker fault
CB 224 at Birch Creek 230 kV
(P2-3)
124% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 244 at Birch Creek 230 kV
(P2-3)
124% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 264 at Birch Creek 230 kV
(P2-3)
124% of its 30-
minute rating Light Load

• Overload on Canyon Compression Tap – Q715 POI 138 kV line
Contingency % of Overload Worst Case Mitigation
N-1 of Birch Creek - Q1083
POI 230 kV line (P1-2)
126% of its 30-
minute rating Light Load Rebuild 0.34-mile
Canyon Compression
Tap – Q715 (prior
cluster queue) POI
138 kV line with
1272 ACSR because
the limiting factor on
Internal circuit breaker fault
CB 224 at Birch Creek 230 kV
(P2-3)
125% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 244 at Birch Creek 230 kV
(P2-3)
125% of its 30-
minute rating Light Load
Transition Cluster Study Report
Transition Cluster Area 2 Page 91 March 31, 2021

Internal circuit breaker fault
CB 264 at Birch Creek 230 kV
(P2-3)
125% of its 30-
minute rating Light Load
this line is 795 ACSR
conductor

• Overload on Naughton – Glenco Tap 138 kV line
Contingency % of Overload Worst Case Mitigation
N-1 of Birch Creek - Q1083
POI 230 kV line (P1-2)
104% of its 30-
minute rating Light Load Rebuild 0.34-mile
Canyon Compression
Tap – Q715 (prior
cluster queue) POI
138 kV line with
1272 ACSR because
the limiting factor on
this line is 795 ACSR
conductor
Internal circuit breaker fault
CB 224 at Birch Creek 230 kV
(P2-3)
103% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 244 at Birch Creek 230 kV
(P2-3)
104% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 264 at Birch Creek 230 kV
(P2-3)
104% of its 30-
minute rating Light Load

• Overload on Glenco Tap – Structure (STR) 204 138 kV line
Contingency % of Overload Worst Case Mitigation
N-1 of Birch Creek - Q1083
POI 230 kV line (P1-2)
105% of its 30-
minute rating Light Load Rebuild 17.03-mile
Glenco Tap –
Structure (STR) 204
138 kV line with
1272 ACSR because
the limiting factor on
this line is 795 ACSR
conductor
Internal circuit breaker fault
CB 224 at Birch Creek 230 kV
(P2-3)
104% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 244 at Birch Creek 230 kV
(P2-3)
104% of its 30-
minute rating Light Load
Internal circuit breaker fault
CB 264 at Birch Creek 230 kV
(P2-3)
104% of its 30-
minute rating Light Load

Transition Cluster Study Report
Transition Cluster Area 2 Page 92 March 31, 2021

Figure 27: Outage of Birch Creek – Q1083 (TCS-17) POI 230 kV line (P1-2) during off-peak
load

Information
• It is assumed that the common structures sharing the Naughton – Ben Lomond and Birch
Creek – Ben Lomond 230 kV lines are separated by a higher priority Interconnection
Request. Otherwise, N-2 of the Naughton – Ben Lomond and Birch Creek – Ben Lomond
230 kV lines make the case not even converged during light load with off-peak load with
Rock Springs/ Firehole path stressed.

Transition Cluster Study Report
Transition Cluster Area 2 Page 93 March 31, 2021

12.2 Appendix 2: Higher Priority Requests
All active higher priority Transmission Provider projects, and transmission service and/or
generator interconnection requests will be considered in this cluster area study and are
identified below. If any of these requests are withdrawn, the Transmission Provider reserves
the right to restudy this request, as the results and conclusions contained within this study
could significantly change.

Transmission/Generation Interconnection Queue Requests considered:

Q0753 (80 MW) (TSR 2790)
Q0754 (80 MW) (TSR 2846)
Q0799 (67 MW)
Q0862 (45 MW)
Q0941 (45 MW)
Q0715 (120 MW)
Q0786 (100 MW)
Q0810 (101 MW)
Q0958 (21 MW) (TSR 2409)
Q0974 (80 MW)
Transition Cluster Study Report
Transition Cluster Area 2 Page 94 March 31, 2021

12.3 Appendix 3: Property Requirements
Property Requirements for Point of Interconnection Substation
Requirements for rights of way easements
Rights of way easements will be acquired by the Interconnection Customer in the
Transmission Provider’s name for the construction, reconstruction, operation, maintenance,
repair, replacement and removal of Transmission Provider’s Interconnection Facilities that
will be owned and operated by PacifiCorp. Interconnection Customer will acquire all
necessary permits for the Project and will obtain rights of way easements for the Project on
Transmission Provider’s easement form.

Real Property Requirements for Point of Interconnection Substation
Real property for a point of interconnection substation will be acquired by an Interconnection
Customer to accommodate the Interconnection Customer’s Project. The real property must be
acceptable to Transmission Provider. Interconnection Customer will acquire fee ownership
for interconnection substation unless Transmission Provider determines that other than fee
ownership is acceptable; however, the form and instrument of such rights will be at
Transmission Provider’s sole discretion. Any land rights that Interconnection Customer is
planning to retain as part of a fee property conveyance will be identified in advance to
Transmission Provider and are subject to the Transmission Provider’s approval.

The Interconnection Customer must obtain all permits required by all relevant jurisdictions
for the planned use including but not limited to conditional use permits, Certificates of Public
Convenience and Necessity, California Environmental Quality Act, as well as all
construction permits for the Project.

If eligible, Interconnection Customer will not be reimbursed through network upgrades for
more than the market value of the property.

As a minimum, real property must be environmentally, physically, and operationally
acceptable to Transmission Provider. The real property shall be a permitted or able to be
permitted use in all zoning districts. The Interconnection Customer shall provide
Transmission Provider with a title report and shall transfer property without any material
defects of title or other encumbrances that are not acceptable to Transmission Provider.
Property lines shall be surveyed and show all encumbrances, encroachments, and roads.

Examples of potentially unacceptable environmental, physical, or operational conditions
could include but are not limited to:

1. Environmental: known contamination of site; evidence of environmental
contamination by any dangerous, hazardous or toxic materials as defined by any
governmental agency; violation of building, health, safety, environmental, fire,
land use, zoning or other such regulation; violation of ordinances or statutes of
any governmental entities having jurisdiction over the property; underground or
above ground storage tanks in area; known remediation sites on property; ongoing
mitigation activities or monitoring activities; asbestos; lead-based paint, etc. A
Transition Cluster Study Report
Transition Cluster Area 2 Page 95 March 31, 2021

phase I environmental study is required for land being acquired in fee by the
Transmission Provider unless waived by Transmission Provider.

2. Physical: inadequate site drainage; proximity to flood zone; erosion issues;
wetland overlays; threatened and endangered species; archeological or culturally
sensitive areas; inadequate sub-surface elements, etc. Transmission Provider may
require Interconnection Customer to procure various studies and surveys as
determined necessary by Transmission Provider.

Operational: inadequate access for Transmission Provider’s equipment and vehicles; existing
structures on land that require removal prior to building of substation; ongoing maintenance
for landscaping or extensive landscape requirements; ongoing homeowner's or other
requirements or restrictions (e.g., Covenants, Codes and Restrictions, deed restrictions, etc.)
on property which are not acceptable to the Transmission Provider.

Generation Interconnection Transition Cluster

Transition Cluster Study Report

Cluster Area 3

March 31, 2021

Transition Cluster Study Report
Transition Cluster Area 3 Page i March 31, 2021

TABLE OF CONTENTS

1.0 SCOPE OF THE STUDY ................................................................................................................. 1
2.0 STUDY ASSUMPTIONS ................................................................................................................. 1
3.0 GENERATING FACILITY REQUIREMENTS .............................................................................. 2
3.1 Transmission Voltage Interconnection Requests .............................................................................. 3
3.2 Distribution Voltage Interconnection Requests ................................................................................ 5
4.0 CLUSTER AREA DEFINITIONS ................................................................................................... 6
5.0 CLUSTER AREA 3 .......................................................................................................................... 6
5.1 Description of Interconnection Request – TCS-27 ........................................................................... 6
5.2 Description of Interconnection Request – TCS-48 ........................................................................... 8
6.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS ........................................................ 9
6.1 Transmission System Requirements ................................................................................................. 9
6.2 Distribution System Requirements ................................................................................................... 9
6.3 Transmission Line Requirements ...................................................................................................... 9
6.4 Existing Circuit Breaker Upgrades – Short Circuit ........................................................................... 9
6.5 Protection Requirements ................................................................................................................... 9
6.6 Data (RTU) Requirements .............................................................................................................. 10
6.7 Substation Requirements ................................................................................................................. 12
6.8 Communication Requirements ........................................................................................................ 13
6.9 Metering Requirements ................................................................................................................... 14
7.0 CONTINGENT FACILITIES ......................................................................................................... 16
8.0 COST ESTIMATE .......................................................................................................................... 17
8.1 Interconnection Facilities ................................................................................................................ 17
8.2 Station Equipment ........................................................................................................................... 18
8.3 Network Upgrades .......................................................................................................................... 18
8.4 Total Estimated Project Costs ......................................................................................................... 18
9.0 SCHEDULE .................................................................................................................................... 19
10.0 AFFECTED SYSTEMS ................................................................................................................. 19
11.0 APPENDICES ................................................................................................................................ 19
11.1 Appendix 1: Cluster Area Power Flow and Stability Study Results ............................................... 20
11.2 Appendix 2: Higher Priority Requests ............................................................................................ 21
11.3 Appendix 3: Property Requirements ............................................................................................... 22

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1.0 SCOPE OF THE STUDY
Cluster Area 3 (CA3) generally includes the Salt Lake Valley and includes the following two
Interconnection Requests: TCS-27 and TCS-48

Consistent with Attachment W, Section 3.4.2 and Section 51.4 of PacifiCorp’s (“Transmission
Provider”) Open Access Transmission Tariff (“OATT”), this interconnection Transition Cluster
Study (“Cluster Study”) evaluated the impact of the proposed interconnections on the reliability
of the Transmission System. The Cluster Study considered the Base Case as well as all generating
facilities (and with respect to (iii) below, any identified Network Upgrades associated with such
higher queued interconnection) that, on the date the Cluster Request Window closes:

(i) are existing and directly interconnected to the Transmission System;
(ii) are existing and interconnected to Affected Systems and may have an impact on the
Interconnection Request;
(iii) have a pending higher queued or higher clustered interconnection request to interconnect
to the transmission system; and
(iv) have executed an LGIA or requested that an unexecuted LGIA be filed with FERC.

The Cluster Study consisted of power flow, stability, and short circuit analyses.

This Cluster Study report provides the following information:
• identification of any circuit breaker short circuit capability limits exceeded as a result of the
interconnection;
• identification of any thermal overload or voltage limit violations resulting from the
interconnection;
• identification of any instability or inadequately damped response to system disturbances
resulting from the interconnection and
• description and non-binding, good faith estimated cost of facilities required to interconnect the
Generating Facilities to the Transmission System and to address the identified short circuit,
instability, and power flow issues.
2.0 STUDY ASSUMPTIONS
• All active higher priority transmission service and/or generator interconnection requests
that were considered in this study are listed in Appendix 2. If any of these requests are
withdrawn, the Transmission Provider reserves the right to restudy this request, and the
results and conclusions could significantly change.
• For study purposes there are two separate queues:
o Transmission Service Queue: to the extent practical, all network upgrades that are
required to accommodate active transmission service requests were modeled in this
study.
o Generation Interconnection Queue: Interconnection Facilities and network
upgrades associated with higher queued or higher clustered interconnection
requests were modeled in this study.
• The Interconnection Customers’ request for energy or network resource interconnection
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service in and of itself does not request or convey transmission service. Only a Network
Customer may make a request to designate a generating resource as a Network Resource.
Because the queue of higher priority transmission service requests may be different when
a Network Customer requests network resource designation for this Generating Facility,
the available capacity or transmission modifications, if any, necessary to provide Network
Integration Transmission Service may be significantly different. Therefore,
Interconnection Customers should regard the results of this study as informational rather
than final.
• Under normal conditions, the Transmission Provider does not dispatch or otherwise
directly control or regulate the output of generating facilities. Therefore, the need for
transmission modifications, if any, that may be required to provide Network Resource
Interconnection Service will be evaluated on the basis of 100 percent deliverability (i.e.,
this study did not model displacement of other resources in the same area).
• This study assumed the Projects will be integrated into the Transmission Provider’s system
at agreed upon and/or proposed Points of Interconnection (“POI” or “POIs”).
• If Interconnection Customers proceed through the interconnection process, they will be
required to construct and own any facilities required between the Point of Change of
Ownership and the Project unless specifically identified by the Transmission Provider.
• Line reconductor or fiber underbuild required on existing poles were assumed to follow the
most direct path on the Transmission Provider’s system. If during detailed design the path
must be modified it may result in additional cost and timing delays for the Interconnection
Customer’s Project.
• Generator tripping may be required for certain outages.
• All facilities will meet or exceed the minimum Western Electricity Coordinating Council
(“WECC”), North American Electric Reliability Corporation (“NERC”), and the
Transmission Provider’s performance and design standards.
• Power flow analysis requires WECC base cases to reliably balance under peak load
conditions the aggregate of generation in the local area, with the Generating Facility at full
output, to the aggregate of the load in the Transmission Provider’s Transmission System.
As the PacifiCorp East (“PACE”) balancing authority area (“BAA”) has more existing and
proposed generation than load, it is necessary to assume some portion of other remote
resources are displaced by this Project’s output in order to assess the impact of
interconnecting this Project’s generation to transmission system operations. For the
purposes of this study, generation in the Transmission Provider’s southern Utah area was
assumed to be displaced.
• The case was studied before and after the addition of relevant capital projects up to year
2022. They are the Magna capacitor project and Path C Improvement project.
• This report is based on information available at the time of the study. It is the
Interconnection Customer’s responsibility to check the Transmission Provider’s web site
regularly for Transmission System updates at https://www.oasis.oati.com/ppw
3.0 GENERATING FACILITY REQUIREMENTS
The following requirements are applicable to all Interconnection Requests. The Transmission
Provider will identify any site-specific Generating Facility requirements in addition to the
following in this report and in Facilities Studies. Certain Interconnection Requests requesting
service at a voltage level traditionally defined as distribution may be subject to the transmission
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interconnection request requirements listed below should the Transmission Provider make that
determination.
3.1 Transmission Voltage Interconnection Requests
All interconnecting synchronous and non-synchronous generators are required to design their
Generating Facilities with reactive power capabilities necessary to operate within the full power
factor range of 0.95 leading to 0.95 lagging. This power factor range shall be dynamic and can be
met using a combination of the inherent dynamic reactive power capability of the generator or
inverter, dynamic reactive power devices and static reactive power devices to make up for losses.

For synchronous generators, the power factor requirement is to be measured at the POI. For non-
synchronous generators, the power factor requirement is to be measured at the high-side of the
generator substation.

The Generating Facility must provide dynamic reactive power to the system in support of both
voltage scheduling and contingency events that require transient voltage support, and must be able
to provide reactive capability over the full range of real power output.

If the Generating Facility is not capable of providing positive reactive support (i.e., supplying
reactive power to the system) immediately following the removal of a fault or other transient low
voltage perturbations, the Generating Facility must be required to add dynamic voltage support
equipment. These additional dynamic reactive devices shall have correct protection settings such
that the devices will remain on line and active during and immediately following a fault event.

Generators shall be equipped with automatic voltage-control equipment and normally operated
with the voltage regulation control mode enabled unless written authorization (or directive) from
the Transmission Provider is given to operate in another control mode (e.g. constant power factor
control). The control mode of generating units shall be accurately represented in operating studies.
The generators shall be capable of operating continuously at their maximum power output at its
rated field current within +/- 5% of its rated terminal voltage.

All generators are required to ensure the primary frequency capability of their facility by installing,
maintaining, and operating a functioning governor or equivalent controls as indicated in FERC
Order 842.

As required by NERC standard VAR-001-4.2, the Transmission Provider will provide a voltage
schedule for the POI. In general, Generating Facilities should be operated so as to maintain the
voltage at the POI, typically between 1.00 per unit to 1.04 per unit, or other designated point as
deemed appropriated by Transmission Provider. The Transmission Provider may also specify a
voltage and/or reactive power bandwidth as needed to coordinate with upstream voltage control
devices such as on-load tap changers. At the Transmission Provider’s discretion, these values
might be adjusted depending on operating conditions.

Generating Facilities capable of operating with a voltage droop are required to do so. Voltage
droop control enables proportionate reactive power sharing among Generation Facilities. Studies
will be required to coordinate voltage droop settings if there are other facilities in the area. It will
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be the Interconnection Customer’s responsibility to ensure that a voltage coordination study is
performed, in coordination with Transmission Provider, and implemented with appropriate
coordination settings prior to unit testing.

For areas with multiple Generating Facilities additional studies may be required to determine
whether or not critical interactions, including but not limited to control systems, exist. These
studies, to be coordinated with Transmission Provider, will be the responsibility of the
Interconnection Customer. If the need for a master controller is identified, the cost and all related
installation requirements will be the responsibility of the Interconnection Customer. Participation
by the Generation Facility in subsequent interaction/coordination studies will be required pre- and
post-commercial operation in order ensure system reliability.

Interconnection Requests that are 75 MVA or larger may be required to facilitate collection and
validation of accurate modeling data to meet NERC modeling standards. The Transmission
Provider, in its roles as the Planning Coordinator, requires Phasor Measurement Units (PMUs) at
all new Generating Facilities with an individual or aggregate nameplate capacity of 75 MVA or
greater. In addition to owning and maintaining the PMU, the Generating Facility will be
responsible for collecting, storing (for a minimum of 90 days) and retrieving data as requested by
the Planning Coordinator. Data must be stored for a minimum of 90 days. Data must be collected
and be able to stream to Planning Coordinator for each of the Generating Facility’s step-up
transformers measured on the low side of the GSU at a sample rate of at least 60 samples per
second and synchronized within +/- 2 milliseconds of the Coordinated Universal Time (UTC).
Initially, the following data must be collected:
• Three phase voltage and voltage angle (analog)
• Three phase current (analog)
Data requirements are subject to change as deemed necessary to comply with local and federal
regulations.

All generators must meet the Federal Energy Regulatory Commission (FERC), North American
Electric Reliability Corporation (NERC) and WECC low voltage ride-through requirements as
specified in the interconnection agreement. Inverters must be designed to stay connected to the
grid in the case of severe faults and may not momentarily cease output within the no-trip area of
the voltage curves. Figure 1 illustrates the voltage ride-through capability as per NERC PRC-
024. Importantly, inverters should be designed such that a trip outside of the curves is a “may-
trip” area (if needed to protect equipment) not a “must-trip” area. Inverters that momentarily cease
active power output for these voltage excursions should be configured to restore output to pre-
disturbance levels in no greater than five seconds, provided the inverter is capable of these changes.
Generators must provide test results to the Transmission Provider verifying that the inverters for
this Project have been programmed to meet all PRC-024 requirements rather than manufacturer
IEEE distribution standards.

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Figure 1 – Voltage Ride-Through Curve

As the Transmission Provider cannot submit a user written model to WECC for inclusion in base
cases, a standard model from the WECC Approved Dynamic Model Library is required 180 days
prior to trial operation. The list of approved generator models is continually updated and is
available on the http://www.WECC.biz website.

Interconnection Customer with an Interconnection Request for a Generating Facility that is both
75 MVA or larger as well as being interconnected at a voltage higher than 100 kV shall register
with NERC as the Generator Owner (“GO”) and Generator Operator (“GOP”) for the Large
Generating Facility and provide the Transmission Provider documentation demonstrating
registration in order to be approved for Commercial Operation. This registration must be
maintained throughout the lifetime of the Interconnection Agreement.

Interconnection Customers are responsible for the protection of transmission lines between the
Generating Facility and the POI substation. For Interconnection Requests that are smaller than 75
MVA or are interconnected at a voltage less than 100 kV which have a tie line that is longer than
800 feet the Interconnection Customer shall construct and own a tie-line substation to be located
at the change of ownership (separate fenced facility adjacent to the Transmission Provider’s POI
substation). The tie line substation shall include an Interconnection Customer owned protective
device and associated transmission line relaying/communications. The ground grids of the
Transmission Provider’s POI substation and the Interconnection Customer’s tie-line substation
will be connected to support the use of a bus differential protection scheme which will protect the
overhead bus connection between the two facilities.
3.2 Distribution Voltage Interconnection Requests
The Generating Facility and interconnection equipment owned by the Interconnection Customers
are required to operate under constant power factor mode with a unity power factor setting unless
specifically requested otherwise by the Transmission Provider. The Generating Facilities are
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expressly forbidden from actively participating in voltage regulation of the Transmission
Provider’s system without written request or authorization from the Transmission Provider. The
Generating Facilities shall have sufficient reactive capacity to enable the delivery of 100 percent
of the plant output to the applicable POI at unity power factor measured at 1.0 per unit voltage
under steady state conditions.

Generators capable of operating under voltage control with voltage droop are required to do so.
Studies will be required to coordinate the voltage droop setting with other facilities in the area. In
general, the Generating Facility and Interconnection Equipment should be operated so as to
maintain the voltage at the POI between 1.01 pu to 1.04 pu. At the Public Utility’s discretion, these
values might be adjusted depending on the operating conditions. Within this voltage range, the
Generating Facility should operate so as to minimize the reactive interchange between the
Generating Facility and the Public Utility’s system (delivery of power at the POI at approximately
unity power factor). The voltage control settings of the Generating Facility must be coordinated
with the Public Utility prior to energization (or interconnection). The reactive compensation must
be designed such that the discreet switching of the reactive device (if required by the
Interconnection Customer) does not cause step voltage changes greater than +/-3% on the Public
Utility’s system.

All generators must meet applicable WECC low voltage ride-through requirements as specified in
the interconnection agreement.

As per NERC standard VAR-001-1, the Public Utility is required to specify voltage or reactive
power schedule at the POI. Under normal conditions, the Public Utility’s system should not supply
reactive power to the Generating Facility.
4.0 CLUSTER AREA DEFINITIONS
The Transmission Provider performed the Transition Cluster Study based on geographically and/or
electrically relevant areas on the Transmission Provider’s Transmission System known as Cluster
Areas. The Transmission Provider has determined that the Interconnection Requests discussed in
Section 5.0 are located in a geographically and/or electrically relevant area on Transmission
Provider’s Transmission System, and thus, were assigned Cluster Area 3 in the Transition Cluster
Study process.
5.0 CLUSTER AREA 3
Cluster Area 3 (CA3) generally includes the Salt Lake Valley and includes the following two
Interconnection Requests.
5.1 Description of Interconnection Request – TCS-27
The Interconnection Customer has proposed to interconnect 60 megawatts (“MW”) of new
generation to PacifiCorp’s (“Transmission Provider”) Terminal-Goggin-Grow 138 kV
transmission line located in Salt Lake County, UT. The Interconnection Request is proposed to
consist of twenty four (24) 2500 KVA SMA Sunny Central 2500-EV-US solar inverters for a total
output of 60 MW at the POI. The Interconnection Request also consists of 30 MW of battery
storage with no capability to charge from the Transmission Provider’s grid. The requested
commercial operation date is December 31, 2021. Figure 2 below, is a one-line diagram that
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illustrates the interconnection of the proposed Generating Facility to the Transmission Provider’s
system.

Interconnection Customer will operate this generator as a Qualified Facility as defined by the
Public Utility Regulatory Policies Act of 1978 (PURPA).

The Interconnection Request will be studied for Network Resource Interconnection Service
(“NRIS”).

The Transmission Provider has assigned the Project Cluster Number “TCS-27”

30/50 MVAZ = 8.35 %
TCS-27
Collector
Substation
M
Lee Creek Substation
M
Point of Interconnection
Change of Ownership
Grow-
Terminal
Line
Goggin Substation
MM
30/50 MVA
Z = 8.35 %
M
M
M
M
M
2.5 MW DC/AC
2.5 MW DC/AC
5 MVA
Z = 5 %
6 transformer / inverters combinations total
0.5 MW DC/AC
2 MVAZ = 3 %
15 transformer / inverters / battery
combinations total
0.5 MW DC/AC
0.5 MW DC/AC
0.5 MW DC/AC
480 V
480 V 480 V
Saltair
138 kV
34.5 kV
F1
F2
F3
F4
F5
F6
2.5 MW DC/AC
2.5 MW DC/AC
5 MVAZ = 5 %
480 V 480 V
6 transformer / inverters combinations total
12.5 kV
T2T1

Figure 2: Simplified System One Line Diagram for TCS-27
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Transition Cluster Area 3 Page 8 March 31, 2021

5.2 Description of Interconnection Request – TCS-48
The Interconnection Customer has proposed to interconnect 200 MW of new generation to the
Transmission Provider’s Terminal substation located in Salt Lake County, Utah. The
Interconnection Request is proposed to consist of sixty-eight (68) Power Electronics PCSM
FP3510M3 US-UL battery storage inverters for a total output of 200 MW at the POI. The
requested commercial operation date is December 31, 2023. Figure 3 below, is a one-line diagram
that illustrates the interconnection of the proposed Generating Facility to the Transmission
Provider’s system.

Interconnection Customer will NOT operate this generator as a Qualified Facility as defined by
the Public Utility Regulatory Policies Act of 1978 (PURPA).

The Interconnection Request will be studied for Network Resource Interconnection Service
(“NRIS”).

The Transmission Provider has assigned the Project Cluster Number “TCS-48.”

M
Point of Interconnection
Terminal
Substation
– kVTransformer
Midvalley Change of ownership
4,850 ft
F6F5F4F3F2F1
141/188/236 MVAZ = 10.9 %
3.51 MVA DC/AC
3.51 MVAZ = 8.5 %
– Ba
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t
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r
y

/

I
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v
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r
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To
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t
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y

/

I
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– Ba
t
t
e
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y

/

I
n
v
e
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t
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– Ba
t
t
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y

/

I
n
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– Ba
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/

I
n
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M
Au
x
.

L
o
a
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345 kV
34.5 kV
TCS-48
Energy
Storage
Project M1
660 V

Figure 3: Simplified System One Line Diagram for TCS-48
Transition Cluster Study Report
Transition Cluster Area 3 Page 9 March 31, 2021

6.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS
6.1 Transmission System Requirements
The TCS-27 project will require construction to create a ring bus at the new Lee Creek
substation, which is currently under construction, with a planned in-service date of May 2021.
TCS-27 construction will include addition of a 138 kV bus, expansion of two bays, a new line
position with two new 138 kV circuit breakers and three switches.

The TCS-48 project will require expansion of the Terminal substation yard to the east with a new
345 kV bay and new line position with four switches and two circuit breakers. The north and
south buses will need to be extended to this new 345 kV bay.
6.2 Distribution System Requirements
No distribution system upgrades are required for the Interconnection Requests in this Cluster
Area.
6.3 Transmission Line Requirements
TCS-48
The Interconnection Customer shall construct the transmission tie line between the
Interconnection Customer’s collector substation and the Terminal substation. The
Interconnection Customer shall construct it’s last tie line structure to Transmission Provider
standards. The Interconnection Customer shall coil conductor, OPGW and/or shield wire, and
line hardware with sufficient quantities to allow the Transmission Provider to terminate on the
Emery substation deadend structure.
6.4 Existing Circuit Breaker Upgrades – Short Circuit
The TCS-27 project will have photovoltaic arrays fed through 24 – 2,500 kVA inverters connected
12 – 34.5 kV – 480 V 5 MVA transformers with 5 % impedance and batteries connected to 45 -
500 kW inverters fed through 15 – 2 MVA transformers with 3 % impedance. The combination
of the solar and batteries inverters is connected to the power network with a pair of 138 – 34.5 kV
30/50 MVA transformers with 8.35 % impedance.

The TCS-48 project is an energy storage facility with batteries connected to 68 – 3.51 MVA
inverters fed through 68 – 3.51 MVA 34.5 kV – 660 V transformers with 8.5 % impedance and
then connected to the power system with a 345 – 34.5 kV 141/188/236 MVA transformer with
10.9 % impedance.

The increase in the fault duty on the system as the result of the addition of the two generation
facilities TCS-27 and TCS-48 will not exceed interrupting rating of any of the existing equipment.
6.5 Protection Requirements
The TCS-27 project will be connected to the transmission network through Lee Creek substation.
The 138 kV bus at the substation will be expanded to form a ring bus with the addition of two 138
Transition Cluster Study Report
Transition Cluster Area 3 Page 10 March 31, 2021

kV breakers. The existing line relays for the Grow – Terminal and the Goggin lines will be
reconnected to include the two new breakers.

Due to the plan to locate the collector substation for this Project adjacent to Lee Creek substation
the two substations can share a common ground mat. This will permit the use of metallic control
cables between the substations. The line between Lee Creek substation and the Interconnection
Customer’s collector substation will be protected with a bus differential relay system. The bus
differential relays will be in Lee Creek substation. The Interconnection Customer will need to
provide the output from sets of current transformers from each of the transformer 138 kV breakers.
These currents will be fed into a set of bus differential relays. If a fault is detected both the 138
kV breakers in Lee Creek substation and the 138 kV breakers in the collector substation will be
tripped. The installation and maintenance of protective relays to detect faults in the Interconnection
Customer’s main power transformers and the 34.5 kV lines to the solar arrays from the collector
substation will be the responsibility of the Interconnection Customer.

In addition to the line protective relaying a relay used for under/over voltage and over/under
frequency protection of the system will be installed in Lee Creek substation. If the voltage,
magnitude or frequency, is outside of the normal operation range this relay will trip the 138 kV
breakers in the Interconnection Customer’s Collector substation.

For the TCS-48 project the 345 kV tie line will be protected with line current differential relay
systems. The 345 kV breakers at Terminal substation will be connected into the existing
redundant north and south bus differential relay systems. A relay panel with line current
differential relays will be installed at the TCS-48 collector substation. The panel will be owned
and maintained by the Transmission Provider. The line relays at Terminal substation and at the
collector substation will communicate over digital communication circuits. Redundant diverted
routed communication circuits will be required for the two relay systems. For a fault on the tie
line the two breakers at Terminal substation and breaker M1 at the collector substation will be
tripped.

There will be under and over voltage and frequency relay elements in the line relays for the tie
line in Terminal substation. If the voltage, magnitude or frequency is outside of the normal
operation range, these relay elements will trip the two 345 kV breakers at Terminal substation.
6.6 Data (RTU) Requirements
TCS-27
Data for the operation of the Transmission Provider’s system will be needed from Lost Creek
substation and the Interconnection Customer collector substation.

From the collector substation:
Analog Written to the RTU:
▪ Max Gen Limit MW Set Point
Analogs:
▪ Max Gen Limit MW Set Point Feed Back
▪ Potential Power MW
▪ Real power flowing through the #1 138 – 34.5 kV transformer
Transition Cluster Study Report
Transition Cluster Area 3 Page 11 March 31, 2021

▪ Reactive power flowing through the #1 138 – 34.5 kV transformer
▪ Real power flowing through the #2 138 – 34.5 kV transformer
▪ Reactive power flowing through the #2 138 – 34.5 kV transformer
▪ 34.5 kV Real power 52-F1
▪ 34.5 kV Reactive power 52-F1
▪ 34.5 kV Real power 52-F2
▪ 34.5 kV Reactive power 52-F2
▪ 34.5 kV Real power 52-F3
▪ 34.5 kV Reactive power 52-F3
▪ 34.5 kV Real power 52-F4
▪ 34.5 kV Reactive power 52-F4
▪ 34.5 kV Real power 52-F5
▪ 34.5 kV Reactive power 52-F5
▪ 34.5 kV Real power 52-F6
▪ 34.5 kV Reactive power 52-F6
▪ Global Horizontal Irradiance (GHI)
▪ Average Plant Atmospheric Pressure (Bar)
▪ Average Plant Temperature (Celsius)
Status:
▪ 138 kV transformer breaker 52-T1
▪ 138 kV transformer breaker 52-T2
▪ 34.5 kV breaker 52-F1
▪ 34.5 kV breaker 52-F2
▪ 34.5 kV breaker 52-F3
▪ 34.5 kV breaker 52-F4
▪ 34.5 kV breaker 52-F5
▪ 34.5 kV breaker 52-F6

From the POI substation:
Analogs:
▪ Net Generation MW
▪ Net Generator MVAR
▪ Interchange metering kWH

TCS-48
Data for the operation of the Transmission Provider’s system will be needed from Terminal
substation and the Interconnection Customer collector substation.

From the collector substation:
Analog Written to the RTU:
▪ Max Gen Limit MW Set Point
Analogs:
▪ Max Gen Limit MW Set Point Feed Back
▪ Potential Power MW
▪ A phase 345 kV voltage
▪ B phase 345 kV voltage
Transition Cluster Study Report
Transition Cluster Area 3 Page 12 March 31, 2021

▪ C phase 345 kV voltage
▪ 34.5 kV Real power 52-F1
▪ 34.5 kV Reactive power 52-F1
▪ 34.5 kV Real power 52-F2
▪ 34.5 kV Reactive power 52-F2
▪ 34.5 kV Real power 52-F3
▪ 34.5 kV Reactive power 52-F3
▪ 34.5 kV Real power 52-F4
▪ 34.5 kV Reactive power 52-F4
▪ 34.5 kV Real power 52-F5
▪ 34.5 kV Reactive power 52-F5
▪ 34.5 kV Real power 52-F6
▪ 34.5 kV Reactive power 52-F6
Status:
▪ 345 kV transformer breaker 52-M1
▪ 34.5 kV breaker 52-F1
▪ 34.5 kV breaker 52-F2
▪ 34.5 kV breaker 52-F3
▪ 34.5 kV breaker 52-F4
▪ 34.5 kV breaker 52-F5
▪ 34.5 kV breaker 52-F6
▪ Line relay alarm

From the POI substation:
Analogs:
▪ Net Generation MW
▪ Net Generator MVAR
▪ Interchange metering kWH
6.7 Substation Requirements
The following major equipment has been preliminarily identified for this Project and may change
during actual design:

TCS-27
The Lee Creek substation and Interconnection Customer collector substation will be adjacent to
each other and share a ground grid. The Interconnection Customer shall perform a CDEGS
grounding analysis of the collector substation location and provide the results to the Transmission
Provider.

Lee Creek Substation:
Lee Creek substation will be expanded to create a new line position and the addition of a 138 kV
bus.

(2) – 145KV, 2000A Breaker
(3) – 138 KV, 2000 AMP Horizontal Mount, Group Operated Switch
(1) – 138 KV, 2000 AMP, Vertical Mount, Group Operated Switch
Transition Cluster Study Report
Transition Cluster Area 3 Page 13 March 31, 2021

(1) – 138 KV, 2000 AMP, Vertical Mount, Group Operated Switch, w/ Motor Operator
(3) – 138kV Surge Arresters
(3) – CT/VT Metering Units

TCS-27 collector substation:
(1) – 14’ x 28’ Control House
(24) – CT/VT Metering Units

TCS-48
Terminal Substation:
Terminal substation will be expanded to create a new 345 kV bay and new line position with four
switches and two circuit breakers. The north and south buses will need to be extended to this new
345 kV bay.

(2) – 362KV, 3000A, Breaker
(5) – 345KV, 3000A, Horizontal Mount, Group Operated Switch
(1) – 345KV, 3000A, Horizontal Mount, Group Operated Switch, w/ Motor Operator
(3) – 345kV surge arresters
(1) – 480V – 120/240V pad mount station service transformer
(3) – CT/VT Metering Units

TCS-48 collector substation:
(1) – 12’ x 12’ Control House
(3) – CT/VT Metering Units
6.8 Communication Requirements
TCS-27
Because the Interconnection Customer collector substation will be constructed adjacent to the Lee
Creek substation the Interconnection Customer will bring all necessary data points to the Lee
Creek substation by hard wiring its source devices to a marshalling cabinet to be installed at the
Lee Creek substation fence by the Transmission Provider.

TCS-48
In order to meet line protection standards, the Transmission Provider will require redundant
communications between the Interconnection Customer’s collector substation and the Terminal
substation. For the first path the Interconnection Customer will install Transmission Provider
approved fiber optic cable on its transmission tie line. The fiber will be owned and maintain by
the Transmission Provider. The Interconnection Customer will leave sufficient quantities of
fiber optic cable at both ends of the tie line for the Transmission Provider to terminate the fiber
inside its control buildings at both sites. The second path is assumed to be microwave. The
Transmission Provider will install towers at both facilities.

These communications paths will also be utilized to provide the necessary data and metering
information from the Interconnections Customer’s collector substation to the Transmission
Provider’s communications network. The Transmission Provider will install metering and
communications equipment at the Interconnection Customer’s collector substation. The
Transition Cluster Study Report
Transition Cluster Area 3 Page 14 March 31, 2021

Interconnection Customer will hard wire all source devices to the Transmission Provider’s
communications equipment in its control building at the collector substation site in order to
provide the required data points.
6.9 Metering Requirements
TCS-27
Interchange Metering
The overall Project metering will be located at the POI at Lee Creek substation. This will require
one metering point. This metering will be rated for the total net generation of the Project.

The Transmission Provider will specify and order all interconnection revenue metering,
including the instrument transformers, meters, meter panel, junction box, and secondary
metering wire. The primary metering transformers will be combination 138kV CT/VT units with
extended range CTs for high-accuracy metering.

The metering design package will include two revenue quality meters with DNP real time digital
data terminated at a metering interposition block. One meter will be designated as primary
SCADA meter with DNP data delivered to the primary control center. A second meter will be
designated as backup SCADA meter with DNP data delivered to the alternate control center. The
metering data will include bidirectional KWH and KVARH revenue quantities. The meter data
will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps
data.

An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.

GSU Metering
Each of the Interconnection Customer’s GSU transformers will require metering, which will
require two metering points at 138kV. The metering will be located at the Interconnection
Customer’s collector substation, and each metering point will be rated per transformer size.

The Transmission Provider will specify and order all interconnection revenue metering,
including the instrument transformers, meters, meter panel, junction box, and secondary
metering wire. The primary metering transformers will be combination 138kV CT/VT units with
extended range CTs for high-accuracy metering.

The metering design package will include two revenue quality meters for each meter point with
DNP real time digital data terminated at a metering interposition block. One meter will be
designated as primary SCADA meter with DNP data delivered to the primary control center. A
second meter will be designated as backup SCADA meter with DNP data delivered to the
alternate control center. The metering data will include bidirectional KWH and KVARH revenue
quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase
voltage, and per-phase amps data.

An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.
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Transition Cluster Area 3 Page 15 March 31, 2021

Generator Metering
The solar generator and battery storage are to be separately metered. Specifically, the four
breakers for the solar generators, and the two breakers for the battery storage will be metered.
This will require six metering points. The metering will be located at the Interconnection
Customer’s collector substation and each metering point will be rated for its individual circuit on
the Project.

The Transmission Provider will specify and order all interconnection revenue metering,
including the instrument transformers, meters, meter panels, junction boxes, and secondary
metering wire. The primary metering transformers will be combination 34.5kV CT/VT units with
extended range CTs for high-accuracy metering.

The metering design package will include two revenue quality meters for each meter point with
DNP real time digital data terminated at a metering interposition block. One meter will be
designated as primary SCADA meter with DNP data delivered to the primary control center. A
second meter will be designated as backup SCADA meter with DNP data delivered to the
alternate control center. The metering data will include bidirectional KWH and KVARH revenue
quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase
voltage, and per-phase amps data.

An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.

Station Service
The Project is within the Transmission Provider’s service territory. Please note that prior to back
feed, Interconnection Customer must arrange transmission retail meter service for electricity
consumed by the Project that will be drawn from the transmission system when the Project is not
generating. Interconnection Customer must call the Help Desk at 1-800‐625‐6078 to arrange this
service. Approval for back feed is contingent upon obtaining station service.

TCS-48
Interchange Metering
The overall Project metering will be located at the POI at Terminal substation. This will require
one metering point. This metering will be rated for the total net generation of the Project.

The Transmission Provider will specify and order all interconnection revenue metering,
including the instrument transformers, meters, meter panel, junction box, and secondary
metering wire. The primary metering transformers will be combination 345kV CT/VT units with
extended range CTs for high-accuracy metering.

The metering design package will include two revenue quality meters with DNP real time digital
data terminated at a metering interposition block. One meter will be designated as primary
SCADA meter with DNP data delivered to the primary control center. A second meter will be
designated as backup SCADA meter with DNP data delivered to the alternate control center. The
metering data will include bidirectional KWH and KVARH revenue quantities. The meter data
Transition Cluster Study Report
Transition Cluster Area 3 Page 16 March 31, 2021

will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps
data.

An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.

Auxiliary Metering
The auxiliary load at the Project site will be metered. This will require one metering point at the
energy storage facility. This metering will be rated for the expected aux load of the Project.

The Transmission Provider will specify and order all interconnection revenue metering,
including the instrument transformers, meters, meter panel, junction box, and secondary
metering wire. The primary metering transformers will be combination 34.5kV CT/VT units with
extended range CTs for high-accuracy metering.

The metering design package will include two revenue quality meters with DNP real time digital
data terminated at a metering interposition block. One meter will be designated as primary
SCADA meter with DNP data delivered to the primary control center. A second meter will be
designated as backup SCADA meter with DNP data delivered to the alternate control center. The
metering data will include bidirectional KWH and KVARH revenue quantities. The meter data
will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps
data.

An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.

Station Service
The Project is within the Transmission Provider’s service territory. Please note that prior to back
feed, Interconnection Customer must arrange transmission retail meter service for electricity
consumed by the Project that will be drawn from the transmission system when the Project is not
discharging. Interconnection Customer must call the Help Desk at 1-800‐625‐6078 to arrange
this service. Approval for back feed is contingent upon obtaining station service.
7.0 CONTINGENT FACILITIES

Table 1. Contingent Facilities Table
Potential
Contingent
Facility
Description

Outage(s) Pre-CA3
Level Post-CA3
Level
% Change Contingent
Facility
(Yes/No)

Responsible
Entity

Planned
ISD
Capacitors at
Magna two
15 MVAr
each
Breaker
internal
fault at
Terminal
CB 109 or
open
Terminal-
0.8851 PU 0.8858 PU +0.07% No PAC 2022
Transition Cluster Study Report
Transition Cluster Area 3 Page 17 March 31, 2021

Potential
Contingent
Facility
Description

Outage(s) Pre-CA3
Level Post-CA3
Level
% Change Contingent
Facility
(Yes/No)

Responsible
Entity

Planned
ISD
Magna 138
kV line
(HS)
Path C
Improvement
Project
Bus fault at
Wheelon

115.0%

114.5%

-0.5%

No PAC 2023
Path C
Improvement
Project
Breaker
internal
fault Ben
Lomond
CB 204 or
CB 205
103.0% 102.8% -0.2% No PAC 2023

It was observed that a breaker failure at Terminal substation or opening of the Terminal-Magna
138 kV line during heavy loads will produce low voltage at Magna and Praxair substations, but an
existing capital project is already planned to mitigate this issue in 2022. This new project will
install two new 15 MVAr capacitors at Magna substation. The Contingent Facility analysis
confirmed that the generation additions in this Cluster Area did not exacerbate the voltage and
therefore the Magna capacitor project is not a Contingent Facility for the Interconnection Requests
in this Cluster Area.

Prior to the Path C Improvement project, the Wheelon substation bus outage produces an overload
on the Green Canyon-Franklin 138 kV line. Also prior to the Path C Improvement project an
internal fault of Ben Lomond CB 204 or CB 205 will overload the Ben Lomond 230/138 kV #2
transformer. Addition of the Interconnection Requests in this Cluster Area did not exacerbate the
overloads and therefore the Path C Improvement project is not a Contingent Facility.
8.0 COST ESTIMATE
The following estimate represents only scopes of work that will be performed by the Transmission
Provider. Costs for any work being performed by the Interconnection Customer and/or Affected
Systems are not included.
8.1 Interconnection Facilities
The following facilities are directly assigned to Interconnection Customer(s) using such
facilities. If multiple Interconnection Requests are utilizing the same Transmission Provider
Interconnection Facilities the costs shall be shared pursuant to Section 39.2.3 of Transmission
Provider’s OATT.

TCS-27
Collector substation $1,657,000
Control building, metering and communications equipment

Transition Cluster Study Report
Transition Cluster Area 3 Page 18 March 31, 2021

Lee Creek substation $351,000
Line termination and metering

Total: $2,008,000

TCS-48
TCS-48 Collector Substation $768,000
Control building, relays, metering, and communication equipment

Terminal substation $882,000
Line termination and metering

Total: $1,650,000
8.2 Station Equipment
The following are Network Upgrades which are allocated based on the number of Generating
Facilities interconnecting at an individual station on a per Interconnection Request basis.
Interconnection Requests utilizing the same Interconnection Facilities shall be consider one
request for this allocation.

TCS-27
Lost Creek Substation $1,453,000
New line position with two new 138 kV breakers in the ring bus

TCS-48
Terminal substation $5,124,000
Construct new 345 kV bay with two 345 kV breakers
8.3 Network Upgrades
The funding responsibility for Network Upgrades other than those identified in the previous
section shall be allocated based on the proportional capacity of each individual Generating
Facility.

None
8.4 Total Estimated Project Costs

TCS-27
Interconnection Facilities $2,008,000
Station Equipment $1,453,000
Network Upgrades $0

Total: $3,459,000
TCS-48
Interconnection Facilities $1,650,000
Station Equipment $5,124,000
Transition Cluster Study Report
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Network Upgrades $0

Total: $6,774,000
9.0 SCHEDULE
The Transmission Provider estimates it will require approximately 24 months to design, procure
and construct the facilities described in this report following the execution of Interconnection
Agreements. The schedule will be further developed and optimized during the Facilities Studies.
10.0 AFFECTED SYSTEMS
Transmission Provider has identified the following affected systems: None.

A copy of this report will be shared with each Affected System.
11.0 APPENDICES
Appendix 1: Cluster Area Power Flow and Stability Study Results
Appendix 2: Higher Priority Requests
Appendix 3: Property Requirements
Transition Cluster Study Report
Transition Cluster Area 3 Page 20 March 31, 2021

11.1 Appendix 1: Cluster Area Power Flow and Stability Study Results

The study was completed using a heavy summer load 2025 case and a light summer load 2025
case. Each case was studied considering prior generator interconnection queue projects with signed
interconnection agreements and prior queued and granted transmission service requests. Two
relevant capital improvement projects were considered in the study: 1) the addition of two 15
MVAr capacitor banks at Magna substation and 2) the Path C Improvement project. The Path C
project loops the Populus-Terminal 345 kV line in and out of Bridgerland substation and adds a
345/138 kV transformer at Bridgerland, it also will connect the same line in and out of Ben-
Lomond substation.

Existing generation in the study area was left at or very near maximum generation levels. These
cases were studied with a wide variety of outage contingencies and system performance was
monitored before and after each contingency.

The CA3 cluster was studied again as described above with the addition of the prior transmission
queued project Q2611 (Carbon Free - 600MW) due to its later transmission service request start
date in 2026.

Study results did not identify any system issues requiring additional network upgrades or
contingent projects. For the addition of TCS-27 and TCS-48, both requesting NRIS, the only
required improvements would be those described in section 6.0 “Site Specific Generator Facility
Requirements.”

Transition Cluster Study Report
Transition Cluster Area 3 Page 21 March 31, 2021

11.2 Appendix 2: Higher Priority Requests
All active higher priority Transmission Provider projects, and transmission service requests (TSR
and/or generator interconnection (GI) requests will be considered in this cluster area study and
are identified below. If any of these requests are withdrawn, the Transmission Provider reserves
the right to restudy this request, as the results and conclusions contained within this study could
significantly change.

Transmission/Generation Interconnection Queue Requests considered:

TSR Q2611 (600 MW)
TSR Q2417 (32 MW)
TSR Q2789 (75 MW)
TSR Q2790 (80 MW)
TSR Q2865 (70 MW)
TSR Q2882 (25 MW)

GI Q0524 (6 MW)
GI Q0754 (80 MW)
GI Q0799 (67 MW)
GI Q0846 (75 MW)
GI Q1003 (10 MW)

Transition Cluster Study Report
Transition Cluster Area 3 Page 22 March 31, 2021

11.3 Appendix 3: Property Requirements
Property Requirements for Point of Interconnection Substation
Requirements for rights of way easements
Rights of way easements will be acquired by the Interconnection Customer in the Transmission
Provider’s name for the construction, reconstruction, operation, maintenance, repair, replacement
and removal of Transmission Provider’s Interconnection Facilities that will be owned and
operated by PacifiCorp. Interconnection Customer will acquire all necessary permits for the
Project and will obtain rights of way easements for the Project on Transmission Provider’s
easement form.

Real Property Requirements for Point of Interconnection Substation
Real property for a POI substation will be acquired by an Interconnection Customer to
accommodate the Interconnection Customer’s Project. The real property must be acceptable to
Transmission Provider. Interconnection Customer will acquire fee ownership for interconnection
substation unless Transmission Provider determines that other than fee ownership is acceptable;
however, the form and instrument of such rights will be at Transmission Provider’s sole
discretion. Any land rights that Interconnection Customer is planning to retain as part of a fee
property conveyance will be identified in advance to Transmission Provider and are subject to
the Transmission Provider’s approval.

The Interconnection Customer must obtain all permits required by all relevant jurisdictions for
the planned use including but not limited to conditional use permits, Certificates of Public
Convenience and Necessity, California Environmental Quality Act, as well as all construction
permits for the Project.

If eligible, Interconnection Customer will not be reimbursed through network upgrades for more
than the market value of the property.

As a minimum, real property must be environmentally, physically, and operationally acceptable
to Transmission Provider. The real property shall be a permitted or able to be permitted use in all
zoning districts. The Interconnection Customer shall provide Transmission Provider with a title
report and shall transfer property without any material defects of title or other encumbrances that
are not acceptable to Transmission Provider. Property lines shall be surveyed and show all
encumbrances, encroachments, and roads.

Examples of potentially unacceptable environmental, physical, or operational conditions could
include but are not limited to:

1. Environmental: known contamination of site; evidence of environmental
contamination by any dangerous, hazardous or toxic materials as defined by any
governmental agency; violation of building, health, safety, environmental, fire,
land use, zoning or other such regulation; violation of ordinances or statutes of
any governmental entities having jurisdiction over the property; underground or
above ground storage tanks in area; known remediation sites on property; ongoing
mitigation activities or monitoring activities; asbestos; lead-based paint, etc. A
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phase I environmental study is required for land being acquired in fee by the
Transmission Provider unless waived by Transmission Provider.

2. Physical: inadequate site drainage; proximity to flood zone; erosion issues;
wetland overlays; threatened and endangered species; archeological or culturally
sensitive areas; inadequate sub-surface elements, etc. Transmission Provider may
require Interconnection Customer to procure various studies and surveys as
determined necessary by Transmission Provider.

Operational: inadequate access for Transmission Provider’s equipment and vehicles; existing
structures on land that require removal prior to building of substation; ongoing maintenance for
landscaping or extensive landscape requirements; ongoing homeowner's or other requirements or
restrictions (e.g., Covenants, Codes and Restrictions, deed restrictions, etc.) on property which
are not acceptable to the Transmission Provider.

Generation Interconnection Transition Cluster

Transition Cluster Study Report

Cluster Area 7

March 31, 2021

Transition Cluster Study Report
Transition Cluster Area 7 Page i March 31, 2021

TABLE OF CONTENTS

1.0 SCOPE OF THE STUDY ................................................................................................................. 1
2.0 STUDY ASSUMPTIONS ................................................................................................................. 1
3.0 GENERATING FACILITY REQUIREMENTS .............................................................................. 3
3.1 Transmission Voltage Interconnection Requests .............................................................................. 3
3.2 Distribution Voltage Interconnection Requests ................................................................................ 6
4.0 CLUSTER AREA DEFINITIONS ................................................................................................... 6
5.0 CLUSTER AREA 7 .......................................................................................................................... 6
5.1 Description of Interconnection Request(s) – TCS-55 ....................................................................... 7
6.0 SITE SPECIFIC GENERATING FACILITY REQUIREMENTS ................................................... 7
7.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS ........................................................ 8
7.1 Transmission System Requirements ................................................................................................. 8
7.2 Distribution System Requirements ................................................................................................... 9
7.3 Transmission Line Requirements ...................................................................................................... 9
7.4 Existing Circuit Breaker Upgrades – Short Circuit ......................................................................... 10
7.5 Protection Requirements ................................................................................................................. 10
7.6 Data (RTU) Requirements .............................................................................................................. 11
7.7 Substation Requirements ................................................................................................................. 11
7.8 Communication Requirements ........................................................................................................ 13
7.9 Metering Requirements ................................................................................................................... 13
8.0 CONTINGENT FACILITIES ......................................................................................................... 14
9.0 COST ESTIMATE .......................................................................................................................... 15
10.0 SCHEDULE .................................................................................................................................... 15
11.0 AFFECTED SYSTEMS ................................................................................................................. 15
12.0 APPENDICES ................................................................................................................................ 15
12.1 Appendix 1: Cluster Area Power Flow and Stability Study Results ............................................... 16
12.2 Appendix 2: Higher Priority Requests ............................................................................................ 17
12.3 Appendix 3: Property Requirements ............................................................................................... 18

Transition Cluster Study Report
Transition Cluster Area 7 Page 1 March 31, 2021

1.0 SCOPE OF THE STUDY
Cluster Are 7 (CA7) generally consists of the Dalreed/Arlington, Oregon area and consists of the
following Interconnection Requests: TCS-55

Consistent with Attachment W, Section 3.4.2 and Section 51.4 of PacifiCorp’s (“Transmission
Provider”) Open Access Transmission Tariff (“OATT”), this interconnection Transition Cluster
Study (“Cluster Study”) evaluated the impact of the proposed interconnections on the reliability
of the Transmission System. The Cluster Study considered the Base Case as well as all generating
facilities (and with respect to (iii) below, any identified Network Upgrades associated with such
higher queued interconnection) that, on the date the Cluster Request Window closes:

(i) are existing and directly interconnected to the Transmission System;
(ii) are existing and interconnected to Affected Systems and may have an impact on the
Interconnection Request;
(iii) have a pending higher queued or higher clustered interconnection request to interconnect
to the transmission system; and
(iv) have executed an LGIA or requested that an unexecuted LGIA be filed with FERC.

The Cluster Study consisted of power flow, stability, and short circuit analyses.

This Cluster Study report provides the following information:
• identification of any circuit breaker short circuit capability limits exceeded as a result of the
interconnection;
• identification of any thermal overload or voltage limit violations resulting from the
interconnection;
• identification of any instability or inadequately damped response to system disturbances
resulting from the interconnection and
• description and non-binding, good faith estimated cost of facilities required to interconnect the
Generating Facilities to the Transmission System and to address the identified short circuit,
instability, and power flow issues.
2.0 STUDY ASSUMPTIONS
• All active higher priority transmission service and/or generator interconnection requests
that were considered in this study are listed in Appendix 2. If any of these requests are
withdrawn, the Transmission Provider reserves the right to restudy this request, and the
results and conclusions could significantly change.
• For study purposes there are two separate queues:
o Transmission Service Queue: to the extent practical, all network upgrades that are
required to accommodate active transmission service requests were modeled in this
study.
o Generation Interconnection Queue: Interconnection Facilities and network
upgrades associated with higher queued or higher clustered interconnection
requests were modeled in this study.
• The Interconnection Customers’ request for energy or network resource interconnection
Transition Cluster Study Report
Transition Cluster Area 7 Page 2 March 31, 2021

service in and of itself does not request or convey transmission service. Only a Network
Customer may make a request to designate a generating resource as a Network Resource.
Because the queue of higher priority transmission service requests may be different when
a Network Customer requests network resource designation for this Generating Facility,
the available capacity or transmission modifications, if any, necessary to provide Network
Integration Transmission Service may be significantly different. Therefore,
Interconnection Customers should regard the results of this study as informational rather
than final.
• Under normal conditions, the Transmission Provider does not dispatch or otherwise
directly control or regulate the output of generating facilities. Therefore, the need for
transmission modifications, if any, that may be required to provide Network Resource
Interconnection Service will be evaluated on the basis of 100 percent deliverability (i.e.,
this study did not model displacement of other resources in the same area).
• This study assumed the Projects will be integrated into the Transmission Provider’s system
at agreed upon and/or proposed Points of Interconnection (“POI” or “POIs”).
• If Interconnection Customers proceed through the interconnection process, they will be
required to construct and own any facilities required between the Point of Change of
Ownership and the Project unless specifically identified by the Transmission Provider.
• Line reconductor or fiber underbuild required on existing poles were assumed to follow the
most direct path on the Transmission Provider’s system. If during detailed design the path
must be modified it may result in additional cost and timing delays for the Interconnection
Customer’s Project.
• Generator tripping may be required for certain outages.
• All facilities will meet or exceed the minimum Western Electricity Coordinating Council
(“WECC”), North American Electric Reliability Corporation (“NERC”), and the
Transmission Provider’s performance and design standards.
• The Dalreed Sub 4K16 Willow Cove Feeder has SCADA metering and shows 0.0 kW
minimum daytime load at times during the year. Maximum load on 4K16 does not exceed
20 MW under any loading conditions throughout the year, thus backfeed onto the 230 kV
transmission bus is likely under all configurations, with backfeed onto Bonneville Power
Administration’s (“BPA”) transmission system likely under all configurations outside of
the summer months.
• The Generator Facility is expected to operate during daylight hours every day 7 days per
week 12 months per year.
• The Generator Facility is expected to operate in constant power factor mode with a unity
power factor setting unless otherwise requested by the Transmission Provider. The study
was conducted assuming the generation stayed within the 0.95 +/- power factor range.
• The Transmission Provider assumes the Interconnection Customer’s generating facility
will interconnect at/near existing facility point 01103023.0060100 located north of Dalreed
substation at approximate coordinates of 45.764655°N, 119.999374°W.
• This report is based on information available at the time of the study. It is the
Interconnection Customer’s responsibility to check the Transmission Provider’s web site
regularly for Transmission System updates at https://www.oasis.oati.com/ppw
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Transition Cluster Area 7 Page 3 March 31, 2021

3.0 GENERATING FACILITY REQUIREMENTS
The following requirements are applicable to all Interconnection Requests. The Transmission
Provider will identify any site-specific generating facility requirements in addition to the following
in this report and in facilities studies. Certain Interconnection Requests requesting service at a
voltage level traditionally defined as distribution may be subject to the transmission
interconnection request requirements listed below should the Transmission Provider make that
determination.
3.1 Transmission Voltage Interconnection Requests
All interconnecting synchronous and non-synchronous generators are required to design their
Generating Facilities with reactive power capabilities necessary to operate within the full
power factor range of 0.95 leading to 0.95 lagging. This power factor range shall be dynamic
and can be met using a combination of the inherent dynamic reactive power capability of the
generator or inverter, dynamic reactive power devices and static reactive power devices to
make up for losses.

For synchronous generators, the power factor requirement is to be measured at the POI. For
non-synchronous generators, the power factor requirement is to be measured at the high-side
of the generator substation.

A Generating Facility must provide dynamic reactive power to the system in support of both
voltage scheduling and contingency events that require transient voltage support, and must be
able to provide reactive capability over the full range of real power output.

If a Generating Facility is not capable of providing positive reactive support (i.e., supplying
reactive power to the system) immediately following the removal of a fault or other transient
low voltage perturbations, the facility must be required to add dynamic voltage support
equipment. These additional dynamic reactive devices shall have correct protection settings
such that the devices will remain on line and active during and immediately following a fault
event.

Generators shall be equipped with automatic voltage-control equipment and normally operated
with the voltage regulation control mode enabled unless written authorization (or directive)
from the Transmission Provider is given to operate in another control mode (e.g. constant
power factor control). The control mode of generating units shall be accurately represented in
operating studies. The generators shall be capable of operating continuously at their maximum
power output at its rated field current within +/- 5% of its rated terminal voltage.

All generators are required to ensure the primary frequency capability of their facility by
installing, maintaining, and operating a functioning governor or equivalent controls as
indicated in FERC Order 842.

As required by NERC standard VAR-001-4.2, the Transmission Provider will provide a
voltage schedule for the POI. In general, Generating Facilities should be operated so as to
maintain the voltage at the POI, typically between 1.00 per unit to 1.04 per unit, or other
designated point as deemed appropriated by Transmission Provider. The Transmission
Transition Cluster Study Report
Transition Cluster Area 7 Page 4 March 31, 2021

Provider may also specify a voltage and/or reactive power bandwidth as needed to coordinate
with upstream voltage control devices such as on-load tap changers. At the Transmission
Provider’s discretion, these values might be adjusted depending on operating conditions.

Generating Facilities capable of operating with a voltage droop are required to do so. Voltage
droop control enables proportionate reactive power sharing among Generating Facilities.
Studies will be required to coordinate voltage droop settings if there are other facilities in the
area. It will be the Interconnection Customer’s responsibility to ensure that a voltage
coordination study is performed, in coordination with Transmission Provider, and
implemented with appropriate coordination settings prior to unit testing.

For areas with multiple generating facilities, additional studies may be required to determine
whether or not critical interactions, including but not limited to control systems, exist. These
studies, to be coordinated with Transmission Provider, will be the responsibility of the
Interconnection Customer. If the need for a master controller is identified, the cost and all
related installation requirements will be the responsibility of the Interconnection Customer.
Participation by the generation facility in subsequent interaction/coordination studies will be
required pre- and post-commercial operation in order ensure system reliability.

Interconnection Requests that are 75 MVA or larger may be required to facilitate collection
and validation of accurate modeling data to meet NERC modeling standards. The Transmission
Provider, in its roles as the Planning Coordinator, requires Phasor Measurement Units (PMUs)
at all new Generating Facilities with an individual or aggregate nameplate capacity of 75 MVA
or greater. In addition to owning and maintaining the PMU, the Generating Facility will be
responsible for collecting, storing (for a minimum of 90 days) and retrieving data as requested
by the Planning Coordinator. Data must be stored for a minimum of 90 days. Data must be
collected and be able to stream to Planning Coordinator for each of the Generating Facility’s
step-up transformers measured on the low side of the GSU at a sample rate of at least 60
samples per second and synchronized within +/- 2 milliseconds of the Coordinated Universal
Time (UTC). Initially, the following data must be collected:
• Three phase voltage and voltage angle (analog)
• Three phase current (analog)
Data requirements are subject to change as deemed necessary to comply with local and federal
regulations.

All generators must meet the Federal Energy Regulatory Commission (FERC), North
American Electric Reliability Corporation (NERC) and WECC low voltage ride-through
requirements as specified in the interconnection agreement. Inverters must be designed to stay
connected to the grid in the case of severe faults and may not momentarily cease output within
the no-trip area of the voltage curves. Figure 1 illustrates the voltage ride-through capability
as per NERC PRC-024. Importantly, inverters should be designed such that a trip outside of
the curves is a “may-trip” area (if needed to protect equipment) not a “must-trip”
area. Inverters that momentarily cease active power output for these voltage excursions should
be configured to restore output to pre-disturbance levels in no greater than five seconds,
provided the inverter is capable of these changes. Generators must provide test results to the
Transition Cluster Study Report
Transition Cluster Area 7 Page 5 March 31, 2021

Transmission Provider verifying that the inverters for this Project have been programmed to
meet all PRC-024 requirements rather than manufacturer IEEE distribution standards.

Figure 1 – Voltage Ride-Through Curve

As the Transmission Provider cannot submit a user written model to WECC for inclusion in
base cases, a standard model from the WECC Approved Dynamic Model Library is required
180 days prior to trial operation. The list of approved generator models is continually updated
and is available on the http://www.WECC.biz website.

Interconnection Customer with an Interconnection Request for a Generating Facility that is
both 75 MVA or larger as well as being interconnected at a voltage higher than 100 kV shall
register with NERC as the Generator Owner (“GO”) and Generator Operator (“GOP”) for the
Large Generating Facility and provide the Transmission Provider documentation
demonstrating registration in order to be approved for Commercial Operation. This registration
must be maintained throughout the lifetime of the Interconnection Agreement.

Interconnection Customers are responsible for the protection of transmission lines between the
Generating Facility and the POI substation. For Interconnection Requests that are smaller than
75 MVA or are interconnected at a voltage less than 100 kV which have a tie line that is longer
than 1,000 feet the Interconnection Customer shall construct and own a tie-line substation to
be located at the change of ownership (separate fenced facility adjacent to the Transmission
Provider’s POI substation). The tie line substation shall include an Interconnection Customer
owned protective device and associated transmission line relaying/communications. The
ground grids of the Transmission Provider’s POI substation and the Interconnection
Customer’s tie-line substation will be connected to support the use of a bus differential
protection scheme which will protect the overhead bus connection between the two facilities.
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Transition Cluster Area 7 Page 6 March 31, 2021

3.2 Distribution Voltage Interconnection Requests
The Generation Facility and Interconnection Equipment owned by the Interconnection
Customer are required to operate under constant power factor mode with a unity power factor
setting unless specifically requested otherwise by the Transmission Provider. The Generation
Facility is expressly forbidden from actively participating in voltage regulation of the Public
Utilities system without written request or authorization from the Transmission Provider. The
Generating Facility shall have sufficient reactive capacity to enable the delivery of 100 percent
of the plant output to the POI at unity power factor measured at 1.0 per unit voltage under
steady state conditions.

Generators shall be capable of operating under Voltage-reactive power mode, Active power-
reactive power mode, and Constant reactive power mode as per IEEE Std. 1547-2018. This
project shall be capable of activating each of these modes one at a time. The Transmission
Provider reserves the right to specify any mode and settings within the limits of IEEE Std 1547-
2018 needed before or after the Generation Facility enters service. The Interconnection
Customer shall be responsible for implementing settings modifications and mode selections as
requested by the Transmission Provider within an acceptable timeframe. The reactive
compensation must be designed such that the discreet switching of the reactive device (if
required by the Interconnection Customer) does not cause step voltage changes greater than
+/-3% on the Transmission Provider’s system. In all cases the minimum power quality
requirements in PacifiCorp’s Engineering Handbook section 1C shall be met and are available
at https://www.pacificpower.net/about/power-quality-standards.html. Requirements specified
in the System Impact Study that exceed requirements in the Engineering Handbook section 1C
power quality standards shall apply.

All generators must meet applicable WECC low voltage ride-through requirements as specified
in the interconnection agreement.

As per NERC standard VAR-001-1, the Transmission Provider is required to specify voltage
or reactive power schedule at the POI. Under normal conditions, the Transmission Provider’s
system should not supply reactive power to the Generating Facility.
4.0 CLUSTER AREA DEFINITIONS
The Transmission Provider performed the Transition Cluster Study based on geographically and/or
electrically relevant areas on the Transmission Provider’s Transmission System known as Cluster
Areas. The Transmission Provider has determined that the Interconnection Requests discussed in
Section 5.0 are located in a geographically and/or electrically relevant area on Transmission
Provider’s Transmission System, and thus, were assigned Cluster Area 7 in the Transition Cluster
Study process.
5.0 CLUSTER AREA 7
Cluster Are 7 (CA7) generally consists of the Dalreed/Arlington, Oregon area of the
Transmission Provider’s system. This area is an isolated load pocket.
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5.1 Description of Interconnection Request(s) – TCS-55
The Interconnection Customer has proposed to interconnect 20 megawatts (“MW”) of new
generation to PacifiCorp’s (“Transmission Provider”) distribution circuit 4K16 out of Dalreed
substation located in Gilliam County, Oregon. The Interconnection Request is proposed to
consist of seven (7) 3,550 KVA Power Electronics FS3430 solar inverters for a total output of
20 MW at the POI. The requested commercial operation date is June 1, 2023. Figure 2 shows
a simplified one-line diagram that illustrates the interconnection of the proposed Generating
Facility to the Transmission Provider’s system.
Interconnection Customer will operate this generator as a Qualified Facility as defined by the
Transmission Provider Regulatory Policies Act of 1978 (PURPA).

The Interconnection Request will be studied for Network Resource Interconnection Service
(“NRIS”).

The Transmission Provider has assigned the Project Cluster Number “TCS-55”
6.0 SITE SPECIFIC GENERATING FACILITY REQUIREMENTS
In addition to the requirements described above the Interconnection Customer’s Generating
Facility must also comply with the following:

The Interconnection Customer’s proposed step-up transformers are ungrounded-wye (645 V) –
grounded-wye (34.5 kV). These transformers alone do not comply with the standards of the
Transmission Provider. In order to meet the requirements of the effectively grounded 34.5 kV
system, the Interconnection Customer must install a grounding transformer at the 34.5 kV location
indicated in Figure 2. The grounding transformer could be a grounded-wye/delta transformer or a
zig-zag transformer with 20 ohms impedance (at 34.5 kV) and solidly grounded neutral. The
Interconnection Customer will be responsible for the detailed specification of such a grounding
transformer following the current American Standards.

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Transition Cluster Area 7 Page 8 March 31, 2021

4K16
R
DALREED
SUBSTATION
Change of Ownership
Point of
Interconnection
Optical Fiber
Cable
~0.1 mile
TOWILLOW
COVESUBSTATION
New
Facilities
34.5kV
Meter
M
R
TCS-55 – 20 MW- SEVEN (7) IDENTICAL GROUPS
- TRANSFORMERS ARE:
34500-645 V, GY-Y, 3550 kVA, Z=6%
34.5kV
GROUNDING
TRANSFORMER
TBD
XFMR3
XFMR2
XFMR1
TO
BOARDMAN(PGE)
TOJONES
CANYON
PV ARRAYPV ARRAY PV ARRAY PV ARRAY PV ARRAYPV ARRAYPV ARRAY
XFMR4
52
PTs and CTs owned by
Transmission Provider
230kV
TO
MORROW
FLAT
PST
WINE
COUNTRY
SUBSTATION
~50 mi
(FUT)
TO BPA 230kV YARD
XFMR1
115 kV
230 kV
Meter
M
N. O.
Figure 2: System Simplified one-line diagram
7.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS
7.1 Transmission System Requirements
Except the 230 kV bus within Dalreed substation, the transmission system serving Dalreed
substation is owned and operated by BPA. While no steady-state power flow deficiencies were
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Transition Cluster Area 7 Page 9 March 31, 2021

noted in this study, BPA has been identified as an Affected System and is responsible for
studying and identifying any impacts to their transmission system.

As a Qualifying Facility, TCS-55 must be used to serve network load. The Dalreed/Arlington
area is non-contiguous, both within the local system and with other portions of the
Transmission Provider’s Transmission System. For a significant portion of the year, loads in
the Dalreed area are less than the sum of all existing and proposed network resources, with up
to 10 MW of existing network resources already flowing onto BPA’s 230 kV transmission
system. The addition of the TCS-55 generation facility will result in a direct increase of this
flow onto the BPA 230 kV system by 20 MW. Therefore, the Dalreed area is considered
generation surplus prior to the interconnection of TCS-55, and the output of TCS-55 must be
transmitted to another area of the Transmission Provider’s Transmission System that is not
generation surplus. The Yakima, Washington area is the nearest load surplus pocket. The
Transmission Provider does not have an existing Transmission System between the
Dalreed/Arlington and Yakima areas therefore new transmission construction will be required.
In order to tie these two areas together the Transmission Provider will construct a new,
approximately 50 mile 230 kV transmission line from Dalreed substation to the Transmission
Provider’s Wine Country substation. A phase shifting transformer will be required to direct
power flow from Dalreed toward Wine Country substation, and expansions of the 230 kV buses
at both Wine Country and Dalreed substations would be required to accommodate the
additional 230 kV line positions at each substation.
7.2 Distribution System Requirements
From the POI north of Dalreed substation at the pole with facility point 060100 the
Transmission Provider will design, procure, and install a 477AAC 34.5 kV primary and 4/0
AAC neutral conductor line extension to the Point of Ownership Change (“POC”). One pole
will hold a Transmission Provider owned and operated gang switch with the next structure
being owned and installed by the Interconnection Customer where the primary metering
transformers will be installed. Conductor from the gang operated switch pole to the first
Interconnection Customer structure will be installed by the Transmission Provider, the
termination of this conductor at the Interconnection Customer’s structure will be the POC.
These Transmission Provider facilities will require Right of Ways obtained by the
Interconnection Customer as required in Appendix 3.
7.3 Transmission Line Requirements
A new 230 kV transmission line will be constructed from Dalreed substation to Wine Country
substation near Yakima, Washington. The line is estimated at 50 miles in length but could
significantly change during the line routing process. The line route will also require a new
crossing of the Columbia River which in this vicinity will require a long span of high tension
type conductor supported on steel lattice towers. The line route is assumed to be 40 miles of
horizontal configured line supported on two and three pole wood structures with twelve
structures per mile and an additional 10 miles of delta configured line supported on a
combination of wood and steel single pole structures with roughly 18 structure per mile.
Minimum conductor size will be a single 954 kcmil ACSR unless further study identifies a
larger conductor size being required.
Transition Cluster Study Report
Transition Cluster Area 7 Page 10 March 31, 2021

7.4 Existing Circuit Breaker Upgrades – Short Circuit
The addition of the TCS-55 generation facility with seven (7) 3.55 MVA, 34.5kV-645V, Z=6%
transformers, including a 20 ohms grounding transformer as shown in Figure 2, will cause an
increase in the system’s fault duty which will not violate the interrupting capacity of any of the
existing interrupting equipment of Dalreed or Wine Country substations.
7.5 Protection Requirements
Dalreed 230-34.5kV Substation
Any fault in the 4K16 34.5kV line will be cleared by tripping CB 4K16 at Dalreed substation
and the circuit breaker (or recloser) at the TCS-55 Generating Facility. Faults close to Dalreed
and TCS-55 will have to be cleared using high-speed relaying. The 4K16 line load during
daytime can be lower than the generated power output of TCS-55; therefore, anytime CB 4K16
is open, an instantaneous transfer trip to the generating facility will be sent through the
multifunction digital relay associated with CB 4K16 at Dalreed. This relay will be set to issue
fast automatic reclosing after a fault clearing with the provision to delay the reclosing until the
Generating Facility is disconnected by monitoring the line voltage using a line potential
transformer to be installed for this project (dead-line checking).

There are other generators connected to the 34.5kV lines of Dalreed substation. If the 230 kV
connection of Dalreed to the system is lost, the total load can be lower than the total day-time
generation; therefore, if line relays (11A and 11B) at Dalreed detect a fault in the 230 kV lines,
they must issue an automatic transfer trip to TCS-55 through the multifunction relay associated
with CB 4K16. In the same way, direct transfer trip to TCS-55 must be issued when transformer
#3 and/or #4 are taken out of service or if the partial bus differential of the 34.5kV bus operates.

TCS-55 Site
The multifunction digital relay associated with the TCS-55 automatic disconnecting device
(circuit breaker or recloser), must have:

• Ability to receive transfer trip from Dalreed substation using Mirrored Bits
communication protocol and send information to the relay at Dalreed to indicate the
status of the disconnecting device.
• Directional overcurrent relay elements to detect faults in the 4K16 34.5kV line.
• Directional overcurrent relay elements to detect faults in the Generating Facility.
• Monitor the voltage and disconnect the plant in case the voltage and/or frequency fall
out of the Transmission Provider’s standard tolerable limits.

Dalreed 230 kV Substation
The 230 kV lines to Morrow Flats (BPA), Jones Canyon (BPA) and Wine Country (PacifiCorp,
proposed) will have permissive overreaching transfer trip scheme (POTT) using distance relay
elements; therefore, communications between Dalreed and those three substations will be
needed. The new 230 kV Phase Shifting Transformer (PST) will have Transmission Provider
standard redundant differential and overcurrent protection. Due to the lack of unused available
current transformers on the 230kV side of the transformers, the 230kV buses of the existing
substation will be protected using a Transmission Provider standard redundant low impedance
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Transition Cluster Area 7 Page 11 March 31, 2021

bus differential scheme. For the same reason, a stand-alone current transformer with three cores
will be needed at the connection to the existing line to Portland General Electric plant.

Wine Country 230 kV Substation
Permissive overreach transfer trip protection will be installed for the new transmission line to
Dalreed. The Transmission Provider will have to install the communications equipment and
the line relay panels needed to implement the POTT protection scheme. Dual bus differentials
for the interconnection with the BPA 230kV yard and the 230-115kV transformer.
7.6 Data (RTU) Requirements
TCS-55 Site
The following data associated with the TCS-55 Generating Facility will be monitored by the
Transmission Provider EMS by installing a SEL RTAC/Axion RTU at the collector site and
from PAC meters. Meters will be direct connected to EMS.

Analogs from PAC Meters:
▪ Net Generation real power MW
▪ Net Generator reactive power MVAR
▪ Energy Register KWH
▪ A phase 12.5 kV voltage
▪ B phase 12.5 kV voltage
▪ C phase 12.5 kV voltage

Analogs from Customer:
▪ Global Horizontal Irradiance (GHI)
▪ Average Plant Atmospheric Pressure (Bar)
▪ Average Plant Temperature (Celsius)
▪ Max Generator Limit MW (set point control)
▪ Potential Power MW

Status from Customer:
▪ 34.5 kV circuit recloser
▪ Recloser relay failure alarm

Dalreed 230kV Substation
Install an RTU in the new control house to bring in all the necessary points associated with the
new 230kV yard station equipment, relay equipment and communication equipment.

Wine Country Substation
The existing substation GE D20 RTU will require the addition of control boards to
accommodate the circuit breaker additions at the substation. Spare points are available in the
existing RTU to accommodate what is needed for status and analog points associated with the
substation additions.
7.7 Substation Requirements
TCS-55 Site
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Transition Cluster Area 7 Page 12 March 31, 2021

At the Interconnection Customer site, the Interconnection Customer will provide a separate
graded, grounded and fenced area along the perimeter of the Interconnection Customer’s
Generating Facility for the Transmission Provider to install a control house for any required
metering and communication equipment. This area will share a fence and ground grid with
the Generating Facility and have separate, unencumbered access for the Transmission
Provider. The Interconnection Customer shall perform and provide a CDEGS grounding
analysis. AC station service will be supplied by the Customer. DC power for the control
house will be supplied by the Customer. Three (3), 34.5 kV combined CT/VT metering
instrument transformers will be installed. A gang switch will be required on each side of the
metering instrument transformer. The switch on the transmission provider side will be
supplied and owned by Transmission Provider. The switch on the generation side of the
VT/CT structure will be supplied and owned by the customer but operated by Transmission
Provider.

Dalreed 34.5 kV Substation
Install a single-phase potential transformer on the line side of the 4K16 feeder. This will be
used to implement the dead-line checking feature in the feeder relay reclosing function.
Setting changes on the Load Tap Changer (LTC) controls for bank #3 and bank #4 will be
required to account for regulating voltage during periods of reverse power.

Dalreed 230 kV Substation
A yard expansion to the south portion of the Dalreed substation yard is required for a new
transmission line from Dalreed substation to Wine Country substation. The yard expansion
will consist of rebuilding the high side of the substation to a breaker and a half layout and
adding a phase shifting transformer. There will be seven 230 kV breakers, three line
switches, three bus/transformer switches and 14 breaker switches. The three line switches
will have motor operators. Each of the lines will require three CCVTs, the two buses will
each require a CCVT, and the phase shifting transformer will need one CCVT on each side.
Six lighting arresters will be installed (Three at each line entrance). A new control house will
be needed to accommodate the new panels that will be needed for the yard expansion. A third
source (distribution feeder) is required for the station service. Three stand-alone CTs, with
three cores, will be installed at the Boardman line. A CDEGS study will be needed for the
substation expansion. The equipment identified may change during the detailed design.

Wine Country 230 kV Substation
A yard expansion to the east of the 115 kV yard at Wine Country substation is required for a
new transmission line from Dalreed substation to Wine Country substation. The yard
expansion will consist of adding a 230 kV ring bus with three breakers to add a line position
for the new Dalreed-Wine Country 230 kV line. There will be eight breaker switches, one
meter disconnect switch, and three line switches installed. The three line switches will have
motor operators. Three 230 kV combined CT/VT metering instrument transformers will be
installed. A gang switch will be required on each side of the metering instrument transformer.
Nine lightning arresters will be installed, three at each line entrance. Four CCVTs will be
installed (one for the transformer and three for the line). A CDEGS study will be needed for
the substation expansion. The equipment identified may change during the detailed design.
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Transition Cluster Area 7 Page 13 March 31, 2021

7.8 Communication Requirements
A 48-fiber, single-mode, ADSS cable will be installed, either underbuilt, or in trench,
between the Interconnection Customer Generation Facility and Dalreed substation for
protective relaying and data monitoring. It will be terminated in patch panels at both ends.
SEL and RLH fiber optic transceivers will be installed at both ends. At the Interconnection
Customer site the equipment will be placed in a pole-mounted cabinet with a power supply
and batteries. At the Dalreed end, the equipment will be rack-mounted in the control house.
Fiber optic jumpers will be installed between the patch panels and the transceivers. Data
circuits from the Interconnection Customer facility will be routed on existing
communications systems to control centers, or to the RTU at Dalreed.

For protective relaying between Dalreed and Jones Canyon, Morrow Flats, and Wine
Country, circuits will be routed on existing microwave radios from Dalreed to Kennewick
Communications Site. At Kennewick, the circuits will cross-connect into BPA’s
communication system which will deliver the circuits to the various sites. An agreement
with BPA will be required for this. Loop channel banks will be installed at Dalreed and
Wine Country with C37.94 cards. Fiber optic jumpers will be installed between the C37.94
cards and the relays’ fiber optic transceivers. BPA will install C37.94 channel cards in their
channel banks at Jones Canyon and Morrow Flats, and install fibers to the relays’ fiber optic
transceivers.
7.9 Metering Requirements
Transmission Metering
The new transmission line from Dalreed to Wine Country substation will require metering at
Wine County because there will be a new 230kV connection between PacifiCorp and BPA at
Wine County Substation. Exact parameters of this requirement are subject to future
agreements between PacifiCorp and BPA, but here it is assumed that PacifiCorp will own the
metering.

The metering will be located at Wine County substation on the 230kV connection between
BPA and PacifiCorp. The Transmission Provider will specify and order all interconnection
revenue metering, including the instrument transformers, meters, meter panel, junction box,
and secondary metering wire. The primary metering transformers will be combination 230kV
CT/VT units.
The metering design package will include two revenue quality meters with DNP real time
digital data terminated at a metering interposition block. One meter will be designated as
primary SCADA meter with DNP data delivered to the primary control center. A second meter
will be designated as backup SCADA meter with DNP data delivered to the alternate control
center. The metering data will include bidirectional KWH and KVARH revenue quantities.
The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage,
and per-phase amps data.
An Ethernet connection is required for retail sales and generation accounting via the MV-
90 translation system.

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State Line Metering
The new transmission line from Dalreed to Wine Country substation will require metering at
Dalreed to measure the state line between Oregon and Washington.

The metering will be located at Dalreed substation on the 230 kV line to Wine Country. The
Transmission Provider will specify and order all interconnection revenue metering, including
the meter, meter panel, and secondary metering wire. The primary metering transformers are
expected to be breaker CTs and line VTs from relay.
The metering design package will include one revenue quality meter with bidirectional KWH
and KVARH quantities.
Cellular or Ethernet connection is required for retail sales and generation accounting via
the MV-90 translation system.

Interchange Metering
The Point of Interconnect metering will be located at the customer’s substation and rated for
the total net generation of the Project. The Transmission Provider will specify and order all
interconnection revenue metering, including the instrument transformers, meters, meter panel,
junction box, and secondary metering wire. The primary metering transformers will be
combination 34.5kV CT/VT units with extended range CTs for high-accuracy metering.
The metering design package will include two revenue quality meters with DNP real time
digital data terminated at a metering interposition block. One meter will be designated as
primary SCADA meter with DNP data delivered to the primary control center. A second meter
will be designated as backup SCADA meter with DNP data delivered to the alternate control
center. The metering data will include bidirectional KWH and KVARH revenue quantities.
The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage,
and per-phase amps data.
An Ethernet connection is required for retail sales and generation accounting via the MV-
90 translation system.

Station Service/Construction Power
The Project is within the Transmission Provider’s service territory. Please note that prior to
back feed, Interconnection Customer must arrange transmission retail meter service for
electricity consumed by the Project that will be drawn from the transmission system when the
Project is not generating. Interconnection Customer must call the PCCC Solution Center 1-
800‐625‐6078 to arrange this service. Approval for back feed is contingent upon obtaining
station service.

8.0 CONTINGENT FACILITIES
The following Interconnection Facilities and/or upgrades to the Transmission Provider’s system
are Contingent Facilities applicable to this Cluster Area: None.
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9.0 COST ESTIMATE
The following facilities are directly assigned to Interconnection Customer(s) using such facilities.
If multiple Interconnection Requests are utilizing the same Transmission Provider Interconnection
Facilities the costs shall be shared pursuant to Section 39.2.3 of Transmission Provider’s OATT.

TCS-55 Site $481,000
Control house, metering & communications

Distribution $40,000
Tap feeder and line extension

Dalreed Substation $19,266,000
New line position, phase shifter, voltage transformer

Wine Country Substation $3,816,000
New line position, metering, communications

Dalreed-Wine Country Transmission Line $53,417,000
Construct ~50-mile 230 kV transmission line

Grand Total $77,020,000
10.0 SCHEDULE
The Transmission Provider estimates it will require approximately 120 months to permit, design,
procure and construct the facilities described in this report following the execution of an
Interconnection Agreement. The schedule will be further developed and optimized during the
Facilities Study.

Please note, the time required to perform the scope of work identified in this report does not support
the Interconnection Customers’ requested Commercial Operation date.
11.0 AFFECTED SYSTEMS
Transmission Provider has identified the following affected systems: Bonneville Power
Administration and Portland General Electric

A copy of this report will be shared with each Affected System.
12.0 APPENDICES
Appendix 1: Cluster Area Power Flow and Stability Study Results
Appendix 2: Higher Priority Requests
Appendix 3: Property Requirements
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12.1 Appendix 1: Cluster Area Power Flow and Stability Study Results
Two case studies were assembled and studied in power flow simulation at the transmission
level:
• Case 1: Normal configuration with circuit 4K16 fed by Dalreed 230-34.5 kV transformer
banks 3 and 4 in parallel.
• Case 2: Contingency configuration with circuit 4K16 fed by Dalreed 230-34.5 kV
transformer bank 3 or 4 alone.

Certain other contingency configurations may warrant generation curtailment until the system
returns to a normal state. This includes the following scenarios:
• An outage of BPA’s 230 kV system serving Dalreed substation, resulting in a restoration
of service from the 69 kV Arlington source.
• An outage of both Dalreed 230-34.5 kV transformer banks 3 and 4, resulting in restoration
from bank 1 or 2.

No identified power flow restrictions were identified on the Transmission Provider’s
transmission system with the proposed generation online.

Voltages and post transient voltage steps are projected in power flow simulation to remain
within permissible limits during the interruption of the TCS-55 generation in the Transmission
Provider’s configuration cases 1 and 2 for all load levels.

During all times of the year, TCS-55 generation at maximum levels will result in export to the
Dalreed 230 kV bus. Peak summer loads on the PacifiCorp 34.5 kV are sufficient to sync
TCS-55 generation. Outside of summer, the Dalreed area load is less than the sum of existing
and proposed generation, so generation at even low levels will result in export to the Dalreed
230 kV bus and to BPA’s transmission system during these periods.

A stability study will be required to determine the effects of generating into the Dalreed system
due to possible stability issues resulting from conflict with existing wind and biofuel
generation.

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12.2 Appendix 2: Higher Priority Requests
All active higher priority Transmission Provider projects, and transmission service and/or
generator interconnection requests will be considered in this cluster area study and are
identified below. If any of these requests are withdrawn, the Transmission Provider reserves
the right to restudy this request, as the results and conclusions contained within this study could
significantly change.

Transmission/Generation Interconnection Queue Requests considered:

None
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12.3 Appendix 3: Property Requirements
Property Requirements for Point of Interconnection Substation
Requirements for rights of way easements
Rights of way easements will be acquired by the Interconnection Customer in the Transmission
Provider’s name for the construction, reconstruction, operation, maintenance, repair,
replacement and removal of Transmission Provider’s Interconnection Facilities that will be
owned and operated by PacifiCorp. Interconnection Customer will acquire all necessary
permits for the Project and will obtain rights of way easements for the Project on Transmission
Provider’s easement form.

Real Property Requirements for Point of Interconnection Substation
Real property for a POI substation will be acquired by an Interconnection Customer to
accommodate the Interconnection Customer’s Project. The real property must be acceptable to
Transmission Provider. Interconnection Customer will acquire fee ownership for
interconnection substation unless Transmission Provider determines that other than fee
ownership is acceptable; however, the form and instrument of such rights will be at
Transmission Provider’s sole discretion. Any land rights that Interconnection Customer is
planning to retain as part of a fee property conveyance will be identified in advance to
Transmission Provider and are subject to the Transmission Provider’s approval.

The Interconnection Customer must obtain all permits required by all relevant jurisdictions for
the planned use including but not limited to conditional use permits, Certificates of Public
Convenience and Necessity, California Environmental Quality Act, as well as all construction
permits for the Project.

Interconnection Customer will not be reimbursed through network upgrades for more than the
market value of the property.

As a minimum, real property must be environmentally, physically, and operationally
acceptable to Transmission Provider. The real property shall be a permitted or able to be
permitted use in all zoning districts. The Interconnection Customer shall provide Transmission
Provider with a title report and shall transfer property without any material defects of title or
other encumbrances that are not acceptable to Transmission Provider. Property lines shall be
surveyed and show all encumbrances, encroachments, and roads.

Examples of potentially unacceptable environmental, physical, or operational conditions could
include but are not limited to:

1. Environmental: known contamination of site; evidence of environmental
contamination by any dangerous, hazardous or toxic materials as defined by any
governmental agency; violation of building, health, safety, environmental, fire, land
use, zoning or other such regulation; violation of ordinances or statutes of any
governmental entities having jurisdiction over the property; underground or above
ground storage tanks in area; known remediation sites on property; ongoing
mitigation activities or monitoring activities; asbestos; lead-based paint, etc. A
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phase I environmental study is required for land being acquired in fee by the
Transmission Provider unless waived by Transmission Provider.

2. Physical: inadequate site drainage; proximity to flood zone; erosion issues; wetland
overlays; threatened and endangered species; archeological or culturally sensitive
areas; inadequate sub-surface elements, etc. Transmission Provider may require
Interconnection Customer to procure various studies and surveys as determined
necessary by Transmission Provider.

Operational: inadequate access for Transmission Provider’s equipment and vehicles; existing
structures on land that require removal prior to building of substation; ongoing maintenance
for landscaping or extensive landscape requirements; ongoing homeowner's or other
requirements or restrictions (e.g., Covenants, Codes and Restrictions, deed restrictions, etc.)
on property which are not acceptable to the Transmission Provider.

Generation Interconnection Transition Cluster

Transition Cluster Study Report

Cluster Area 10

March 31, 2021

Transition Cluster Study Report
Transition Cluster Area 10 Page i March 31, 2021

TABLE OF CONTENTS

1.0 SCOPE OF THE STUDY ................................................................................................................. 1
2.0 STUDY ASSUMPTIONS ................................................................................................................. 1
3.0 GENERATING FACILITY REQUIREMENTS .............................................................................. 2
3.1 Distribution Interconnection Requests .............................................................................................. 3
4.0 CLUSTER AREA DEFINITIONS ................................................................................................... 3
5.0 CLUSTER AREA 10 ........................................................................................................................ 3
5.1 Description of Interconnection Request – TCS-38 ........................................................................... 3
5.2 Description of Interconnection Request – TCS-39 ........................................................................... 4
5.3 Description of Interconnection Request – TCS-40 ........................................................................... 4
6.0 SITE SPECIFIC GENERATING FACILITY REQUIREMENTS ................................................... 5
7.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS ........................................................ 6
7.1 Transmission System Requirements ................................................................................................. 6
7.2 Distribution System Requirements ................................................................................................... 6
7.3 Transmission Line Requirements ...................................................................................................... 8
7.4 Existing Circuit Breaker Upgrades – Short Circuit ........................................................................... 8
7.5 Protection Requirements ................................................................................................................... 9
7.6 Data (RTU) Requirements ................................................................................................................ 9
7.7 Substation Requirements ................................................................................................................... 9
7.8 Communication Requirements .......................................................................................................... 9
7.9 Metering Requirements ................................................................................................................... 10
8.0 CONTINGENT FACILITIES ......................................................................................................... 11
9.0 COST ESTIMATE .......................................................................................................................... 11
9.1 Interconnection Facilities ................................................................................................................ 11
10.0 SCHEDULE .................................................................................................................................... 12
11.0 AFFECTED SYSTEMS ................................................................................................................. 12
12.0 APPENDICES ................................................................................................................................ 12
12.1 Appendix 1: Cluster Area Power Flow and Stability Study Results ............................................... 13
12.2 Appendix 2: Higher Priority Requests ............................................................................................ 14
12.3 Appendix 3: Property Requirements ............................................................................................... 15

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1.0 SCOPE OF THE STUDY
Cluster Area 10 (CA10) generally covers the Transmission Provider’s Willamette Valley load
pocket in west-central Oregon and consists of the following Interconnection Requests: TCS-38,
TCS-39 and TCS-40

Consistent with Attachment W, Section 3.4.2 and Section 51.4 of PacifiCorp’s (“Transmission
Provider”) Open Access Transmission Tariff (“OATT”), this interconnection Transition Cluster
Study (“Cluster Study”) evaluated the impact of the proposed interconnections on the reliability
of the Transmission System. The Cluster Study considered the Base Case as well as all generating
facilities (and with respect to (iii) below, any identified Network Upgrades associated with such
higher queued interconnection) that, on the date the Cluster Request Window closes:

(i) are existing and directly interconnected to the Transmission System;
(ii) are existing and interconnected to Affected Systems and may have an impact on the
Interconnection Request;
(iii) have a pending higher queued or higher clustered interconnection request to interconnect
to the transmission system; and
(iv) have executed an LGIA or requested that an unexecuted LGIA be filed with FERC.

The Cluster Study consisted of power flow, stability, and short circuit analyses.

This Cluster Study report provides the following information:
• identification of any circuit breaker short circuit capability limits exceeded as a result of the
interconnection;
• identification of any thermal overload or voltage limit violations resulting from the
interconnection;
• identification of any instability or inadequately damped response to system disturbances
resulting from the interconnection and
• description and non-binding, good faith estimated cost of facilities required to interconnect the
Generating Facilities to the Transmission System and to address the identified short circuit,
instability, and power flow issues.
2.0 STUDY ASSUMPTIONS
• All active higher priority transmission service and/or generator interconnection requests
that were considered in this study are listed in Appendix 2. If any of these requests are
withdrawn, the Transmission Provider reserves the right to restudy this request, and the
results and conclusions could significantly change.
• For study purposes there are two separate queues:
o Transmission Service Queue: to the extent practical, all network upgrades that are
required to accommodate active transmission service requests were modeled in this
study.
o Generation Interconnection Queue: Interconnection Facilities and network
upgrades associated with higher queued or higher clustered interconnection
requests were modeled in this study.
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• The Interconnection Customers’ request for energy or network resource interconnection
service in and of itself does not request or convey transmission service. Only a Network
Customer may make a request to designate a generating resource as a Network Resource.
Because the queue of higher priority transmission service requests may be different when
a Network Customer requests network resource designation for this Generating Facility,
the available capacity or transmission modifications, if any, necessary to provide Network
Integration Transmission Service may be significantly different. Therefore,
Interconnection Customers should regard the results of this study as informational rather
than final.
• Under normal conditions, the Transmission Provider does not dispatch or otherwise
directly control or regulate the output of generating facilities. Therefore, the need for
transmission modifications, if any, that may be required to provide Network Resource
Interconnection Service will be evaluated on the basis of 100 percent deliverability (i.e.,
this study did not model displacement of other resources in the same area).
• This study assumed the Projects will be integrated into the Transmission Provider’s system
at agreed upon and/or proposed Points of Interconnection (“POI” or “POIs”).
• If Interconnection Customers proceed through the interconnection process, they will be
required to construct and own any facilities required between the Point of Change of
Ownership and the Project unless specifically identified by the Transmission Provider.
• Line reconductor or fiber underbuild required on existing poles were assumed to follow the
most direct path on the Transmission Provider’s system. If during detailed design the path
must be modified it may result in additional cost and timing delays for the Interconnection
Customer’s Project.
• Generator tripping may be required for certain outages.
• The Transmission Provider has assumed that the current contractual arrangement of the
leased system between the Interconnection Customer and the Transmission Provider
remains as it currently stands. Should that contractual arrangement change, metering and
communications changes could be required.
• All facilities will meet or exceed the minimum Western Electricity Coordinating Council
(“WECC”), North American Electric Reliability Corporation (“NERC”), and the
Transmission Provider’s performance and design standards.
• This report is based on information available at the time of the study. It is the
Interconnection Customer’s responsibility to check the Transmission Provider’s web site
regularly for Transmission System updates at https://www.oasis.oati.com/ppw
3.0 GENERATING FACILITY REQUIREMENTS
The following requirements are applicable to all Interconnection Requests. The Transmission
Provider will identify any site-specific generating facility requirements in addition to the following
in this report and in facilities studies. Certain Interconnection Requests requesting service at a
voltage level traditionally defined as distribution may be subject to the transmission
interconnection request requirements listed below should the Transmission Provider make that
determination.
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3.1 Distribution Interconnection Requests
The Generating Facility and interconnection equipment owned by the Interconnection
Customers are required to operate under constant power factor mode with a unity power factor
setting unless specifically requested otherwise by the Transmission Provider. The Generating
Facilities are expressly forbidden from actively participating in voltage regulation of the
Transmission Provider’s system without written request or authorization from the
Transmission Provider. The Generating Facilities shall have sufficient reactive capacity to
enable the delivery of 100 percent of the plant output to the applicable POI at unity power
factor measured at 1.0 per unit voltage under steady state conditions.

Generators shall be capable of operating under Voltage-reactive power mode, Active power-
reactive power mode, and Constant reactive power mode as per IEEE Std. 1547-2018. This
Project shall be capable of activating each of these modes one at a time. The Transmission
Provider reserves the right to specify any mode and settings within the limits of IEEE Std 1547-
2018 needed before or after the generating facility enters service. The Interconnection
Customer shall be responsible for implementing settings modifications and mode selections as
requested by the Transmission Provider within an acceptable timeframe. The reactive
compensation must be designed such that the discreet switching of the reactive device (if
required by the Interconnection Customer) does not cause step voltage changes greater than
+/-3% on the Transmission Provider’s system. In all cases the minimum power quality
requirements in Transmission Provider’s Engineering Handbook section 1C shall be met and
are available at https://www.pacificpower.net/about/power-quality-standards.html.
Requirements specified in the System Impact Study that exceed requirements in the
Engineering Handbook section 1C power quality standards shall apply.
4.0 CLUSTER AREA DEFINITIONS
The Transmission Provider will perform the cluster study based on geographically and/or
electrically relevant areas on the Transmission Provider’s Transmission System known as Cluster
Areas. The Transmission Provider has determined that this Cluster Study will be comprised of the
following Cluster Areas:
5.0 CLUSTER AREA 10
The Transmission Provider performed the Transition Cluster Study based on geographically
and/or electrically relevant areas on the Transmission Provider’s Transmission System known as
Cluster Areas. The Transmission Provider has determined that the Interconnection Requests
discussed in Section 5.0 are located in a geographically and/or electrically relevant area on
Transmission Provider’s Transmission System, and thus, were assigned Cluster Area 10 in the
Transition Cluster Study process.
5.1 Description of Interconnection Request – TCS-38
The Interconnection Customer has proposed to interconnect 0.3 megawatts (“MW”) of new
generation to PacifiCorp’s (“Transmission Provider”) distribution circuit 4M182 located in
Benton County, Oregon. The Interconnection Request is proposed to consist of six (6) 50 KVA
Solectria PV150TL solar inverters for a total output of 0.3 MW at the POI. The requested
commercial operation date is September 1, 2021. Figure 1 below, is a one-line diagram that
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illustrates the interconnection of the proposed Generating Facility to the Transmission
Provider’s system.

Interconnection Customer will NOT operate this generator as a Qualified Facility as defined
by the Public Utility Regulatory Policies Act of 1978 (PURPA).

The Interconnection Request will be studied for Energy Resource Interconnection Service
(“ERIS”).

The Transmission Provider has assigned the Project Cluster Number “TCS-38”
5.2 Description of Interconnection Request – TCS-39
The Interconnection Customer has proposed to interconnect 0.15 megawatts (“MW”) of new
generation to PacifiCorp’s (“Transmission Provider”) distribution circuit 4M182 located in
Benton County, Oregon. The Interconnection Request is proposed to consist of three (3) 50
KVA Solectria PV150TL solar inverters for a total output of 0.15 MW at the POI. The
requested commercial operation date is September 1, 2021. Figure 1 below, is a one-line
diagram that illustrates the interconnection of the proposed Generating Facility to the
Transmission Provider’s system.

Interconnection Customer will NOT operate this generator as a Qualified Facility as defined
by the Public Utility Regulatory Policies Act of 1978 (PURPA).

The Interconnection Request will be studied for Energy Resource Interconnection Service
(“ERIS”).

The Transmission Provider has assigned the Project Cluster Number “TCS-39”
5.3 Description of Interconnection Request – TCS-40
The Interconnection Customer has proposed to interconnect 0.8 megawatts (“MW”) of new
generation to PacifiCorp’s (“Transmission Provider”) distribution circuit 4M182 located in
Benton County, Oregon. The Interconnection Request is proposed to consist of eight (8) 100
KVA Solaredge SE100KUM solar inverters for a total output of 0.8 MW at the POI. The
requested commercial operation date is September 1, 2021. Figure 1 below, is a one-line
diagram that illustrates the interconnection of the proposed Generating Facility to the
Transmission Provider’s system.

Interconnection Customer will NOT operate this generator as a Qualified Facility as defined
by the Public Utility Regulatory Policies Act of 1978 (PURPA).

The Interconnection Request will be studied for Energy Resource Interconnection Service
(“ERIS”).

The Transmission Provider has assigned the Project Cluster Number “TCS-40”

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NO
115kV
Hillview Substation
Energy Center
R
1.25 MVA
6 MVALoad
750 kVAZ=2.4%
20.8 kV
50 kWDC/AC
50 kWDC/AC
50 kWDC/AC
R
50 kWDC/AC
50 kWDC/AC
50 kWDC/AC
750 kVA
Z=3%
300 kVA
Z=6%
45 kVAZ=6%Grounding
Transformer
480 V
208 V
4.16 kV
Load
M
1000 kVA
Z=5.75%
M480 V
R
50 kWDC/AC50 kWDC/AC50 kWDC/AC
50 kWDC/AC50 kWDC/AC
50 kWDC/AC
50 kWDC/AC50 kWDC/AC
R
50 kWDC/AC50 kWDC/AC 50 kWDC/AC
LoadLoad
480 V
15 kVAZ=6%GroundingTransformer
75 kVAZ=6%GroundingTransformer
300 kVAZ=3.66%
R
Coliseum
Substation
TCS-38
TCS-39TCS-40
Optical Fiber Cable
Optical Fiber Cable
4M182
2.39 miles
630 ft
3580 ft
300 kWDC/AC500 kWDC/AC500 kWDC/AC
20.8 kV R
35th Street Substation
750 ft
2015 ftRabbit
Solar
Load
Mary s River
Grant
808 ft
NO
M
M
M
Figure 1: Simplified System One Line Diagram
6.0 SITE SPECIFIC GENERATING FACILITY REQUIREMENTS
In addition to the requirements described above the following Generating Facility are required for
the specific Interconnection Requests listed below.

TCS-38
The TCS-38 Interconnection Customer will be required to install a transformer that will hold the
phase to neutral voltages within limits when the generation facility is isolated with the
Transmission Provider’s local system until the generation disconnects. The circuit that the Project
is connecting to is a four wire multi-grounded circuit with line to neutral connected load. The 45
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kVA grounding transformer specified by the Interconnection Customer and shown in Figure 1 will
satisfy this requirement.

The electric generation facility will need to be equipped with a main 480 V generation breaker that
can disconnect all generation sources and the grounding transformer from the distribution network.
The main breaker needs to have stored energy operate capability so that the breaker can be tripped
open in a zero AC voltage state.

TCS-39
The TCS-39 Interconnection Customer will be required to install a transformer that will hold the
phase to neutral voltages within limits when the generation facility is isolated with the
Transmission Provider’s local system until the generation disconnects. The circuit that the Project
is connecting to is a four wire multi-grounded circuit with line to neutral connected load. The 15
kVA grounding transformer specified by the Interconnection Customer and shown in Figure 1 will
satisfy this requirement.

The electric generation facility will need to be equipped with a main 480 V generation breaker that
can disconnect all generation sources and the grounding transformer from the distribution network.
The main breaker needs to have stored energy operate capability so that the breaker can be tripped
open in a zero AC voltage state.

TCS-40
The TCS-40 Interconnection Customer will be required to install a transformer that will hold the
phase to neutral voltages within limits when the generation facility is isolated with the
Transmission Provider’s local system until the generation disconnects. The circuit that the Project
is connecting to is a four wire multi-grounded circuit with line to neutral connected load. The 75
kVA grounding transformer specified by the Interconnection Customer and shown in Figure 1 will
satisfy this requirement.

The electric generation facility will need to be equipped with a main 480 V generation breaker that
can disconnect all generation sources and the grounding transformer from the distribution network.
The main breaker needs to have stored energy operate capability so that the breaker can be tripped
open in a zero AC voltage state.
7.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS
7.1 Transmission System Requirements
No transmission system modifications are required to accommodate the three Interconnection
Requests in this Cluster Area.
7.2 Distribution System Requirements
TCS-38
No distribution system upgrades were identified as necessary to accommodate this
Interconnection Request.

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TCS-39
No distribution system upgrades were identified as necessary to accommodate this
Interconnection Request.

TCS-40
To accommodate this Interconnection Request the Transmission Provider will need to replace
an existing 300 kVA transformer with a 1000 kVA transformer and vault. The Transmission
Provider will also need to install a new PME-3 gang operated switchgear and vault between an
existing sectionalizer and the new transformer. New conduit and 4/0 AL conductor will be
required from the sectionalizer to switchgear and on to the new transformer. The placement of
required distribution equipment has not been finalized and will require input from
Interconnection Customer. The Transmission Provider has identified two possible options for
the installation of the new equipment that will be coordinated with the Interconnection
Customer:
• Replace in existing location, this will require prolonged outage to remove transformer
and vault and pull new wire as required.
• Install new vault, conduit and transformer in a new location near existing without taking
extended outage and cut over to new transformer with smaller outage.
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Figure 2: Map for TCS-40
7.3 Transmission Line Requirements
No transmission line upgrades are necessary for the proposed interconnection requests in this
Cluster Area.
7.4 Existing Circuit Breaker Upgrades – Short Circuit
The increase in the fault duty on the system as the result of the addition of the Generation
Facilities with photovoltaic arrays fed through 6 – 50 kW inverters connected to a 300 kVA
208 – 480 V transformer with 6% impedance then through a 750 kVA 4160 – 208 V
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transformer with 3 % impedance then through a 750 kVA 20.8 – 4.16 kV transformer with 2.4
% impedance along with photovoltaic array fed through 3 – 50 kW inverters connected to a
300 kVA 20.8 kV – 480 V transformer with 3.66 % impedance along with photovoltaic array
fed through 8 – 50 kW inverters connected to a 1000 kVA 20.8 kV – 480 V transformer with
5.75 % impedance will not push the fault duty above the interrupting rating of any of the
existing fault interrupting equipment.
7.5 Protection Requirements
The three solar projects in this Cluster Area will need to disconnect from the network in a high-
speed manner for faults on the 20.8 kV line on circuit 4M182 out of Hillview substation or for
faults in the 115–20.8 kV transformers at Hillview substation. There are existing generators on
this circuit that required the installation of relays at Hillview substation to detect faults in the
115–20.8 kV transformers and send transfer trip to the generators. The TCS-38, 39 and 40
Generating Facilities will also need to receive this transfer trip signal from Hillview substation.
The transfer trip signal is currently being received at the Energy Center. As part of there
Interconnection Requests a communication circuit will need to be installed that can carry this
signal from the Energy Center to the relays for the generation main 480 V breakers for each of
the three Generating Facilities.

Each of the three proposed Generating Facilities will need to be equipped with a main 480 V
generation breaker that can disconnect all generation sources from the distribution network.
The main breaker needs to have stored energy operate capability so that the breaker can be
tripped open in a zero AC voltage state. An SEL 751 relay would meet these requirements.
The source of sensing voltage for the relay will need to be on the utility side of the main breaker
for the Generating Facilities. The SEL 751 relay will be configured to perform the following
functions:
1. Detect faults on the 480 V equipment at the Generating Facilities
2. Detect faults on the 20.8 kV line to Hillview substation
3. Monitor the voltage and react to under or over frequency, and /or magnitude of the voltage
4. Monitor the unbalance current flowing through the grounding transformers and protect the
transformers from damage due to phase unbalances on the 20.8 kV circuit
5. Receive transfer trip from Hillview substation via the Energy Center
7.6 Data (RTU) Requirements
Due to the power size of these proposed Generating Facilities, no real time data will be
required.
7.7 Substation Requirements
No substation upgrades have been identified as necessary for the Interconnection Requests in
this Cluster Area.
7.8 Communication Requirements
An optical fiber cable will be required between the Interconnection Customer’s Energy Center
and each of the three Generating Facilities. The Transmission Provider will install
communications equipment, assumed to be pole mounted, at each of the three sites. Fiber will
be extended to the Interconnection Customers’ relays.
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7.9 Metering Requirements
TCS-38
A production meter to measure the output from the generator is required. The generator output
rating does not require metering DNP real-time data. The Transmission Provider will provide
the metering instrument transformers, meter, test switch and communication cellular package.
The Transmission Provider will create the meter program/design, test, and complete an in-
service accuracy verification of the metering package. The Interconnection Customer will
install the meter mounting and transformer enclosure, which will conform to the Transmission
Provider’s Six State Electric Service Requirements manual.

Station Service/Construction Power
Presumably the Interconnection Customer will provide construction power within their
existing system. However, if the customer does require a feed from the Transmission Provider,
the customer must arrange temporary construction power metering. Interconnection Customer
must call the PCCC Solution Center 1-800-640-2212 to arrange this service

TCS-39
A production meter to measure the output from the generator is required. The generator output
rating does not require metering DNP real-time data. The Transmission Provider will provide
the metering instrument transformers, meter, test switch and communication cellular package.
The Transmission Provider will create the meter program/design, test, and complete an in-
service accuracy verification of the metering package. The Interconnection Customer will
install the meter mounting and transformer enclosure, which will conform to the Transmission
Provider’s Six State Electric Service Requirements manual.

Station Service/Construction Power
Presumably the Interconnection Customer will provide construction power within their
existing system. However, if the customer does require a feed from the Transmission Provider,
the customer must arrange temporary construction power metering. Interconnection Customer
must call the PCCC Solution Center 1-800-640-2212 to arrange this service

TCS-40
A production meter to measure the output from the generator is required. The generator output
rating does not require metering DNP real-time data. The Transmission Provider will provide
the metering instrument transformers, meter, test switch and communication cellular package.
The Transmission Provider will create the meter program/design, test, and complete an in-
service accuracy verification of the metering package. The Interconnection Customer will
install the meter mounting and transformer enclosure, which will conform to the Transmission
Provider’s Six State Electric Service Requirements manual.

Station Service/Construction Power
Presumably the Interconnection Customer will provide construction power within their
existing system. However, if the customer does require a feed from the Transmission Provider,
the customer must arrange temporary construction power metering. Interconnection Customer
must call the PCCC Solution Center 1-800-640-2212 to arrange this service
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8.0 CONTINGENT FACILITIES
There are no contingent facilities identified for this interconnection request.
9.0 COST ESTIMATE
The following estimate represents only scopes of work that will be performed by the Transmission
Provider. Costs for any work being performed by the Interconnection Customer and/or Affected
Systems are not included.
9.1 Interconnection Facilities
The following facilities are directly assigned to Interconnection Customer(s) using such
facilities. If multiple Interconnection Requests are utilizing the same Transmission Provider
Interconnection Facilities the costs shall be shared pursuant to Section 39.2.3 of Transmission
Provider’s OATT.

TCS-38
Project Administration $7,000
Project management, administrative support

Develop Relay Settings $9,000
P&C Engineer and Relay Technician

Metering $9,000
Metering equipment

Communications $75,000
Fiber from Energy Center to POI, equipment at POI and Energy Center

Other Costs $19,000
Capital surcharge and contingency

Total $119,000

TCS-39
Project Administration $7,000
Project management, administrative support

Develop Relay Settings $9,000
P&C Engineer and Relay Technician

Metering $9,000
Metering equipment

Communications $18,000
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Fiber from Energy Center to POI, equipment at POI and Energy Center

Other Costs $19,000
Capital surcharge and contingency

Total $62,000

TCS-40
Project Administration $7,000
Project management, administrative support

Develop Relay Settings $9,000
P&C Engineer and Relay Technician

Metering $9,000
Metering equipment

Distribution $64,000
Install transformer, switchgear, conductor

Communications $18,000
Fiber from Energy Center to POI, equipment at POI and Energy Center

Other Costs $19,000
Capital surcharge and contingency

Total $126,000
10.0 SCHEDULE
The Transmission Provider estimates it will require approximately 15-18 months to design,
procure and construct the facilities described in this report following the execution of
Interconnection Agreements. The schedule will be further developed and optimized during the
Facilities Studies.

Please note, the time required to perform the scope of work identified in this report does not support
the Interconnection Customers’ requested Commercial Operation dates.
11.0 AFFECTED SYSTEMS
Transmission Provider has identified the following affected systems: None
12.0 APPENDICES
Appendix 1: Cluster Area Power Flow and Stability Study Results
Appendix 2: Higher Priority Requests
Appendix 3: Property Requirements
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12.1 Appendix 1: Cluster Area Power Flow and Stability Study Results
Three base cases were developed to represent heavy summer, heavy winter and light spring load
conditions. A Power flow analysis was performed on each case for various system configurations.
The study focused on the 115 kV system that make up the Corvallis loop and distribution bus at
Hillview substation. Voltage and thermal limitation of surrounding substation buses and lines were
monitored.

The results for the transmission study concluded that steady state and post transient voltages are
within acceptable limits. No thermal violations were identified. The proposed Generation Facilities
TCS-38, 39 and 40 do not result in additional deficiencies to the Transmission Provider’s
transmission system. No transmission upgrades are required.
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12.2 Appendix 2: Higher Priority Requests
All active higher priority Transmission Provider projects, and transmission service and/or
generator interconnection requests will be considered in this cluster area study and are identified
below. If any of these requests are withdrawn, the Transmission Provider reserves the right to
restudy this request, as the results and conclusions contained within this study could significantly
change.

Transmission/Generation Interconnection Queue Requests considered:

OCS008 (2.16 MW)
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12.3 Appendix 3: Property Requirements
Property Requirements for Point of Interconnection Substation
Requirements for rights of way easements
Rights of way easements will be acquired by the Interconnection Customer in the Transmission
Provider’s name for the construction, reconstruction, operation, maintenance, repair, replacement
and removal of Transmission Provider’s Interconnection Facilities that will be owned and
operated by PacifiCorp. Interconnection Customer will acquire all necessary permits for the
Project and will obtain rights of way easements for the Project on Transmission Provider’s
easement form.

Real Property Requirements for Point of Interconnection Substation
Real property for a POI substation will be acquired by an Interconnection Customer to
accommodate the Interconnection Customer’s Project. The real property must be acceptable to
Transmission Provider. Interconnection Customer will acquire fee ownership for interconnection
substation unless Transmission Provider determines that other than fee ownership is acceptable;
however, the form and instrument of such rights will be at Transmission Provider’s sole
discretion. Any land rights that Interconnection Customer is planning to retain as part of a fee
property conveyance will be identified in advance to Transmission Provider and are subject to
the Transmission Provider’s approval.

The Interconnection Customer must obtain all permits required by all relevant jurisdictions for
the planned use including but not limited to conditional use permits, Certificates of Public
Convenience and Necessity, California Environmental Quality Act, as well as all construction
permits for the Project.

If eligible, Interconnection Customer will not be reimbursed through network upgrades for more
than the market value of the property.

As a minimum, real property must be environmentally, physically, and operationally acceptable
to Transmission Provider. The real property shall be a permitted or able to be permitted use in all
zoning districts. The Interconnection Customer shall provide Transmission Provider with a title
report and shall transfer property without any material defects of title or other encumbrances that
are not acceptable to Transmission Provider. Property lines shall be surveyed and show all
encumbrances, encroachments, and roads.

Examples of potentially unacceptable environmental, physical, or operational conditions could
include but are not limited to:

1. Environmental: known contamination of site; evidence of environmental
contamination by any dangerous, hazardous or toxic materials as defined by any
governmental agency; violation of building, health, safety, environmental, fire,
land use, zoning or other such regulation; violation of ordinances or statutes of
any governmental entities having jurisdiction over the property; underground or
above ground storage tanks in area; known remediation sites on property; ongoing
mitigation activities or monitoring activities; asbestos; lead-based paint, etc. A
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phase I environmental study is required for land being acquired in fee by the
Transmission Provider unless waived by Transmission Provider.

2. Physical: inadequate site drainage; proximity to flood zone; erosion issues;
wetland overlays; threatened and endangered species; archeological or culturally
sensitive areas; inadequate sub-surface elements, etc. Transmission Provider may
require Interconnection Customer to procure various studies and surveys as
determined necessary by Transmission Provider.

Operational: inadequate access for Transmission Provider’s equipment and vehicles; existing
structures on land that require removal prior to building of substation; ongoing maintenance for
landscaping or extensive landscape requirements; ongoing homeowner's or other requirements or
restrictions (e.g., Covenants, Codes and Restrictions, deed restrictions, etc.) on property which
are not acceptable to the Transmission Provider.

Generation Interconnection Transition Cluster
Transition Cluster Study Report
Cluster Area 6

March 31, 2021

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Transition Cluster Area 6 Page i March 31, 2021

TABLE OF CONTENTS
1.0 SCOPE OF THE STUDY ................................................................................................................. 1 2.0 STUDY ASSUMPTIONS ................................................................................................................. 1 3.0 GENERATING FACILITY REQUIREMENTS .............................................................................. 2 3.1 Distribution Voltage Interconnection Requests ................................................................................ 2 4.0 CLUSTER AREA DEFINITIONS ................................................................................................... 3
5.0 CLUSTER AREA 6 .......................................................................................................................... 3 5.1 Description of Interconnection Request - TCS-12 ............................................................................ 3 5.2 Description of Interconnection Request - TCS-13 ............................................................................ 4 5.3 Description of Interconnection Request - TCS-14 ............................................................................ 5 5.4 Description of Interconnection Request - TCS-15 ............................................................................ 6 6.0 SITE SPECIFIC GENERATING FACILITY REQUIREMENTS ................................................... 7 6.1 Interconnection Request Cluster #6 .................................................................................................. 7 7.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS - ERIS ............................................ 7 7.1 Transmission System Requirements ................................................................................................. 7 7.2 Distribution System Requirements ................................................................................................... 7 7.3 Transmission Line Requirements ...................................................................................................... 8 7.4 Existing Circuit Breaker Upgrades – Short Circuit ........................................................................... 8 7.5 Protection Requirements ................................................................................................................... 9 7.6 Data (RTU) Requirements .............................................................................................................. 11 7.7 Substation Requirements ................................................................................................................. 12 7.8 Communication Requirements ........................................................................................................ 12 7.9 Metering Requirements ................................................................................................................... 13 8.0 CONTINGENT FACILITIES (ERIS) ............................................................................................ 14 9.0 COST ESTIMATE (ERIS) ............................................................................................................. 14 9.1 Interconnection Facilities ................................................................................................................ 14 10.0 SCHEDULE (ERIS) ....................................................................................................................... 16 11.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS – NRIS ......................................... 16 12.0 AFFECTED SYSTEMS ................................................................................................................. 16 13.0 APPENDICES ................................................................................................................................ 16 13.1 Appendix 1: Cluster Area Power Flow and Stability Study Results ............................................... 17 13.2 Appendix 2: Higher Priority Requests ............................................................................................ 18 13.3 Appendix 3: Property Requirements ............................................................................................... 19
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1.0 SCOPE OF THE STUDY
Cluster Area 6 (CA6) generally covers the Sunnyside/Yakima, Washington area and consists of
the following four Interconnection Requests.: TCS-12, TCS-13, TCS-14 and TCS-15 Consistent with Attachment W, Section 3.4.2 and Section 51.4 of PacifiCorp’s (“Transmission Provider”) Open Access Transmission Tariff (“OATT”), this interconnection Transition Cluster Study (“Cluster Study”) evaluated the impact of the proposed interconnections on the reliability
of the Transmission System. The Cluster Study considered the Base Case as well as all generating facilities (and with respect to (iii) below, any identified Network Upgrades associated with such higher queued interconnection) that, on the date the Cluster Request Window closes:
(i) are existing and directly interconnected to the Transmission System;
(ii) are existing and interconnected to Affected Systems and may have an impact on the Interconnection Request; (iii) have a pending higher queued or higher clustered interconnection request to interconnect to the transmission system; and
(iv) have executed an LGIA or requested that an unexecuted LGIA be filed with FERC.
The Cluster Study consisted of power flow, stability, and short circuit analyses. This Cluster Study report provides the following information:
• identification of any circuit breaker short circuit capability limits exceeded as a result of the
interconnection;
• identification of any thermal overload or voltage limit violations resulting from the interconnection;
• identification of any instability or inadequately damped response to system disturbances resulting from the interconnection and
• description and non-binding, good faith estimated cost of facilities required to interconnect the Generating Facilities to the Transmission System and to address the identified short circuit,
instability, and power flow issues

2.0 STUDY ASSUMPTIONS
• All active higher priority transmission service and/or generator interconnection requests that were considered in this study are listed in Appendix 2. If any of these requests are withdrawn, the Transmission Provider reserves the right to restudy this request, and the results and conclusions could significantly change.
• For study purposes there are two separate queues:
o Transmission Service Queue: to the extent practical, all network upgrades that are required to accommodate active transmission service requests were modeled in this study. o Generation Interconnection Queue: Interconnection Facilities and network
upgrades associated with higher queued or higher clustered interconnection requests were modeled in this study.
• The Interconnection Customers’ request for energy or network resource interconnection
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service in and of itself does not request or convey transmission service. Only a Network Customer may make a request to designate a generating resource as a Network Resource.
Because the queue of higher priority transmission service requests may be different when a Network Customer requests network resource designation for this Generating Facility, the available capacity or transmission modifications, if any, necessary to provide Network Integration Transmission Service may be significantly different. Therefore, Interconnection Customers should regard the results of this study as informational rather than final.
• Under normal conditions, the Transmission Provider does not dispatch or otherwise directly control or regulate the output of generating facilities. Therefore, the need for transmission modifications, if any, that may be required to provide Network Resource Interconnection Service will be evaluated on the basis of 100 percent deliverability (i.e., this study did not
model displacement of other resources in the same area).
• This study assumed the Projects will be integrated into the Transmission Provider’s system at agreed upon and/or proposed Points of Interconnection (“POI” or “POIs”).
• If Interconnection Customers proceed through the interconnection process, they will be
required to construct and own any facilities required between the Point of Change of Ownership and the Project unless specifically identified by the Transmission Provider.
• Line reconductor or fiber underbuild required on existing poles were assumed to follow the most direct path on the Transmission Provider’s system. If during detailed design the path
must be modified it may result in additional cost and timing delays for the Interconnection Customer’s Project.
• Generator tripping may be required for certain outages.
• All facilities will meet or exceed the minimum Western Electricity Coordinating Council
(“WECC”), North American Electric Reliability Corporation (“NERC”), and the Transmission
Provider’s performance and design standards.
• This report is based on information available at the time of the study. It is the Interconnection Customer’s responsibility to check the Transmission Provider’s web site regularly for Transmission System updates at https://www.oasis.oati.com/ppw
3.0 GENERATING FACILITY REQUIREMENTS
The following requirements are applicable to all Interconnection Requests. The Transmission Provider will identify any site-specific generating facility requirements in addition to the following in this report and in facilities studies. Certain Interconnection Requests requesting service at a voltage level traditionally defined as distribution may be subject to the transmission
interconnection request requirements listed below should the Transmission Provider make that
determination.
3.1 Distribution Voltage Interconnection Requests
The Generating Facility and interconnection equipment owned by the Interconnection Customers are required to operate under constant power factor mode with a unity power factor
setting unless specifically requested otherwise by the Transmission Provider. The Generating
Facilities are expressly forbidden from actively participating in voltage regulation of the Transmission Provider’s system without written request or authorization from the Transmission Provider. The Generating Facilities shall have sufficient reactive capacity to enable the delivery of 100 percent of the plant output to the applicable POI at unity power
factor measured at 1.0 per unit voltage under steady state conditions.
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Generating Facilities shall be capable of operating under Voltage-reactive power mode, Active
power-reactive power mode, and Constant reactive power mode as per IEEE Std. 1547-2018. This project shall be capable of activating each of these modes one at a time. The Transmission Provider reserves the right to specify any mode and settings within the limits of IEEE Std 1547-2018 needed before or after the generating facility enters service. The Interconnection Customer shall be responsible for implementing settings modifications and mode selections as
requested by the Transmission Provider within an acceptable timeframe. The reactive compensation must be designed such that the discreet switching of the reactive device (if required by the Interconnection Customer) does not cause step voltage changes greater than +/-3% on the Transmission Provider’s system. In all cases the minimum power quality
requirements in Transmission Provider’s Engineering Handbook section 1C shall be met and
are available at https://www.pacificpower.net/about/power-quality-standards.html. Requirements specified in the System Impact Study that exceed requirements in the Engineering Handbook section 1C power quality standards shall apply.
4.0 CLUSTER AREA DEFINITIONS
The Transmission Provider performed the Transition Cluster Study based on geographically and/or
electrically relevant areas on the Transmission Provider’s Transmission System known as Cluster Areas. The Transmission Provider has determined that the Interconnection Requests discussed in Section 5.0 are located in a geographically and/or electrically relevant area on Transmission Provider’s Transmission System, and thus, were assigned Cluster Area 6 in the Transition Cluster
Study process.
5.0 CLUSTER AREA 6
Cluster Area 6 (CA6 generally covers the Sunnyside/Yakima, Washington area and consists of the following four Interconnection Requests.
5.1 Description of Interconnection Request - TCS-12
The Interconnection Customer has proposed to interconnect 3 megawatts (“MW”) of new
generation to Transmission Provider’s (“Transmission Provider”) distribution circuit 5Y690 out of White Swan substation located in Yakima County, Washington. The Interconnection Request is proposed to consist of twenty (20) 150 KVA SMA Sunny High Power Peak3 solar inverters for a total output of 3 MW at the POI. The requested commercial operation date is
December 31, 2021. Figure 1 below, is a one-line diagram that illustrates the interconnection
of the proposed Generating Facility to the Transmission Provider’s system. Interconnection Customer will NOT operate this generator as a Qualified Facility as defined by the Transmission Provider Regulatory Policies Act of 1978 (PURPA).

The Interconnection Request will be studied for Energy Resource Interconnection Service (“ERIS”). The Transmission Provider has assigned the Project Cluster Number “TCS-12”
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5.2 Description of Interconnection Request - TCS-13
The Interconnection Customer has proposed to interconnect 5 MW of new generation to the
Transmission Provider’s distribution circuit 5Y690 out of White Swan substation located in Yakima County, Washington. The Interconnection Request is proposed to consist of thirty-four (34) 150 KVA SMA Sunny High Power Peak3 solar inverters for a total output of 5 MW at the POI. The requested commercial operation date is December 31, 2021. Figure 1 below, is a one-line diagram that illustrates the interconnection of the proposed Generating Facility to
the Transmission Provider’s system. Interconnection Customer will operate this generator as a Qualified Facility as defined by the Transmission Provider Regulatory Policies Act of 1978 (PURPA).

The Interconnection Request will be studied for Network Resource Interconnection Service (“NRIS”). The Transmission Provider has assigned the Project Cluster Number “TCS-13”
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911 feet
5Y690
TOUNION GAP115kV
TOBPA WHITE SWAN115kV
12.0kV
MM
R
WHITE SWAN
SUBSTATION
Change of Ownership
Point of Interconnection
12.0kV
Meter
Optical Fiber Cable
LTC
R
R
LTC
LOADS
150 kWDC/AC 150 kWDC/AC150 kWDC/AC
150 kWDC/AC 20InvertersTotal
5000 kVA Z=6%3000 kVA Z=6%
600 V 600 V
34InvertersTotal
750 kVA Z=6%
TCS-12TCS-13
Figure 1: Simplified System One Line Diagram
5.3 Description of Interconnection Request - TCS-14
The Interconnection Customer has proposed to interconnect 2.99 MW of new generation to the Transmission Provider’s distribution circuit 5Y312 out of Sunnyside substation located in
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Yakima County, Washington. The Interconnection Request is proposed to consist of one (1) 3,300 KVA Power Electronics FP3190K2 solar inverter to be factory limited for a total output
of 2.99 MW at the POI. The Interconnection Request also consists of 2.99 MW of battery storage with no capability of charging from the Transmission Provider’s grid. The requested commercial operation date is December 31, 2020. Figure 2 below, is a one-line diagram that illustrates the interconnection of the proposed Generating Facility to the Transmission Provider’s system.
Interconnection Customer will operate this generator as a Qualified Facility as defined by the Transmission Provider Regulatory Policies Act of 1978 (PURPA).
The Interconnection Request will be studied for Network Resource Interconnection Service
(“NRIS”). The Transmission Provider has assigned the Project Cluster Number “TCS-14”
5.4 Description of Interconnection Request - TCS-15
The Interconnection Customer has proposed to interconnect 2 MW of new generation to the
Transmission Provider’s distribution circuit 5Y312 out of Sunnyside substation located in Yakima County, Washington. The Interconnection Request is proposed to consist of one (1) 2,125 KVA Power Electronics FP2125K2 solar inverter for a total output of 2 MW at the POI. The Interconnection Request also consists of 2 MW of battery storage with no capability of
charging from the Transmission Provider’s grid. for a total output of 2 MW at the POI. The
requested commercial operation date is December 31, 2020. Figure 2 below, is a one-line diagram that illustrates the interconnection of the proposed Generating Facility to the Transmission Provider’s system.
Interconnection Customer will operate this generator as a Qualified Facility as defined by the
Transmission Provider Regulatory Policies Act of 1978 (PURPA). The Interconnection Request will be studied for Network Resource Interconnection Service (“NRIS”).

The Transmission Provider has assigned the Project Cluster Number “TCS-15”
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NO
NO
NO
NO
NONO
115kV
SUNNYSIDE SUB
5Y312
Change of ownership
M
Point of Interconnection12.0 kV 1.7 Miles
Wine Country Sub Outlook Sub
R
Loads
12 kV
TCS-14
600 V
125 kWDC/AC
600 V
125 kWDC/AC
3000 kVA Z=5.75%
2000 kVA Z=5.75%
R
Optical Fiber Cable
1000 kVA Z=7.5%
M M
TCS-15
Figure 2: Simplified System One Line Diagram
6.0 SITE SPECIFIC GENERATING FACILITY REQUIREMENTS
In addition to the requirements described above the following Generating Facility are required for
the specific Interconnection Requests listed below.
6.1 Interconnection Request Cluster #6
The Interconnection Customers will be required to install a transformer that will hold the phase to neutral voltages within limits when the generating facilities are isolated with the Transmission Provider’s local system until the generation disconnects. All four
Interconnection Requests have proposed grounded-wye/ungrounded-wye step-up transformers
which will not accomplish the stabilization of the phase to neutral voltages on the 12 kV system. The circuits that the Interconnection Requests are proposing to connect to are four wire multi-grounded circuits with line to neutral connected load. Figures 1 & 2 show the addition of a wye – delta grounding transformer of adequate power size and impedance that will meet
the requirement as each of the two Points of Interconnection.
7.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS - ERIS
7.1 Transmission System Requirements
The Transmission Provider has determined that it is possible to have reverse power flow at White Swan substation on both banks 1 and 2 caused by the added generation from TCS-12
and 13. Protection and control equipment will need to be updated to accommodate reverse
power from the distribution system to the transmission system.
7.2 Distribution System Requirements
TCS-12 and TCS-13 To create a POI the Transmission Provider will extend 12 kV facilities from its existing
infrastructure to the Interconnection Customers’ Generating Facilities location. This line
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extension will require a minimum of two new poles. A three-phase, gang-operated, load break disconnect switch is required on the first pole. A primary metering assembly is required on
the second pole. The TCS-12 and TCS-13 interconnection projects will require modification to the existing voltage regulation scheme on Feeder 5Y690. These modifications are necessary to maintain steady state voltage levels within ANSI Range A during heavy loading conditions while the
generation facility is online. Without these network upgrades customers on Feeder 5Y690 will experience voltage levels below 0.94 p.u. while the generation facility is operating a full output which exceeds ANSI Range A limits. A new 438A regulator bank will be installed near facility point 02111016.0366000. An existing regulator bank will be moved from its current location
at facility point 02111016.0259001 to a location near 02111016.0192000.
The interconnection will require modifications to the LTC settings on transformers T-1000 and T-961 at White Swan substation. It will also require setting changes to a new set of line regulators just east of this interconnection as well as the next set of downstream line regulators.
TCS-14 and TCS-15 To create a POI the Transmission Provider will extend 12 kV facilities from its existing infrastructure to the Interconnection Customers’ Generating Facilities location. This line extension will require a minimum of two new poles. A three-phase, gang-operated, load break
disconnect switch is required on the first pole. A primary metering assembly is required on
the second pole. The TCS-14 and TCS-15 interconnection projects will require relocation of a bank of voltage regulators and modification of the LTC settings on T-3798 at Sunnyside substation. The
regulator bank will be moved from the present location on Outlook Road east of Maple Grove
to a new location on Maple Grove south of Outlook Road. This is required to maintain voltage within the ANSI Range A level of 0.95 per unit to 1.05 per unit. Without this change the voltage level on the Maple Grove branch near the end is calculated at 0.94 per unit.
Modification of the LTC settings at Sunnyside substation are required to ensure that the other
two feeders served from T-3798 (5Y311 and 5Y316) maintain voltages within ANSI Range A during peak load, as well.
7.3 Transmission Line Requirements
No Transmission line upgrades are required for the Interconnection Requests in this Cluster
Area.
7.4 Existing Circuit Breaker Upgrades – Short Circuit
TCS-12 and TCS-13 The increase in the fault duty on the system as the result of the addition of the generating facilities with photovoltaic arrays, inverters and transformers as specified in the
Interconnection Customers’ applications as shown in Figure 1, assuming transformers with 6%
impedance will not push the fault duty above the interrupting rating of any of the existing fault interrupting equipment.
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TCS-14 and TCS-15
The increase in the fault duty on the system as the result of the addition of the generating facilities with photovoltaic arrays, inverters and transformers as specified in the Interconnection Customers’ applications as shown in Figure 2, assuming transformers with 5% impedance will not push the fault duty above the interrupting rating of any of the existing fault interrupting equipment.
7.5 Protection Requirements
TCS-12 and TCS-13 Protective relaying systems will need to be installed that will detect faults and cause the disconnection of the Generating Facilities for the following:
• 12 kV line faults on circuit 5Y690 out of White Swan substation
• Faults in the 115 – 12 kV transformers at White Swan substation
• Faults on the 115 kV line out of White Swan to Union Gap and BPA White Swan

Faults in the 12 kV distribution circuit will be cleared by timely operation of circuit breaker 5Y690. The faults will be detected by overcurrent relay elements at White Swan substation. The existing relays do not have this capability therefore a new SEL-751 relay and associated equipment will be installed. This relay will be set to be directional which will required a set of
three 12 kV line potential transformers at the substation. The relay will also be set to produce
successive automatic reclosing operations of the line breaker 5Y690 in order to automatically recover the service for temporary faults. The reclosing should not take place when the Generating Facilities are connected to the
distribution feeder; therefore, the relay will not execute the reclosing order unless the line is
de-energized (“dead-line checking”). This requires the installation of 12 kV line potential transformers. As the generation capacity of the proposed Generating Facilities will surpass the feeder’s load during certain daylight periods, the dead-line checking scheme may lead to a condition with
5Y690 circuit breaker open for long periods of time. This will be avoided by sending direct transfer trip to the facility’s main recloser from the 5Y690 SEL-751 relay through a communications path anytime 5Y690 is open. The two substation 115-12 kV transformers are protected with fuses installed on the 115 kV
side. This protection scheme will not be effective when the Generating Facilities are put in service because during a transformer fault there will be a current contribution from the Generating Facilities that will not be cleared by the fuses. In addition to that, faults in the 115 kV line, which are currently cleared by the existing line protection scheme, will have a contribution from the Generation Facilities. To detect those faults in the transformer and in the
115 kV lines, two multifunction relays (SEL-321 or similar) will be installed using the existing 115 kV current transformers and the 115 kV voltage. Three new 115 kV voltage transformers and three slip on CTs on the high side of transformer T-961 are needed in this scheme. When a fault is detected in the direction from 12 kV to 115 kV, the relays will send transfer trip to
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the generating facility reclosers. The LTC control for T-961 is to be replaced with Beckwith controller and LTC settings modified for T-1000 to accommodate reverse power flow.
At the Generating Facility site, the Interconnection Customers will need to install a circuit recloser equipped with a SEL 351R relay/controller and voltage instrument transformers mounted on the utility side of the circuit recloser. The 351R will perform the following protection functions:
• Receive transfer trip from White Swan substation
• Detect faults on the 12 kV at the Generating Facility
• Detect faults on the 12 kV line to White Swan substation
• Monitor the voltage and react to under or over frequency, and / or magnitude of the voltage TCS-14 and TCS-15
Protective relaying systems will need to be installed that will detect faults and cause the disconnection of the generation facility for 12.5 kV line faults on circuit 5Y312 out of Sunnyside substation. The minimum day time load on this circuit is 1.7 MW which is well below the maximum potential power output of the proposed Generating Facilities. For this reason, the unbalance condition of the load and generation cannot be relied upon to cause the
high-speed disconnection of the Generation Facilities for faults on the Distribution System. Existing relay SEL-751 will be set to detect the fault conditions and send transfer trip from Sunnyside substation to the generating facilities to cause the disconnection of the Generation Facilities. For 12.5 kV circuit faults the transfer trip will be keyed by the opening of breaker 5Y312 at Sunnyside substation. The line relay associated with breaker 5Y312 need to have
two functions: directional overcurrent and dead-line checking. Both the functions will require the addition of 12.5 kV VTs on the line side of the CB 5Y312. The secondaries of these voltage transformers will connect to the feeder protection relay. With the addition of the Generation Facilities, current in excess of the overcurrent pickup
setting will flow into the substation for faults on the other feeder. This would cause CB 5Y312 to trip for faults on the other feeder which would be unacceptable. With the directional overcurrent function these unacceptable operations can be prevented. The dead-line checking will be required to block the automatic reclosing of CB 5Y312 for the cases when a failure of the protective systems leads to delayed tripping of the Generation Facilities for a feeder fault.
Reclosing for this type of situation could cause damage to the equipment and needs to be prevented. At the Generating Facility site, the Interconnection Customers will need to install a circuit recloser equipped with a SEL 351R relay/controller and voltage instrument transformers
mounted on the utility side of the circuit recloser. The 351R will perform the following protection functions:
• Receive transfer trip from Sunnyside substation
• Detect faults on the 12.5 kV at the generation facility
• Detect faults on the 12.5 kV line to Sunnyside substation
• Monitor the voltage and react to under or over frequency, and / or magnitude of the
• voltage
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7.6 Data (RTU) Requirements
TCS-12 and TCS-13
Data for the operation of the power system will be needed from the Interconnection Customer’s Generating Facilities. This data will be acquired by installing an RTU at the collector station. The following data will be acquired from the collector station. Analogs:
 Net Generation MW
 Net Generator MVAR
 Energy Register
 Real power flow TCS-12
 Reactive power flow Circuit TCS-12
 Real power flow Circuit TCS-13
 Reactive power flow Circuit TCS-13
 A phase 12.5 kV voltage
 B phase 12.5 kV voltage
 C phase 12.5 kV voltage
 Global Horizontal Irradiance (GHI)
 Average Plant Atmospheric Pressure (Bar)
 Average Plant Temperature (Celsius)
 Max Generator Limit MW (set point control)
 Potential Power MW
Status:
 12.5 kV tie recloser
 Relay alarm
TCS-14 and TCS-15
Data for the operation of the power system will be needed from the Interconnection Customer’s Generating Facilities. This data will be acquired by installing an RTU at the collector station. The following data will be acquired from the collector station.
Analogs:
 Net Generation MW
 Net Generator MVAR
 Energy Register
 A phase 12.5 kV voltage
 B phase 12.5 kV voltage
 C phase 12.5 kV voltage
 Global Horizontal Irradiance (GHI)
 Average Plant Atmospheric Pressure (Bar)
 Average Plant Temperature (Celsius)
 Max Generator Limit MW (set point control)
 Potential Power MW Status:
 12.5 kV tie recloser
 Relay alarm
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7.7 Substation Requirements
White Swan Substation
The following will be installed at White Swan substation to accommodate the protection scheme and may change during detailed design:
• (3) 12.5 kV voltage transformers
• (3) 115 kV CTs on T-961
• (3) 115 kV CCVT TCS-12 and TCS-13 POI
The TCS-12 and TCS-13 POI. Grading, grounding, fencing, and all other construction
activities to support the installation of the new control house and will be performed by the transmission provider. AC station service and DC battery banks will be provided and installed by the transmission provider. A CDEGS grounding analysis will be performed by the transmission provider. The following major equipment, which will be provided by the
transmission provider, has been identified as being required and may change during detailed
design.
• Control house Sunnyside Substation The following will be installed at Sunnyside Substation to accommodate the protection scheme and may change during detailed design:
• (3) 12.5kV voltage transformers
TCS-14 and TCS-15 The TCS-14 and TCS-15 POI. Grading, grounding, fencing, and all other construction activities to support the installation of the new control house and will be performed by the transmission provider. AC station service and DC battery banks will be provided and installed
by the transmission provider. A CDEGS grounding analysis will be performed by the transmission provider. The following major equipment, which will be provided by the transmission provider, has been identified as being required and may change during detailed design.
• Control house
7.8 Communication Requirements
TCS-12 and TCS-13 The existing single channel MAS radio will be replaced with a 960 multiple channel radio to Rattlesnake Hill communications site. A channel bank for SCADA, Ethernet and metering
channels will be installed along with a DC power system for communications. A new network router and switch will be required to support MV-90 communications. To support relaying and SCADA at the Generating Facilities site approximately 900 feet of ADSS fiber optic cable will be built along the distribution route to the Generating Facilities site. Communications equipment including an RTU will be installed at the Generating Facilities site. Fiber will be
extended to the Interconnection Customers’ recloser relay. TCS-14 and TCS-15
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The existing single channel MAS radio will be replaced with a 960 multiple channel radio to Prosser Hill communications site. A channel bank for SCADA, Ethernet and metering channels
will be installed along with a DC power system for communications. A new network router and switch will be required to support MV-90 comms. To support relaying and SCADA at the Generating Facilities site approximately 1.7 miles of ADSS fiber optic cable will be built along the distribution route to the Generating Facilities site. Communications equipment including an RTU will be installed at the generating facilities site. Fiber will be extended to the
Interconnection Customers’ recloser relay.
7.9 Metering Requirements
TCS-12 and TCS-13 Interchange Metering
Three metering points will be required: one metering point at the POI, one metering point for
TCS-12, and one metering point for TCS-13. All metering points will be located on the high side of the Interconnection Customers’ generator step up transformers. The metering transformers will be installed overhead on poles per distribution DM construction standards. The meters will be installed in a meter panel or outdoor enclosure.

The Transmission Provider will procure, install, test, and own all revenue metering equipment including the instrument transformers, meters, test switches, panels/enclosures, junction boxes, and secondary metering wire.
The metering design package for each point will include two revenue quality meters, for a total
of six meters. Each meter will have DNP real time digital data output. One meter for each point will be designated as primary SCADA meter with DNP data delivered to the primary control center. A second meter for each point will be designated as backup SCADA meter with DNP data delivered to the alternate control center. The metering data will include
bidirectional KWH and KVARH revenue quantities. The meter data will also include
instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps data. An Ethernet connection to each meter is required for retail sales and generation accounting via the meter data management system.

Station Service/Construction Power The Interconnection Customers must arrange distribution voltage retail meter service for electricity consumed by the project when not generating. Temporary construction power metering shall conform to the Six State Electric Service Requirements manual. Interconnection
Customer must call the PCCC Solution Center 1-800-640-2212 to arrange this service.
Approval for back feed is contingent upon obtaining station service. TCS-14 and TCS-15 Both Interconnection Requests propose DC coupled battery and solar facilities. The
Transmission Provider has no approved method to meter battery and solar in this configuration
separately therefore the solar and battery storage will essentially be a single Generating Facility from a revenue metering perspective.
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Interchange Metering Three metering points will be required: one metering point at the POI, one metering point for
TCS-14, and one metering point for TCS-15. All metering points will be located on the high side of the Interconnection Customers’ generator step up transformers. The metering transformers will be installed overhead on poles per distribution DM construction standards. The meters will be installed in a meter panel, outdoor enclosure, or outdoor meter base.
The Transmission Provider will procure, install, test, and own all revenue metering equipment including the instrument transformers, meters, test switches, panels/enclosures, junction boxes, and secondary metering wire.
The metering design package for the POI will include two revenue quality meters. Each meter
will have DNP real time digital data output. One meter will be designated as primary SCADA meter with DNP data delivered to the primary control center. A second meter will be designated as backup SCADA meter with DNP data delivered to the alternate control center. The metering data will include bidirectional KWH and KVARH revenue quantities. The meter
data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase
amps data. An Ethernet connection to the POI meters is required for retail sales and generation accounting via the meter data management system. The metering design package for each individual generator will include one revenue-quality
meter with bidirectional KWH and KVARH, revenue quantities. A cellular connection to each
individual generator meter is required for retail sales and generation accounting via the meter data management system. Station Service/Construction Power
The Interconnection Customer must arrange distribution voltage retail meter service for electricity consumed by the project when not generating. Temporary construction power metering shall conform to the Six State Electric Service Requirements manual. Interconnection Customer must
call the PCCC Solution Center 1-800-640-2212 to arrange this service. Approval for back feed is contingent upon obtaining station service.
8.0 CONTINGENT FACILITIES (ERIS)
There are no contingent facilities identified for any of these interconnection requests.
9.0 COST ESTIMATE (ERIS)
The following estimate represents only scopes of work that will be performed by the Transmission Provider. Costs for any work being performed by the Interconnection Customer and/or Affected Systems are not included.
9.1 Interconnection Facilities
The following facilities are directly assigned to Interconnection Customer(s) using such facilities. If multiple Interconnection Requests are utilizing the same Transmission Provider Interconnection Facilities the costs shall be shared pursuant to Section 39.2.3 of Transmission Provider’s OATT.

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Transition Cluster Area Page 15 March 31, 2021

TCS-12 and TCS-13 Collector Substation $466,000
Install control building, metering, communications and develop relay settings
Metering $157,000 Projects metering equipment White Swan Substation $806,000
Replace relay panel, install PT’s, CCVT’s and clip-on CT’s Rattlesnake Hill Substation $58,000
Communications
Distribution $201,000 Line extension, install new regulator bank, relocate existing bank
Total $1,688,000 TCS-12 Total $844,000 TCS-13 Total $844,000

TCS-14 and TCS-15 Collector Substation $448,000 Install control building, communications and develop relay settings
Metering $75,000
Projects metering equipment Sunnyside Substation $269,000
Install VT And communications
Prosser Hill Communications Site $58,000 Install communications
Distribution $99,000
Line extension, relocate regulator bank Total $949,000
TCS-14 Total $475,000 TCS-15 Total $475,000
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10.0 SCHEDULE (ERIS)
The Transmission Provider estimates it will require approximately 18-20 months to design,
procure and construct the facilities described in the ERIS sections of this report following the execution of Interconnection Agreements. The schedule will be further developed and optimized during the Facilities Studies.
11.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS – NRIS
The Transmission Provider has determined that there are no additional requirements to provide
NRIS for TCS-13, TCS-14 or TCS-15 beyond the requirements identified as necessary for ERIS.
12.0 AFFECTED SYSTEMS
Transmission Provider has identified the following affected systems: None
13.0 APPENDICES
Appendix 1: Cluster Area Power Flow and Stability Study Results
Appendix 2: Higher Priority Requests Appendix 3: Property Requirements
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13.1 Appendix 1: Cluster Area Power Flow and Stability Study Results
Three base cases were developed to represent heavy summer, heavy winter and light spring
load conditions. A Power flow analysis was performed on each case for various system configurations. The study focused on the 115 kV system near White Swan and Sunnyside substation and distribution bus at each substation. Voltage and thermal limitation of surrounding substation buses and lines were monitored.
The results for the transmission study concluded that steady state and post transient voltages are within acceptable limits. No thermal violations were identified. The proposed generation facilities do not result in additional deficiencies to the Transmission Provider’s transmission system. Although no voltage or thermal violations were found, the addition of TCS-12/TCS-
13 can cause reverse power flow on banks 1 and 2 at White Swan substation. Protection settings
will need to be updated and regulator controls to accommodate reverse power from the distribution system to the transmission system. The distribution analysis includes load flow and voltage analysis of the distribution systems
under summer peak conditions and fall light load conditions (minimum daytime load).
No conductor capacity issues have been identified. In the case of TCS-14 and TCS-15 the issues identified relate to maintaining voltage within
the ANSI Range A criteria on the Emerald Road section of the Maple Grove Branch during
summer peak demand on the system and maximum output from the two generation facilities. Also, it is possible that the transient impact of adding the generation during this condition may momentarily result in voltage levels on the primary system near the POI that exceed 1.05 per unit. That condition will persist until the substation transformer voltage regulation acts to
reduce the bus voltage and thus the line voltage level. A possible way to mitigate this issue is
to operate the generation facility in such a way that the generation facility consumes kVAR. In the case of TCS-12 and TCS-13 the issues identified relate to maintaining voltage within the ANSI Range A criteria near the intersection of Progressive Road and Stevenson Road in
the Wapato area during summer peak demand on the system and maximum output from the
two generation facilities. Load transfers, load balancing, and volt-var regulation through existing and potentially new switched capacitor banks were considered for alternative solutions to resolve the voltage violation at peak conditions, but each alternative studied failed to fully resolve the negative impact to the feeder voltage caused by the two generation installations.
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13.2 Appendix 2: Higher Priority Requests
All active higher priority Transmission Provider projects, and transmission service and/or
generator interconnection requests will be considered in this cluster area study and are identified below. If any of these requests are withdrawn, the Transmission Provider reserves the right to restudy this request, as the results and conclusions contained within this study could significantly change.
Transmission/Generation Interconnection Queue Requests considered: Q1008 (94 MW) Q0953 (80 MW)

Bonneville Power Administration requests considered: G0634 (80 MW) G0596 (80 MW) G0578 (80 MW)
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13.3 Appendix 3: Property Requirements
Property Requirements for Point of Interconnection Substation
Requirements for rights of way easements Rights of way easements will be acquired by the Interconnection Customer in the Transmission Provider’s name for the construction, reconstruction, operation, maintenance, repair, replacement and removal of Transmission Provider’s Interconnection Facilities that will be owned and operated by Transmission Provider. Interconnection Customer will acquire all
necessary permits for the Project and will obtain rights of way easements for the Project on Transmission Provider’s easement form. Real Property Requirements for Point of Interconnection Substation
Real property for a POI substation will be acquired by an Interconnection Customer to
accommodate the Interconnection Customer’s Project. The real property must be acceptable to Transmission Provider. Interconnection Customer will acquire fee ownership for interconnection substation unless Transmission Provider determines that other than fee ownership is acceptable; however, the form and instrument of such rights will be at
Transmission Provider’s sole discretion. Any land rights that Interconnection Customer is
planning to retain as part of a fee property conveyance will be identified in advance to Transmission Provider and are subject to the Transmission Provider’s approval. The Interconnection Customer must obtain all permits required by all relevant jurisdictions for
the planned use including but not limited to conditional use permits, Certificates of Public
Convenience and Necessity, California Environmental Quality Act, as well as all construction permits for the Project. If eligible, Interconnection Customer will not be reimbursed through network upgrades for
more than the market value of the property.
As a minimum, real property must be environmentally, physically, and operationally acceptable to Transmission Provider. The real property shall be a permitted or able to be permitted use in all zoning districts. The Interconnection Customer shall provide Transmission
Provider with a title report and shall transfer property without any material defects of title or
other encumbrances that are not acceptable to Transmission Provider. Property lines shall be surveyed and show all encumbrances, encroachments, and roads. Examples of potentially unacceptable environmental, physical, or operational conditions could
include but are not limited to:
1. Environmental: known contamination of site; evidence of environmental contamination by any dangerous, hazardous or toxic materials as defined by any governmental agency; violation of building, health, safety, environmental, fire, land use, zoning or other such
regulation; violation of ordinances or statutes of any governmental entities having
jurisdiction over the property; underground or above ground storage tanks in area; known remediation sites on property; ongoing mitigation activities or monitoring activities;
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asbestos; lead-based paint, etc. A phase I environmental study is required for land being acquired in fee by the Transmission Provider unless waived by Transmission Provider.
2. Physical: inadequate site drainage; proximity to flood zone; erosion issues; wetland overlays; threatened and endangered species; archeological or culturally sensitive areas; inadequate sub-surface elements, etc. Transmission Provider may require Interconnection Customer to procure various studies and surveys as determined necessary by Transmission
Provider. Operational: inadequate access for Transmission Provider’s equipment and vehicles; existing structures on land that require removal prior to building of substation; ongoing maintenance
for landscaping or extensive landscape requirements; ongoing homeowner's or other
requirements or restrictions (e.g., Covenants, Codes and Restrictions, deed restrictions, etc.) on property which are not acceptable to the Transmission Provider.

Generation Interconnection Transition Cluster

Transition Cluster Study Report
Cluster Area 8

September 17, 2021

System Impact Study Report
Transition Cluster Area 8 Page i September 17, 2021

TABLE OF CONTENTS
1.0 SCOPE OF THE STUDY ................................................................................................................. 1 2.0 STUDY ASSUMPTIONS ................................................................................................................. 1 3.0 GENERATING FACILITY REQUIREMENTS .............................................................................. 2 3.1 Transmission Voltage Interconnection Requests .............................................................................. 3 4.0 CLUSTER AREA DEFINITIONS ................................................................................................... 5 5.0 CLUSTER AREA 8 .......................................................................................................................... 6 5.1 Description of Interconnection Request – TCS-43 ........................................................................... 6 5.2 Description of Interconnection Request – TCS-44 ........................................................................... 7 5.3 Description of Interconnection Request – TCS-45 ......................................................................... 10 5.4 Description of Interconnection Request – TCS-52 ......................................................................... 11 5.5 Description of Interconnection Request – TCS-53 ......................................................................... 11 5.6 Description of Interconnection Request – TCS-54 ......................................................................... 12 6.0 SITE SPECIFIC GENERATING FACILITY REQUIREMENTS ................................................. 14 7.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS ...................................................... 14 7.1 Transmission System Requirements ............................................................................................... 14 7.2 Distribution System Requirements ................................................................................................. 15 7.3 Transmission Line Requirements .................................................................................................... 15 7.4 Existing Circuit Breaker Upgrades – Short Circuit ......................................................................... 15 7.5 Protection Requirements ................................................................................................................. 16 7.6 Data (RTU) Requirements .............................................................................................................. 18 7.7 Substation Requirements ................................................................................................................. 23 7.8 Communication Requirements ........................................................................................................ 25 7.9 Metering Requirements ................................................................................................................... 27 8.0 CONTINGENT FACILITIES ......................................................................................................... 35 9.0 COST ESTIMATE .......................................................................................................................... 35 9.1 Interconnection Facilities ................................................................................................................ 35 9.2 Station Equipment ........................................................................................................................... 37 9.3 Network Upgrades .......................................................................................................................... 37 9.4 Total Estimated Project Costs ......................................................................................................... 37 10.0 SCHEDULE .................................................................................................................................... 38 11.0 AFFECTED SYSTEMS ................................................................................................................. 38 12.0 APPENDICES ................................................................................................................................ 38 12.1 Appendix 1: Cluster Area Power Flow and Stability Study Results ............................................... 39 12.2 Appendix 2: Higher Priority Requests ............................................................................................ 43 12.3 Appendix 3: Property Requirements ............................................................................................... 44
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1.0 SCOPE OF THE STUDY
This cluster restudy is being performed due to the withdrawal of interconnection requests that were
included in the original cluster study. Cluster Area 8 (CA8) generally covers the geographic area of the Transmission Provider’s system referred to as the Prineville load pocket. This Cluster Area consists of the following Interconnection Requests: TCS-43, TCS-44, TCS-45, TCS-52, TCS-53, and TCS-54
Consistent with Attachment W, Section 3.4.2 and Section 51.4 of PacifiCorp’s (“Transmission Provider”) Open Access Transmission Tariff (“OATT”), this interconnection Transition Cluster Study (“Cluster Study”) evaluated the impact of the proposed interconnections on the reliability of the Transmission System. The Cluster Study considered the Base Case as well as all generating
facilities (and with respect to (iii) below, any identified Network Upgrades associated with such higher queued interconnection) that, on the date the Cluster Request Window closes: (i) are existing and directly interconnected to the Transmission System; (ii) are existing and interconnected to Affected Systems and may have an impact on the
Interconnection Request; (iii) have a pending higher queued or higher clustered interconnection request to interconnect to the transmission system; and (iv) have executed an LGIA or requested that an unexecuted LGIA be filed with FERC.
The Cluster Study consisted of power flow, stability, and short circuit analyses. This Cluster Study report provides the following information:
• identification of any circuit breaker short circuit capability limits exceeded as a result of the
interconnection;
• identification of any thermal overload or voltage limit violations resulting from the interconnection;
• identification of any instability or inadequately damped response to system disturbances
resulting from the interconnection and
• description and non-binding, good faith estimated cost of facilities required to interconnect the Generating Facilities to the Transmission System and to address the identified short circuit, instability, and power flow issues.
2.0 STUDY ASSUMPTIONS
• All active higher priority transmission service and/or generator interconnection requests that were considered in this study are listed in Appendix 2. If any of these requests are withdrawn, the Transmission Provider reserves the right to restudy this request, and the results and
conclusions could significantly change.
• For study purposes there are two separate queues: o Transmission Service Queue: to the extent practical, all network upgrades that are required to accommodate active transmission service requests were modeled in this study.
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o Generation Interconnection Queue: Interconnection Facilities and network upgrades associated with higher queued or higher clustered interconnection requests were modeled
in this study.
• The Interconnection Customers’ request for energy or network resource interconnection service in and of itself does not request or convey transmission service. Only a Network Customer may make a request to designate a generating resource as a Network Resource.
Because the queue of higher priority transmission service requests may be different when a
Network Customer requests network resource designation for this Generating Facility, the available capacity or transmission modifications, if any, necessary to provide Network Integration Transmission Service may be significantly different. Therefore, Interconnection Customers should regard the results of this study as informational rather than final.
• Under normal conditions, the Transmission Provider does not dispatch or otherwise directly control or regulate the output of generating facilities. Therefore, the need for transmission modifications, if any, that may be required to provide Network Resource Interconnection Service will be evaluated on the basis of 100 percent deliverability (i.e., this study did not model displacement of other resources in the same area).
• This study assumed the Projects will be integrated into the Transmission Provider’s system at agreed upon and/or proposed Points of Interconnection (“POI” or “POIs”).
• If Interconnection Customers proceed through the interconnection process, they will be
required to construct and own any facilities required between the Point of Change of
Ownership and the Project unless specifically identified by the Transmission Provider.
• Line reconductor or fiber underbuild required on existing poles were assumed to follow the most direct path on the Transmission Provider’s system. If during detailed design the path
must be modified it may result in additional cost and timing delays for the Interconnection
Customer’s Project.
• Generator tripping may be required for certain outages.
• All facilities will meet or exceed the minimum Western Electricity Coordinating Council (“WECC”), North American Electric Reliability Corporation (“NERC”), and the Transmission
Provider’s performance and design standards.
• This study assumes that a Transmission Provider planned project to construct a new 115 kV transmission line between Houston Lake and Ponderosa substations is in service. (2025)
• Upgrades associated with all previously queued projects are assumed to be in-service.
• Contingency transmission configuration for the Transmission Provider’s system is defined as
any configuration other than normal transmission configuration.
• This report is based on information available at the time of the study. It is the Interconnection Customer’s responsibility to check the Transmission Provider’s web site regularly for Transmission System updates at https://www.oasis.oati.com/ppw
3.0 GENERATING FACILITY REQUIREMENTS
The following requirements are applicable to all Interconnection Requests. The Transmission Provider will identify any site-specific generating facility requirements in addition to the following in this report and in facilities studies. Certain Interconnection Requests requesting service at a voltage level traditionally defined as distribution may be subject to the transmission
interconnection request requirements listed below should the Transmission Provider make that
determination.
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3.1 Transmission Voltage Interconnection Requests
All interconnecting synchronous and non-synchronous generators are required to design their
Generating Facilities with reactive power capabilities necessary to operate within the full power factor range of 0.95 leading to 0.95 lagging. This power factor range shall be dynamic and can be met using a combination of the inherent dynamic reactive power capability of the generator or inverter, dynamic reactive power devices and static reactive power devices to make up for losses.
For synchronous generators, the power factor requirement is to be measured at the Point of Interconnection (“POI”). For non-synchronous generators, the power factor requirement is to be measured at the high-side of the generator step-up transformer.
The Generating Facility must provide dynamic reactive power to the system in support of both voltage scheduling and contingency events that require transient voltage support, and must be able to provide reactive capability over the full range of real power output. If the Generating Facility is not capable of providing positive reactive support (i.e., supplying
reactive power to the system) immediately following the removal of a fault or other transient low voltage perturbations, the facility must be required to add dynamic voltage support equipment. These additional dynamic reactive devices shall have correct protection settings such that the devices will remain on line and active during and immediately following a fault event.
Generators shall be equipped with automatic voltage-control equipment and normally operated with the voltage regulation control mode enabled unless written authorization (or directive) from the Transmission Provider is given to operate in another control mode (e.g. constant power factor control). The control mode of generating units shall be accurately represented in
operating studies. The generators shall be capable of operating continuously at their maximum power output at its rated field current within +/- 5% of its rated terminal voltage. All generators are required to ensure the primary frequency capability of their Generating Facility by installing, maintaining, and operating a functioning governor or equivalent controls
as indicated in FERC Order 842. As required by NERC standard VAR-001-4.2, the Transmission Provider will provide a voltage schedule for the POI. In general, Generating Facilities should be operated so as to maintain the voltage at the POI, typically between 1.00 per unit to 1.04 per unit, or other
designated point as deemed appropriated by Transmission Provider. The Transmission Provider may also specify a voltage and/or reactive power bandwidth as needed to coordinate with upstream voltage control devices such as on-load tap changers. At the Transmission Provider’s discretion, these values might be adjusted depending on operating conditions.
Generating Facilities capable of operating with a voltage droop are required to do so. Voltage droop control enables proportionate reactive power sharing among Generation Facilities. Studies will be required to coordinate voltage droop settings if there are other facilities in the area. It will be the Interconnection Customer’s responsibility to ensure that a voltage
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coordination study is performed, in coordination with Transmission Provider, and implemented with appropriate coordination settings prior to unit testing.
For areas with multiple generating facilities additional studies may be required to determine whether or not critical interactions, including but not limited to control systems, exist. These studies, to be coordinated with Transmission Provider, will be the responsibility of the Interconnection Customer. If the need for a master controller is identified, the cost and all
related installation requirements will be the responsibility of the Interconnection Customer. Participation by the generation facility in subsequent interaction/coordination studies will be required pre- and post-commercial operation in order ensure system reliability. Interconnection Requests that are 75 MVA or larger may be required to facilitate collection and validation of accurate modeling data to meet NERC modeling standards. The Transmission Provider, in its roles as the Planning Coordinator, requires Phasor Measurement Units (PMUs) at all new Generating Facilities with an individual or aggregate nameplate capacity of 75 MVA
or greater. In addition to owning and maintaining the PMU, the Generating Facility will be
responsible for collecting, storing (for a minimum of 90 days) and retrieving data as requested by the Planning Coordinator. Data must be stored for a minimum of 90 days. Data must be collected and be able to stream to Planning Coordinator for each of the Generating Facility’s step-up transformers measured on the low side of the GSU at a sample rate of at least 60
samples per second and synchronized within +/- 2 milliseconds of the Coordinated Universal
Time (UTC). Initially, the following data must be collected:
• Three phase voltage and voltage angle (analog)
• Three phase current (analog)
Data requirements are subject to change as deemed necessary to comply with local and federal regulations. All generators must meet the Federal Energy Regulatory Commission (FERC), NERC, and WECC low voltage ride-through requirements as specified in the interconnection agreement.
Inverters must be designed to stay connected to the grid in the case of severe faults and may
not momentarily cease output within the no-trip area of the voltage curves. Figure 1 illustrates the voltage ride-through capability as per NERC PRC-024. Importantly, inverters should be designed such that a trip outside of the curves is a “may-trip” area (if needed to protect equipment) not a “must-trip” area. Inverters that momentarily cease active power output for
these voltage excursions should be configured to restore output to pre-disturbance levels in no
greater than five seconds, provided the inverter is capable of these changes. Generators must provide test results to the Transmission Provider verifying that the inverters for this Project have been programmed to meet all PRC-024 requirements rather than manufacturer IEEE distribution standards.

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Figure 1 – Voltage Ride-Through Curve
As the Transmission Provider cannot submit a user written model to WECC for inclusion in
base cases, a standard model from the WECC Approved Dynamic Model Library is required 180 days prior to trial operation. The list of approved generator models is continually updated and is available on the http://www.WECC.biz website.
An Interconnection Customer with an Interconnection Request for a Generating Facility that
is both 75 MVA or larger as well as being interconnected at a voltage higher than 100 kV shall register with NERC as the Generator Owner (“GO”) and Generator Operator (“GOP”) for the Large Generating Facility and provide the Transmission Provider documentation demonstrating registration in order to be approved for Commercial Operation. This registration
must be maintained throughout the lifetime of the Interconnection Agreement.
Interconnection Customers are responsible for the protection of transmission lines between the Generating Facility and the POI substation. For Interconnection Requests that are smaller than 75 MVA or are interconnected at a voltage less than 100 kV which have a tie line that is longer
than 1,000 feet the Interconnection Customer shall construct and own a tie-line substation to
be located at the change of ownership (separate fenced facility adjacent to the Transmission Provider’s POI substation). The tie line substation shall include an Interconnection Customer owned protective device and associated transmission line relaying/communications. The ground grids of the Transmission Provider’s POI substation and the Interconnection
Customer’s tie-line substation will be connected to support the use of a bus differential
protection scheme which will protect the overhead bus connection between the two facilities.
4.0 CLUSTER AREA DEFINITIONS
The Transmission Provider performed the Transition Cluster Study based on geographically and/or electrically relevant areas on the Transmission Provider’s Transmission System known as Cluster
Areas. The Transmission Provider has determined that the Interconnection Requests discussed in
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Section 5.0 are located in a geographically and/or electrically relevant area on Transmission Provider’s Transmission System, and thus, were assigned Cluster Area 8 in the Transition Cluster
Study process.
5.0 CLUSTER AREA 8
Cluster Area 8 (CA8) generally covers the geographic area of the Transmission Provider’s system referred to as the Prineville load pocket. This Cluster Area consists of the following Interconnection Requests:
5.1 Description of Interconnection Request – TCS-43
The Interconnection Customer has proposed to interconnect 40 megawatts (“MW”) of new generation to PacifiCorp’s (“Transmission Provider”) Stearns Butte 115 kV substation located in Crook County, Oregon. The Interconnection Request is proposed to consist of thirty-two (32) Ingeteam Ingecon Sun 1600TL B615 2,720 KVA inverters for a total requested output of
40 MW at the POI. The Interconnection Request also consists of a Tesla Megapack 40 MW battery storage with no capability to charge from the Transmission Provider’s grid. The requested commercial operation date is December 30, 2022. Figure 2 below, is a one-line diagram that illustrates the interconnection of the proposed Large Generating Facility to the Transmission Provider’s system.
Interconnection Customer will operate this generator as a Qualified Facility as defined by the Public Utility Regulatory Policies Act of 1978 (PURPA). The Interconnection Request will be studied for Network Resource Interconnection Service
(“NRIS”). The Transmission Provider has assigned the Project Cluster Number “TCS-43”
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Point of Interconnection
Stearns Butte
Substation
Houston Lake Substation
Ponderosa Substation
Q-0850 collectorSubstation
Change of OwnershipM
115 kV
34.5 kV
615 V
2.75 MVA Z=5.75%
1.336 MW DC/AC
615 V
2.75 MVA Z=5.75%
1.336 MW DC/AC
615 V
2.75 MVA Z=5.75%
1.336 MW DC/AC
615 V
2.75 MVA Z=5.75%
1.336 MW DC/AC
615 V
2.75 MVA Z=5.75%
1.336 MW DC/AC
2.75 MVA Z=5.75%
1.336 MW DC/AC
615 V
52CAP(optional)
32InvertersTotal
16Inverters 16Inverters+=
M MMBatteries(Future)
TCS-43
30/40/50 MVAZ = 7.5 %
TCS-45
M
Facility Substation
CS
CS
Figure 2: Simplified System One Line Diagram
5.2 Description of Interconnection Request – TCS-44
The Interconnection Customer has proposed to interconnect 80 MW of new generation to the Transmission Provider’s Ponderosa 115 kV substation located in Crook County, Oregon. The Interconnection Request is proposed to consist of sixty-four (64) Ingeteam Ingecon Sun
1600TL B615 2,720 KVA inverters for a total requested output of 80 MW at the POI. The Interconnection Request also consists of a Tesla Megapack 80 MW battery storage with no capability to charge from the Transmission Provider’s grid. The requested commercial operation date is December 30, 2022. Figure 3 below, is a one-line diagram that illustrates the
interconnection of the proposed Large Generating Facility to the Transmission Provider’s
system.
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Interconnection Customer will operate this generator as a Qualified Facility as defined by the Public Utility Regulatory Policies Act of 1978 (PURPA).
The Interconnection Request will be studied for Network Resource Interconnection Service (“NRIS”). The Transmission Provider has assigned the Project Cluster Number “TCS-44”

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115 kV
Ponderosa
Substation
230 kV
230 kV
Stearns Butte

M
Q0443
Gala Solar Q0824Q0734

TCS-44
TCS-52,53,54
Q0731
Change of Ownership
M
65/80/90 MVAZ = 7.5 %
34.5 kV
615 V
2.75 MVA Z=5.75%
1.336 MW DC/AC
615 V
2.75 MVA Z=5.75%
1.336 MW DC/AC
615 V
2.75 MVA Z=5.75%
1.336 MW DC/AC
615 V
2.75 MVA Z=5.75%
1.336 MW DC/AC
615 V
2.75 MVA Z=5.75%
1.336 MW DC/AC
2.75 MVA Z=5.75%
1.336 MW DC/AC
615 V
52CAP(optional)
16Inverters 16Inverters+=
2.75 MVA Z=5.75%
1.336 MW DC/AC
615 V
2.75 MVA Z=5.75%
1.336 MW DC/AC
2.75 MVA Z=5.75%
1.336 MW DC/AC
615 V
2.75 MVA Z=5.75%
1.336 MW DC/AC
615 V
2.75 MVA Z=5.75%
1.336 MW DC/AC
2.75 MVA Z=5.75%
1.336 MW DC/AC
615 V
16Inverters 16Inverters++64Inverters
0.5 mi
M M M M M
Batteries(Future)
230 kV
Figure 3: Simplified System One Line Diagram
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Transition Cluster Area 8 Page 10 September 17, 2021

5.3 Description of Interconnection Request – TCS-45
The Interconnection Customer has proposed to interconnect 40 MW of new generation to the
Transmission Provider’s Stearns Butte 115 kV substation located in Crook County, Oregon. The Interconnection Request is proposed to consist of thirty-two (32) Ingeteam Ingecon Sun 1600TL B615 2,720 KVA inverters for a total requested output of 40 MW at the POI. The Interconnection Request also consists of a Tesla Megapack 40 MW battery storage with no capability to charge from the Transmission Provider’s grid. The requested commercial
operation date is May 30, 2023. Figure 4 below, is a one-line diagram that illustrates the interconnection of the proposed Large Generating Facility to the Transmission Provider’s system. Interconnection Customer will operate this generator as a Qualified Facility as defined by the
Public Utility Regulatory Policies Act of 1978 (PURPA). The Interconnection Request will be studied for Network Resource Interconnection Service (“NRIS”).
The Transmission Provider has assigned the Project Cluster Number “TCS-45”

Point of Interconnection
Stearns Butte
Substation
Houston Lake Substation
Ponderosa Substation
Q-0850 collectorSubstation
Change of OwnershipM
115 kV
34.5 kV
16Inverters16Inverters
32Inverters
TCS-45
30/40/50 MVAZ = 7.5 %
M M M
TCS-43
M
Facility Substation
CS
CS
Figure 4: Simplified System One Line Diagram
System Impact Study Report
Transition Cluster Area 8 Page 11 September 17, 2021

5.4 Description of Interconnection Request – TCS-52
The Interconnection Customer has proposed to interconnect 20 MW of new generation to the
Transmission Provider’s Ponderosa 115 kV substation located in Crook County, Oregon. The Interconnection Request is proposed to consist of eight (8) 2,500 KVA Sungrow SG2500 solar inverters for a total nameplate output of 20 MW at the POI. The requested commercial operation date is May 1, 2023. Figure 7 below, is a one-line diagram that illustrates the interconnection of the proposed Small Generating Facility to the Transmission Provider’s
system. Interconnection Customer will operate this generator as a Qualified Facility as defined by the Public Utility Regulatory Policies Act of 1978 (PURPA).
The Interconnection Request will be studied for Network Resource Interconnection Service (“NRIS”). The Transmission Provider has assigned the Project Cluster Number “TCS-52”

115 kV
Ponderosa Substation
230 kV
230 kV
Stearns Butte

M
Q0443
Gala Solar Q0824Q0734

230 kV
Q0731
TCS-44
M
Change of Ownership
TCS-52
390 V
2500 kWDC/AC
390 V
2500 kWDC/AC
2.5 MVA Z=5.75%
390 V
2500 kWDC/AC
390 V
2500 kWDC/AC
2.5 MVA Z=5.75%2.5 MVA Z=5.75%
390 V390 V
2500 kWDC/AC
390 V
2500 kWDC/AC
2.5 MVA Z=5.75%
390 V
2500 kWDC/AC 2500 kWDC/AC
2.5 MVA Z=5.75%2.5 MVA Z=5.75%2.5 MVA Z=5.75%2.5 MVA Z=5.75%
34.5 kV
18/20/24 MVAZ = 7.5 %
TCS-54
TCS-53 M
CS
CS
CS
Facility Substation
Figure 7: Simplified System One Line Diagram
5.5 Description of Interconnection Request – TCS-53
The Interconnection Customer has proposed to interconnect 20 MW of new generation to the
Transmission Provider’s Ponderosa 115 kV substation located in Crook County, Oregon. The Interconnection Request is proposed to consist of eight (8) 2,500 KVA Sungrow SG2500 solar inverters for a total nameplate output of 20 MW at the POI. The requested commercial operation date is May 1, 2023. Figure 8 below, is a one-line diagram that illustrates the
interconnection of the proposed Small Generating Facility to the Transmission Provider’s
system.
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Transition Cluster Area 8 Page 12 September 17, 2021

Interconnection Customer will operate this generator as a Qualified Facility as defined by the Public Utility Regulatory Policies Act of 1978 (PURPA).
The Interconnection Request will be studied for Network Resource Interconnection Service (“NRIS”). The Transmission Provider has assigned the Project Cluster Number “TCS-53”

115 kV
Ponderosa Substation
230 kV
230 kV
Stearns Butte

M
Q0443
Gala Solar Q0824Q0734

230 kV
Q0731
TCS-44
M
Change of Ownership
TCS-53
18/20/24 MVAZ = 7.5 %
390 V
2500 kWDC/AC
390 V
2500 kWDC/AC
2.5 MVA Z=5.75%
390 V
2500 kWDC/AC
390 V
2500 kWDC/AC
2.5 MVA Z=5.75%2.5 MVA Z=5.75%
390 V390 V
2500 kWDC/AC
390 V
2500 kWDC/AC
2.5 MVA Z=5.75%
390 V
2500 kWDC/AC 2500 kWDC/AC
2.5 MVA Z=5.75%2.5 MVA Z=5.75%2.5 MVA Z=5.75%2.5 MVA Z=5.75%
34.5 kV
M
TCS-52
CS
CS
CS
Facility Substation
TCS-54
Figure 8: Simplified System One Line Diagram
5.6 Description of Interconnection Request – TCS-54
The Interconnection Customer has proposed to interconnect 40 MW of new generation to the Transmission Provider’s Ponderosa 115 kV substation located in Crook County, Oregon. The Interconnection Request is proposed to consist of thirty-two (32) Ingeteam Ingecon Sun 1600TL B615 2,720 KVA inverters for a total requested output of 40 MW at the POI. The Interconnection Request also consists of a Tesla Megapack 40 MW battery storage with no
capability to charge from the Transmission Provider’s grid. The requested commercial operation date is May 30, 2024. Figure 9 below, is a one-line diagram that illustrates the interconnection of the proposed Large Generating Facility to the Transmission Provider’s system.
Interconnection Customer will operate this generator as a Qualified Facility as defined by the Public Utility Regulatory Policies Act of 1978 (PURPA). The Interconnection Request will be studied for Network Resource Interconnection Service (“NRIS”).
The Transmission Provider has assigned the Project Cluster Number “TCS-54”
System Impact Study Report
Transition Cluster Area 8 Page 13 September 17, 2021

115 kV
Ponderosa Substation
230 kV
230 kV
Stearns Butte

M
Q0443
Gala Solar Q0824Q0734

230 kV
Q0731
TCS-44
M
Change of Ownership
34.5 kV
16Inverters16Inverters
32Inverters
TCS-54
30/40/50 MVAZ = 7.5 %
MMM
Batteries(Future)
M
TCS-52
CS
CS
CS
TCS-53
Facility Substation

System Impact Study Report
Transition Cluster Area 8 Page 14 September 17, 2021

Figure 9: Simplified System One Line Diagram
6.0 SITE SPECIFIC GENERATING FACILITY REQUIREMENTS
TCS-52 and TCS-53 The winding configuration of the step-up transformer, 115 – 34.5 kV transformer, shown in the
Generation Interconnection application will not be acceptable for this project. The step-up
transformer must be a source of ground current for phase to ground faults on the 115 kV transmission system. The transformer will be required to have a wye winding on the 115 kV side, with the neutral grounded, and a delta on the 34.5 kV side. If a ground reference is needed for the 34.5 kV system, then a grounding transformer could be added or a three winding transformer could
be used for the step-up transformer. The three winding transformer would have wye winding with
the neutrals ground for both the 115 kV and 34.5 kV side along with a delta tertiary winding.
7.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS
7.1 Transmission System Requirements
The following transmission system improvements are required to accommodate the
Interconnection Requests in this Cluster Area:
• Expansion of the 115 kV yard to the east at Ponderosa substation (0 MW additional cluster generation can be accommodated without this transmission upgrade)
• Addition of a new 230 kV transmission line between Ponderosa substation to Corral
substation.
• Addition of a third 280 MVA, 230-115 kV transformer at Ponderosa substation. o Up to 55 MW total cluster generation can be accommodated without this transmission upgrade.

Note: existing mitigation procedures in place for this area may warrant curtailment of all TCA-8 generation to 0 MW following the loss of a single element to avoid overloads for a subsequent outage.
Refer to Appendix 1 for more details regarding the necessity for these required upgrades.
The Transmission Provider observed overloads on Bonneville Power Administration’s (“BPA”) 500-230 kV transformer after the addition of CA8 generation. These overloads are
subject to verification by an Affected System study performed by BPA. Identification of overloads outside the Transmission Provider’s system are for informational purposes only.
System Impact Study Report
Transition Cluster Area 8 Page 15 September 17, 2021

115 kV
Ponderosa Substation
230 kV
230 kV
Stearns Butte

M
Q0443
Gala Solar Q0824Q0734

TCS-44
TCS-52,53,54
230 kVCorral
Q0731
Corral Substation
Ponderosa
Ponderosa (BPA)
Ponderosa (BPA)
Ochoco
Q0731
Figure 10: System one line diagram
In addition to the requirements described above, the following construction is required for the specific Interconnection Requests listed below. TCS-43 and TCS 45 Create a new line position on the existing ring bus layout at Stearns Butte substation. This new
line position will accommodate both TCS-43 and TCS 45 via a shared transmission tie line. TCS-44, TCS-52, TCS-53, and TCS-54 The existing 115 kV yard at Ponderosa substation will be expanded to allow the construction of two new line positions. One new line position will accommodate TCS-44, and the other
line position will accommodate TCS-52, TCS-53, and TCS-54 via a shared transmission tie line.
7.2 Distribution System Requirements
There are no distribution upgrades required in this Cluster Area.
7.3 Transmission Line Requirements
The addition of a new 230 kV transmission line between the Transmission Provider’s Ponderosa substation and Corral substation is required. The poles for this additional transmission line already exist as they were previously constructed as part of a double circuit line, however the conductor for this additional circuit was not installed. The conductor for this
additional circuit will need to be installed as part of the work for this Cluster group.
The last structure of each of the Interconnection Customer tie lines outside the Transmission Provider POI substations shall be constructed to Transmission Provider standards. The Interconnection Customers shall coil enough fiber and conductor on the last deadend structure
to make the span into the POI substations. The Transmission Provider shall construct the final
terminations into the POI substations and own the final span across the substation fence.
7.4 Existing Circuit Breaker Upgrades – Short Circuit
TCS-43
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Transition Cluster Area 8 Page 16 September 17, 2021

The increase in the fault duty on the system as the result of the addition of the Generating Facility with photovoltaic arrays fed through 32 – 2750 kVA inverters connected 32 – 34.5 kV
– 615 V 2750 kVA transformers with 5.75 % impedance and then through a 115 – 34.5 kV 30/40/50 MVA transformer with 7.5 % impedance will not push the fault duty above the interrupting rating of any of the existing fault interrupting equipment. TCS-44
The increase in the fault duty on the system as the result of the addition of the Generating Facility with photovoltaic arrays fed through 64 – 2750 kVA inverters connected 64 – 34.5 kV – 615 V 2750 kVA transformers with 5.75 % impedance and then through a 115 – 34.5 kV 65/80/95 MVA transformer with 7.5 % impedance will not push the fault duty above the interrupting rating of any of the existing fault interrupting equipment.
TCS-45 The increase in the fault duty on the system as the result of the addition of the Generating Facility with photovoltaic arrays fed through 32 – 2750 kVA inverters connected 32 – 34.5 kV – 615 V 2750 kVA transformers with 5.75 % impedance and then through a 115 – 34.5 kV
30/40/50 MVA transformer with 7.5 % impedance will not push the fault duty above the interrupting rating of any of the existing fault interrupting equipment. TCS-52 The increase in the fault duty on the system as the result of the addition of the Generating
Facility with photovoltaic arrays fed through 8 – 2500 kVA inverters connected 8 – 34.5 kV – 390 V 2500 kVA transformers with 5.75 % impedance and then through a 115 – 34.5 kV 18/20/24 MVA transformer with 7.5 % impedance will not push the fault duty above the interrupting rating of any of the existing fault interrupting equipment.
TCS-53 The increase in the fault duty on the system as the result of the addition of the Generating Facility with photovoltaic arrays fed through 8 – 2500 kVA inverters connected 8 – 34.5 kV – 390 V 2500 kVA transformers with 5.75 % impedance and then through a 115 – 34.5 kV 18/20/24 MVA transformer with 7.5 % impedance will not push the fault duty above the
interrupting rating of any of the existing fault interrupting equipment. TCS-54 The increase in the fault duty on the system as the result of the addition of the Generating Facility with photovoltaic arrays fed through 32 – 2750 kVA inverters connected 32 – 34.5 kV
– 615 V 2750 kVA transformers with 5.75 % impedance and then through a 115 – 34.5 kV 30/40/50 MVA transformer with 7.5 % impedance will not push the fault duty above the interrupting rating of any of the existing fault interrupting equipment.
7.5 Protection Requirements
At Ponderosa substation, modify the north and south bus differential logic to add the new
expanded 115 kV bay breakers.
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Transition Cluster Area 8 Page 17 September 17, 2021

The new 230 kV line out of Ponderosa to Corral substation will have 411Ls with current differential protection scheme. The CTs on the high side of Ponderosa #3 transformer will be
connected to 411Ls. These relays protect the section of the line between Corral substation and the high side of Ponderosa transformer #3. Any faults in this section of the line will trip the low side breakers at Ponderosa and the 230 kV breakers at Corral substation. Transformer differential protection with redundant SEL-387E relays will be implemented on
the 230-115 kV transformer #3 at Ponderosa. For internal faults in the Ponderosa transformer #3, the respective transformer lockout will trip the low side breakers and send a transfer trip to the breakers at Corral substation via the 411L relays. TCS-43,45 The tie-line between Stearns Butte and the Interconnection Customers’ shared facilities substation will be protected with a current differential scheme. Transmission line relays will need to be installed at Stearns Butte substation and a panel with compatible line relays will be
installed in the Transmission Provider’s shared facilities substation control building.
Relay elements for under/over voltage and over/under frequency protection of the system will be enabled in the line relays for the tie line to the collector substation installed at Stearns Butte substation. If the voltage, magnitude or frequency, is outside of the normal operation range
these relay elements will cause the tripping of the 115 kV breakers at Stearns Butte substation
for the tie line to the collector substation. TCS-44 The Interconnection Customer’s tie line between the Large Generating Facility substation and
Ponderosa substation will be protected with a line current differential relay system. A panel
containing the line relay equipment is to be installed in the Transmission Provider collector substation control building that will communicate with the relay equipment at Ponderosa substation for detecting faults on the tie line. The relays in this panel will be connected to the Interconnection Customer’s current transformers, 115 kV voltage transformers, 115 kV
breaker trip circuit, and a DC power source.
In addition, the line relaying is also used for under/over voltage and over/under frequency protection of the system will be installed in Ponderosa substation. If the voltage, magnitude or frequency is outside of the normal operation range, this relay will send a trip signal over the
optical fiber cable to trip the breaker at Interconnection Customer’s collector substation. TCS-52,53,54 The tie-line between Ponderosa and the Interconnection Customers’ shared facilities substation will be protected with current differential scheme. Transmission line relays will need to be
installed at Ponderosa substation and a panel with compatible line relays will be installed in
the Transmission Provider’s shared facilities substation control building. Relay elements for under/over voltage and over/under frequency protection of the system will be enabled in the line relays for the tie line to the collector substation installed at Ponderosa
substation. If the voltage, magnitude or frequency, is outside of the normal operation range
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Transition Cluster Area 8 Page 18 September 17, 2021

these relay elements will cause the tripping of the 115 kV breakers at Ponderosa substation for the tie line to the collector substation.
7.6 Data (RTU) Requirements
Ponderosa Substation Add additional rack, I/O cards and aux power supply to existing dual ported RTU. Update RTU legacy protocols to DNP.
Install a primary and backup data concentrator in the new control building for the integration of the metering below. Analogs from meters at Ponderosa substation for TCS 52, 53, 54 (1 Primary and 1 Backup):
• Net Generation real power MW
• Net Generator reactive power MVAR
• Energy Register KWH
• A phase 115 kV voltage
• B phase 115 kV voltage
• C phase 115 kV voltage
Analogs from meters at Ponderosa substation for TCS 44 (1 Primary and 1 Backup):
• Net Generation real power MW
• Net Generator reactive power MVAR
• Energy Register KWH
• A phase 115 kV voltage
• B phase 115 kV voltage
• C phase 115 kV voltage

Stearns Butte Sub
Install a primary and backup data concentrator for the integration of the metering below.
Analogs from meters at Stearns Butte (1 Primary and 1 Backup):
• Net Generation real power MW
• Net Generator reactive power MVAR
• Energy Register KWH
• A phase 115 kV voltage
• B phase 115 kV voltage
• C phase 115 kV voltage TCS43 and TCS-45 Shared Facility Substation
Data for the operation of the power system will be required from the Interconnection
Customer’s generating facility and collector substation. The Interconnection Customer will install a data concentrator and hard wire it to all source devices. Transmission Provider approved fiber optic cable will be installed from the data concentrator to the POI substation. The Transmission Provider will install an RTU here as well to integrate the Transmission
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Transition Cluster Area 8 Page 19 September 17, 2021

Provider’s comm equipment alarms into their EMS. The following points will be required which are subject to change based on the Interconnection Customer’s final design:

Status:
• 115 kV Circuit Switcher 1
• 115 kV Circuit Switcher 2
• 115 kV Facility Circuit Breaker TCS-43 Collector Substation From the collector station, the following points will be required which are subject to change
based on the Interconnection Customer’s final design: Analogs:
• Global Horizontal Irradiance (GHI)
• Average Plant Atmospheric Pressure (Bar)
• Average Plant Temperature (Celsius)
• Max Generator Limit MW (set point control)
• Potential Power MW Status:
• 34.5 kV Circuit Breaker 1
• 34.5 kV Circuit Breaker 2
• 34.5 kV Battery Circuit Breaker
• 34.5 kV Transformer Breaker
• 115 kV Transformer Breaker
• 34.5 kV Cap Bank Circuit Breaker (Optional) Analogs from meters at the TCS-43 collector site (4 Primary and 4 Backup):
• Net Generation real power MW
• Net Generator reactive power MVAR
• Energy Register KWH
• A phase 34.5 kV voltage
• B phase 34.5 kV voltage
• C phase 34.5 kV voltage TCS-45 Collector Substation
From the collector station, the following points will be required which are subject to change
based on the Interconnection Customer’s final design: Analogs:
• Global Horizontal Irradiance (GHI)
• Average Plant Atmospheric Pressure (Bar)
• Average Plant Temperature (Celsius)
• Max Generator Limit MW (set point control)
• Potential Power MW
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Transition Cluster Area 8 Page 20 September 17, 2021

Status:
• 34.5 kV Circuit Breaker 1
• 34.5 kV Circuit Breaker 2
• 34.5 kV Battery Circuit Breaker
• 34.5 kV Transformer Breaker
• 115 kV Transformer Breaker
• 34.5 kV Cap Bank Circuit Breaker (Optional)
Analogs from meters at the TCS-45 collector site (4 Primary and 4 Backup):
• Net Generation real power MW
• Net Generator reactive power MVAR
• Energy Register KWH
• A phase 34.5 kV voltage
• B phase 34.5 kV voltage
• C phase 34.5 kV voltage TCS-44 Collector Substation Data for the operation of the power system will be required from the Interconnection
Customer’s generating facility and collector substation. The Interconnection Customer will install a data concentrator and hard wire it to all source devices. Transmission Provider approved fiber optic cable will be installed from the data concentrator to the POI substation. The Transmission Provider will install an RTU here as well to integrate the Transmission Provider’s comm equipment alarms into their EMS. The following points will be required
which are subject to change based on the Interconnection Customer’s final design: Analogs:
• Global Horizontal Irradiance (GHI)
• Average Plant Atmospheric Pressure (Bar)
• Average Plant Temperature (Celsius)
• Max Generator Limit MW (set point control)
• Potential Power MW Status:
• 34.5 kV Circuit Breaker 1
• 34.5 kV Circuit Breaker 2
• 34.5 kV Circuit Breaker 3
• 34.5 kV Circuit Breaker 4
• 34.5 kV Battery Circuit Breaker
• 34.5 kV Transformer Breaker
• 115 kV Transformer Breaker
• 34.5 kV Cap Bank Circuit Breaker (Optional) TCS-52, TCS-53 and TCS-54 Shared Facility Substation Data for the operation of the power system will be required from the Interconnection
Customer’s generating facility and collector substation. The Interconnection Customer will
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Transition Cluster Area 8 Page 21 September 17, 2021

install a data concentrator and hard wire it to all source devices. Transmission Provider approved fiber optic cable will be installed from the data concentrator to the POI substation.
The Transmission Provider will install an RTU here as well to integrate the Transmission Provider’s comm equipment alarms into their EMS. The following points will be required which are subject to change based on the Interconnection Customer’s final design: Analogs:
• Global Horizontal Irradiance (GHI)
• Average Plant Atmospheric Pressure (Bar)
• Average Plant Temperature (Celsius)
• Max Generator Limit MW (set point control)
• Potential Power MW
Status:
• 115 kV Circuit Switcher 1
• 115 kV Circuit Switcher 2
• 115 kV Circuit Switcher 3
• 115 kV Facility Circuit Breaker TCS-52 Collector Substation Analogs:
• Global Horizontal Irradiance (GHI)
• Average Plant Atmospheric Pressure (Bar)
• Average Plant Temperature (Celsius)
• Max Generator Limit MW (set point control)
• Potential Power MW
Status:
• 34.5 kV Transformer Breaker
• 115 kV Transformer Breaker
Analogs from meters at the TCS-52 collector site (1 Primary and 1 Backup):
• Net Generation real power MW
• Net Generator reactive power MVAR
• Energy Register KWH
• A phase 115 kV voltage
• B phase 115 kV voltage
• C phase 115 kV voltage TCS-53 Collector Substation Analogs:
• Global Horizontal Irradiance (GHI)
• Average Plant Atmospheric Pressure (Bar)
• Average Plant Temperature (Celsius)
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Transition Cluster Area 8 Page 22 September 17, 2021

• Max Generator Limit MW (set point control)
• Potential Power MW Status:
• 34.5 kV Transformer Breaker
• 115 kV Transformer Breaker Analogs from meters at the TCS-53 collector site (1 Primary and 1 Backup):
• Net Generation real power MW
• Net Generator reactive power MVAR
• Energy Register KWH
• A phase 115 kV voltage
• B phase 115 kV voltage
• C phase 115 kV voltage TCS-54 Collector Substation Analogs:
• Global Horizontal Irradiance (GHI)
• Average Plant Atmospheric Pressure (Bar)
• Average Plant Temperature (Celsius)
• Max Generator Limit MW (set point control)
• Potential Power MW
Status:
• 34.5 kV Circuit Breaker 1
• 34.5 kV Circuit Breaker 2
• 34.5 kV Battery Circuit Breaker
• 34.5 kV Transformer Breaker
• 115 kV Transformer Breaker
• 34.5 kV Cap Bank Circuit Breaker (Optional) Analogs from meters at the TCS-54 collector site (4 Primary and 4 Backup):
• Net Generation real power MW
• Net Generator reactive power MVAR
• Energy Register KWH
• A phase 115 kV voltage
• B phase 115 kV voltage
• C phase 115 kV voltage

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Transition Cluster Area 8 Page 23 September 17, 2021

7.7 Substation Requirements
Corral Substation
Construct a new line position to feed a third 230/115kV transformer in the Ponderosa substation. The following substation equipment has been identified as required for this improvement: (2) 230 kV Circuit Breaker
(4) 230 kV Horizontal Mount Vertical Break Group Operated Switches (1) 230 kV Vertical Mount Vertical Break Group Operated Switch (1) 125 VDC Motor Operator (3) 230 kV CCVT (3) 230 kV Lightning Arresters
Ponderosa Substation Install a new 230/115kV transformer. Transformer installation will require expansion of the substation and the following major equipment:
(1) 230/115 kV 250 MVA Transformer (1) 230 kV Horizontal Mount Vertical Break Group Operated Switch (1) 125 VDC Motor Operator (3) 115 kV CCVT (7) 115 kV Vertical Break Group Operated Switch
(3) 145 kV Circuit Breakers (1) 28’ X 40’ Control Building (1) 125 VDC Battery Bank TCS-43 and TCS-45
Stearns Butte Substation The Interconnection Requests will require an additional breaker in the Stearns Butte substation ring bus to create a line position for the shared TCS-43, 45 tie line. The following substation equipment has been identified as required and may change during detailed design:
(1) 145 kV Circuit Breaker (4) 115 kV Vertical Break Group Operated Switch (1) 125 VDC Motor Operator (3) CT/VT Combo Metering Units (3) 115 kV Lightning Arresters
TCS-43 and TCS-45 Shared Facility Substation The Interconnection Customer will provide a separate graded, grounded and fenced area along the perimeter of the Interconnection Customers’ shared facility substation for the Transmission Provider to install a control building for metering, protection and communication equipment.
This area will share a fence and ground grid with the Interconnection Customer substation and have separate, unencumbered access for the Transmission Provider. The Interconnection Customer shall perform and provide a CDEGS grounding analysis. The Interconnection Customer shall procure AC service for the Transmission Provider building. DC power for the
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Transition Cluster Area 8 Page 24 September 17, 2021

control building will be supplied by the Transmission Provider. The Interconnection Customer shall provide a disconnect switch on each side of each metering of the Transmission Provider’s
instrument transformers. The Interconnection Customer will provide the necessary easements
for the Transmission Provider control building. TCS-44 Ponderosa Substation
One new line position will be required at Ponderosa substation for this Interconnection Requests. The Ponderosa ground grid shall be connected to the customer single breaker tie line substation. The following major equipment has been identified as required and may change during detailed design:
(2) 145 kV Circuit Breakers (3) 115 kV Vertical Break Group Operated Switches (3) CT/VT Combination Metering Units (3) 115 kV Surge Arresters (1) 125 VDC Motor Operator
(1) 115 kV, Vertical Mount Vertical Break Group Operated Line Disconnect Switch with Ground Switch. TCS-44 Collector Substation The Interconnection Customer will provide a separate graded, grounded and fenced area along
the perimeter of the Interconnection Customer’s collector substation for the Transmission Provider to install a control building for metering, protection and communication equipment. This area will share a fence and ground grid with the Interconnection Customer collector substation and have separate, unencumbered access for the Transmission Provider. The Interconnection Customer shall perform and provide a CDEGS grounding analysis. The
Interconnection Customer shall procure AC service for the Transmission Provider building. DC power for the control building will be supplied by the Transmission Provider. The Interconnection Customer shall provide a disconnect switch on each side of each metering of the Transmission Provider’s instrument transformers. The Interconnection Customer will provide the necessary easements for the Transmission Provider control building.
TCS-52, TCS-53, and TCS-54 Ponderosa Substation One new line position will be required in Ponderosa substation for these Interconnection Requests. The following major equipment has been identified as required and may change
during detailed design: (1) 115 kV Vertical Break Group Operated Switch (1) 145 kV Circuit Breakers (3) CT/VT Combination Metering Unit
(3) 115 kV Lightning Arresters (1) 115 kV, Vertical Mount Vertical Break Group Operated Line Disconnect Switch With Ground Switch (1) 125 VDC Motor Operator
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Transition Cluster Area 8 Page 25 September 17, 2021

TCS-52, TCS-53, and TCS-54 Shared Facility Substation
The Interconnection Customer will provide a separate graded, grounded and fenced area along the perimeter of the Interconnection Customers’ shared facility substation for the Transmission Provider to install a control building for metering, protection and communication equipment. This area will share a fence and ground grid with the Interconnection Customer substation and have separate, unencumbered access for the Transmission Provider. The Interconnection
Customer shall perform and provide a CDEGS grounding analysis. The Interconnection Customer shall procure AC service for the Transmission Provider building. DC power for the control building will be supplied by the Transmission Provider. The Interconnection Customer shall provide a disconnect switch on each side of each metering of the Transmission Provider’s instrument transformers. The Interconnection Customer will provide the necessary easements
for the Transmission Provider control building.
7.8 Communication Requirements
TCS-44 The Interconnection Customer will install fiber from their generation SCADA data concentrator to the fiber patch panel, the fiber will be terminated with an optical transceiver at
the data concentrator. The generation customer shall install sufficient fiber between the generation metering and the collector substation to support direct serial and IP connections to each meter. The transmission provider will install network communications equipment for line protection and metering in a dedicated rack. Battery backup and associated charger system will be required for the communications equipment.

The Interconnection Customer will install Transmission Provider approved fiber optic cable on its transmission line from the Transmission Provider’s collector substation control building to the last tie line structure outside the POI substation. The Interconnection Customer shall leave a sufficient quantity of fiber on its final structure outside the POI substation to allow the
Transmission Provider to terminate the fiber into the POI substation control building. The
Transmission Provider will own and maintain the fiber. The Interconnection Customer shall provide any necessary easement(s) for the Transmission Provider’s fiber. TCS-43
The Interconnection Customer shall install Transmission Provider approved fiber optic cable from each of the Transmission Provider’s metering cabinets and splice to fiber optic cable to be installed on the Interconnection Customer tie line. The Interconnection Customer shall install a data concentrator and hard wire all source devices requiring SCADA points to the data concentrator. The Interconnection Customer will install fiber from its data concentrator to a
splice with the Transmission Provider’s tie line fiber. The Interconnection Customer shall install Transmission Provider approved fiber optic cable on the tie line between the TCS-43 collector substation and the shared facility substation. This fiber will be owned and maintained by the Transmission Provider. The Interconnection
Customer shall provide any necessary easements for the Transmission Provider’s fiber on the tie line.
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TCS-45 The Interconnection Customer shall install Transmission Provider approved fiber optic cable
from each of the Transmission Provider’s metering cabinets and splice to fiber optic cable to be installed on the Interconnection Customer tie line. The Interconnection Customer shall install a data concentrator and hard wire all source devices requiring SCADA points to the data concentrator. The Interconnection Customer will install fiber from its data concentrator to a splice with the Transmission Provider’s tie line fiber.
The Interconnection Customer shall install Transmission Provider approved fiber optic cable on the tie line between the TCS-45 collector substation and the shared facility substation. This fiber will be owned and maintained by the Transmission Provider. The Interconnection Customer shall provide any necessary easements for the Transmission Provider’s fiber on the
tie line. TCS-43 and TCS-45 Shared Facilities The Interconnection Customers will provide sufficient fiber from their respective tie lines into the shared facility substation for the Transmission Provider to terminate the runs of fiber into
the Transmission Provider’s shard facility substation control building. The Interconnection Customers shall provide sufficient fiber optic cable from the shared tie line to the POI substation for the Transmission Provider to terminate the fiber into the Transmission Provider’s shard facility substation control building.
The Interconnection Customers will install Transmission Provider approved fiber optic cable on the transmission line to the POI substation. The Interconnection Customer shall leave a sufficient quantity of fiber on its final structure outside the POI substation to allow the Transmission Provider to terminate the fiber into the POI substation control building. The Transmission Provider will own and maintain the fiber. The Interconnection Customer shall
provide any necessary easements for the Transmission Provider’s fiber. TCS-52 The Interconnection Customer shall install Transmission Provider approved fiber optic cable from each of the Transmission Provider’s metering cabinets and splice to fiber optic cable to
be installed on the Interconnection Customer tie line. The Interconnection Customer shall install a data concentrator and hard wire all source devices requiring SCADA points to the data concentrator. The Interconnection Customer will install fiber from its data concentrator to a splice with the Transmission Provider’s tie line fiber.
The Interconnection Customer shall install Transmission Provider approved fiber optic cable on the tie line between the TCS-52 collector substation and the shared facility substation. This fiber will be owned and maintained by the Transmission Provider. The Interconnection Customer shall provide any necessary easements for the Transmission Provider’s fiber on the tie line.
TCS-53 The Interconnection Customer shall install Transmission Provider approved fiber optic cable from each of the Transmission Provider’s metering cabinets and splice to fiber optic cable to
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be installed on the Interconnection Customer tie line. The Interconnection Customer shall install a data concentrator and hard wire all source devices requiring SCADA points to the data
concentrator. The Interconnection Customer will install fiber from its data concentrator to a splice with the Transmission Provider’s tie line fiber. The Interconnection Customer shall install Transmission Provider approved fiber optic cable on the tie line between the TCS-53 collector substation and the shared facility substation. This
fiber will be owned and maintained by the Transmission Provider. The Interconnection Customer shall provide any necessary easements for the Transmission Provider’s fiber on the tie line. TCS-54
The Interconnection Customer shall install Transmission Provider approved fiber optic cable from each of the Transmission Provider’s metering cabinets and splice to fiber optic cable to be installed on the Interconnection Customer tie line. The Interconnection Customer shall install a data concentrator and hard wire all source devices requiring SCADA points to the data concentrator. The Interconnection Customer will install fiber from its data concentrator to a
splice with the Transmission Provider’s tie line fiber. The Interconnection Customer shall install Transmission Provider approved fiber optic cable on the tie line between the TCS-54 collector substation and the shared facility substation. This fiber will be owned and maintained by the Transmission Provider. The Interconnection
Customer shall provide any necessary easements for the Transmission Provider’s fiber on the tie line. TCS-52, TCS-53, and TSC-54 Shared Facilities The Interconnection Customers will provide sufficient fiber from their respective tie lines into
the shared facility substation for the Transmission Provider to terminate the runs of fiber into the Transmission Provider’s shard facility substation control building. The Interconnection Customers shall provide sufficient fiber optic cable from the shared tie line to the POI substation for the Transmission Provider to terminate the fiber into the Transmission Provider’s shard facility substation control building.
The Interconnection Customers will install Transmission Provider approved fiber optic cable on the transmission line to the POI substation. The Interconnection Customer shall leave a sufficient quantity of fiber on its final structure outside the POI substation to allow the Transmission Provider to terminate the fiber into the POI substation control building. The
Transmission Provider will own and maintain the fiber. The Interconnection Customer shall provide any necessary easements for the Transmission Provider’s fiber.
7.9 Metering Requirements
TCS-43 and TCS-45 Interchange Metering
The POI metering will be located at Stearns Butte substation and rated for the total net generation of the TCS-43 and TCS-45 Projects. The Transmission Provider will specify and order all interconnection revenue metering, including the instrument transformers, meters,
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meter panel, junction box, and secondary metering wire. The primary metering transformers will be combination 115 kV CT/VT units with extended range CTs for high-accuracy metering.
The metering design package will include two revenue quality meters with DNP real time digital data terminated at a metering interposition block. One meter will be designated as primary SCADA meter with DNP data delivered to the primary control center. A second meter will be designated as backup SCADA meter with DNP data delivered to the alternate control
center. The metering data will include bidirectional KWH and KVARH revenue quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps data. An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system. TCS-52, TCS-53 and TCS-54 Interchange Metering The POI metering will be located at Ponderosa substation and rated for the total net generation
of the TCS-52, TCS-53, and TCS-54 Projects. The Transmission Provider will specify and
order all interconnection revenue metering, including the instrument transformers, meters, meter panel, junction box, and secondary metering wire. The primary metering transformers will be combination 115kV CT/VT units with extended range CTs for high-accuracy metering.
The metering design package will include two revenue quality meters with DNP real time
digital data terminated at a metering interposition block. One meter will be designated as primary SCADA meter with DNP data delivered to the primary control center. A second meter will be designated as backup SCADA meter with DNP data delivered to the alternate control center. The metering data will include bidirectional KWH and KVARH revenue quantities.
The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage,
and per-phase amps data. An Ethernet connection is required for retail sales and generation accounting via the MV-90 translation system.
TCS-43 Project metering The project metering will be located at the Interconnection Customer collector substation on the high side of the GSU and rated for the total net generation of the Project. The Transmission
Provider will specify and order all interconnection revenue metering, including the instrument transformers, meters, meter enclosure, junction box, and secondary metering wire. The primary metering transformers will be combination 115kV CT/VT units with extended range CTs for high-accuracy metering.
The metering design package will include two revenue quality meters with DNP real time digital data terminated at a metering interposition block. One meter will be designated as primary SCADA meter with DNP data delivered to the primary control center. A second meter will be designated as backup SCADA meter with DNP data delivered to the alternate control
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center. The metering data will include bidirectional KWH and KVARH revenue quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage,
and per-phase amps data. Depending on the distance from the project site to the Point of Interconnection, a loss calculation may be added to the project metering.
An Ethernet connection is required for retail sales and generation accounting via the MV-90 translation system. Generator Metering The solar generator and battery storage are to be separately metered. Assuming the
Interconnection Customer supplied one line is correct, the two breakers for the solar generator, and the one breaker for the battery storage will be metered. This will require three metering points. The metering will be located at the Interconnection Customer’s collector substation, and each
metering point will be rated for its individual circuit of the Project. The Transmission Provider will specify and order all interconnection revenue metering, including the instrument transformers, meters, meter enclosures, junction boxes, and secondary metering wire. The primary metering transformers will be combination 34.5kV CT/VT units with extended range CTs for high-accuracy metering.

The metering design package will include two revenue quality meters for each meter point with DNP real time digital data terminated at a metering interposition block. One meter will be designated as primary SCADA meter with DNP data delivered to the primary control center. A second meter will be designated as backup SCADA meter with DNP data delivered to the
alternate control center. The metering data will include bidirectional KWH and KVARH
revenue quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps data. An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system. Station Service/Construction Power Prior to construction, Interconnection Customer must arrange construction power with the Transmission Provider holding the certificated service territory rights for the area in which the
load is physically located. Station service and temporary construction power metering shall conform to the Transmission Provider’s requirements. Please note, prior to back feed, Interconnection Customer must arrange retail meter service for electricity consumed by the Project with the Transmission Provider holding the certificated
service territory rights for the area in which the load is physically located. TCS-44 Interchange Metering
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The overall project metering will be located at Ponderosa substation and rated for the total net generation of the Project. The Transmission Provider will specify and order all interconnection
revenue metering, including the instrument transformers, meters, meter panel, junction box, and secondary metering wire. The primary metering transformers will be combination 115kV CT/VT units with extended range CTs for high-accuracy metering. The metering design package will include two revenue quality meters with DNP real time
digital data terminated at a metering interposition block. One meter will be designated as primary SCADA meter with DNP data delivered to the primary control center. A second meter will be designated as backup SCADA meter with DNP data delivered to the alternate control center. The metering data will include bidirectional KWH and KVARH revenue quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage,
and per-phase amps data. An Ethernet connection is required for retail sales and generation accounting via the MV-90 translation system.
Generator Metering
The solar generator and battery storage are to be separately metered. Assuming the Interconnection Customer supplied one line is correct, the four breakers for the solar generator, and the one breaker for the battery storage will be metered. This will require five metering points.

The metering will be located at the Interconnection Customer collector substation and each metering point will be rated for its individual circuit on the Project. The Transmission Provider will specify and order all interconnection revenue metering, including the instrument transformers, meters, meter panels, junction boxes, and secondary metering wire. The primary
metering transformers will be combination 34.5kV CT/VT units with extended range CTs for
high-accuracy metering. The metering design package will include two revenue quality meters for each meter point with DNP real time digital data terminated at a metering interposition block. One meter will be
designated as primary SCADA meter with DNP data delivered to the primary control center. A second meter will be designated as backup SCADA meter with DNP data delivered to the alternate control center. The metering data will include bidirectional KWH and KVARH revenue quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps data.
An Ethernet connection is required for retail sales and generation accounting via the MV-90 translation system. Station Service/Construction Power
Prior to construction, Interconnection Customer must arrange construction power with the Transmission Provider holding the certificated service territory rights for the area in which the load is physically located. Station service and temporary construction power metering shall conform to the Transmission Provider’s requirements.
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Please note, prior to back feed, Interconnection Customer must arrange retail meter service for
electricity consumed by the Project with the Transmission Provider holding the certificated service territory rights for the area in which the load is physically located. TCS-45 Project metering
The project metering will be located at the Interconnection Customer collector substation on the high side of the GSU and rated for the total net generation of the Project. The Transmission Provider will specify and order all interconnection revenue metering, including the instrument transformers, meters, meter enclosure, junction box, and secondary metering wire. The primary metering transformers will be combination 115kV CT/VT units with extended range CTs for
high-accuracy metering. The metering design package will include two revenue quality meters with DNP real time digital data terminated at a metering interposition block. One meter will be designated as primary SCADA meter with DNP data delivered to the primary control center. A second meter
will be designated as backup SCADA meter with DNP data delivered to the alternate control center. The metering data will include bidirectional KWH and KVARH revenue quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps data.
Depending on the distance from the project site to the Point of Interconnection, a loss calculation may be added to the project metering. An Ethernet connection is required for retail sales and generation accounting via the MV-90 translation system.

Generator Metering The solar generator and battery storage are to be separately metered. Assuming the Interconnection Customer supplied one line is correct, the two breakers for the solar generator, and the one breaker for the battery storage will be metered. This will require three metering
points. The metering will be located at the Interconnection Customer’s collector substation and each metering point will be rated for its individual circuit on the Project. The Transmission Provider will specify and order all interconnection revenue metering, including the instrument
transformers, meters, meter enclosures, junction boxes, and secondary metering wire. The primary metering transformers will be combination 34.5kV CT/VT units with extended range CTs for high-accuracy metering. The metering design package will include two revenue quality meters for each meter point with
DNP real time digital data terminated at a metering interposition block. One meter will be designated as primary SCADA meter with DNP data delivered to the primary control center. A second meter will be designated as backup SCADA meter with DNP data delivered to the alternate control center. The metering data will include bidirectional KWH and KVARH
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revenue quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps data.
An Ethernet connection is required for retail sales and generation accounting via the MV-90 translation system. Station Service/Construction Power
Prior to construction, Interconnection Customer must arrange construction power with the Transmission Provider holding the certificated service territory rights for the area in which the load is physically located. Station service and temporary construction power metering shall conform to the Transmission Provider’s requirements.
Please note, prior to back feed, Interconnection Customer must arrange retail meter service for electricity consumed by the Project with the Transmission Provider holding the certificated service territory rights for the area in which the load is physically located. TCS-52
Project Metering
The overall project metering will be located at the Interconnection Customer collector substation on the high side of the GSU and rated for the total net generation of the Project. The Transmission Provider will specify and order all interconnection revenue metering, including the instrument transformers, meters, meter enclosure, junction box, and secondary metering
wire. The primary metering transformers will be combination 115kV CT/VT units with
extended range CTs for high-accuracy metering. The metering design package will include two revenue quality meters with DNP real time digital data terminated at a metering interposition block. One meter will be designated as
primary SCADA meter with DNP data delivered to the primary control center. A second meter
will be designated as backup SCADA meter with DNP data delivered to the alternate control center. The metering data will include bidirectional KWH and KVARH revenue quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps data.
Depending on the distance from the project site to the Point of Interconnection, a loss calculation may be added to the project metering. An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system. Station Service/Construction Power According to the location description from the Interconnection Customer, this project is not in the Transmission Provider’s service territory. Central Electric Coop (“CEC”) appears to be the
service provider in the project area. Prior to approval of backfeed CEC will be required to submit a transmission service request to the Transmission Provider in order to wheel the retail power across the Transmission Provider’s system. Should CEC wish to gain access to the Transmission Provider’s meter data a request must be submitted to the Transmission Provider
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during the design phase of the project. The Transmission Provider will install communications equipment from the meters to the substation fence line where CEC can install a data collector.
Prior to construction, Interconnection Customer must arrange construction power with the Transmission Provider holding the certificated service territory rights for the area in which the load is physically located.
TCS-53
Project Metering The overall project metering will be located at the Interconnection Customer collector substation on the high side of the GSU and rated for the total net generation of the Project. The Transmission Provider will specify and order all interconnection revenue metering, including
the instrument transformers, meters, meter enclosure, junction box, and secondary metering wire. The primary metering transformers will be combination 115kV CT/VT units with extended range CTs for high-accuracy metering. The metering design package will include two revenue quality meters with DNP real time
digital data terminated at a metering interposition block. One meter will be designated as primary SCADA meter with DNP data delivered to the primary control center. A second meter will be designated as backup SCADA meter with DNP data delivered to the alternate control center. The metering data will include bidirectional KWH and KVARH revenue quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage,
and per-phase amps data. Depending on the distance from the project site to the Point of Interconnection, a loss calculation may be added to the project metering.
An Ethernet connection is required for retail sales and generation accounting via the MV-90 translation system. Station Service/Construction Power According to the location description from the Interconnection Customer, this project is not in
the Transmission Provider’s service territory. Central Electric Coop (“CEC”) appears to be the service provider in the project area. Prior to approval of backfeed CEC will be required to submit a transmission service request to the Transmission Provider in order to wheel the retail power across the Transmission Provider’s system. Should CEC wish to gain access to the Transmission Provider’s meter data a request must be submitted to the Transmission Provider
during the design phase of the project. The Transmission Provider will install communications equipment from the meters to the substation fence line where CEC can install a data collector. Prior to construction, Interconnection Customer must arrange construction power with the Transmission Provider holding the certificated service territory rights for the area in which the
load is physically located. TCS-54 Project Metering
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The overall project metering will be located at the Interconnection Customer collector substation on the high side of the GSU and rated for the total net generation of the Project. The
Transmission Provider will specify and order all interconnection revenue metering, including the instrument transformers, meters, meter enclosure, junction box, and secondary metering wire. The primary metering transformers will be combination 115kV CT/VT units with extended range CTs for high-accuracy metering.
The metering design package will include two revenue quality meters with DNP real time digital data terminated at a metering interposition block. One meter will be designated as primary SCADA meter with DNP data delivered to the primary control center. A second meter will be designated as backup SCADA meter with DNP data delivered to the alternate control center. The metering data will include bidirectional KWH and KVARH revenue quantities.
The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps data. Depending on the distance from the project site to the Point of Interconnection, a loss calculation may be added to the project metering.
An Ethernet connection is required for retail sales and generation accounting via the MV-90 translation system. Generator Metering
The solar generator and battery storage are to be separately metered. Assuming the
Interconnection Customer supplied one line is correct, the two breakers for the solar generator, and the one breaker for the battery storage will be metered. This will require three metering points.
The metering will be located at the Interconnection Customer’s collector substation and each
metering point will be rated for its individual circuit on the Project. The Transmission Provider will specify and order all interconnection revenue metering, including the instrument transformers, meters, meter enclosures, junction boxes, and secondary metering wire. The primary metering transformers will be combination 34.5kV CT/VT units with extended range
CTs for high-accuracy metering. The metering design package will include two revenue quality meters for each meter point with DNP real time digital data terminated at a metering interposition block. One meter will be designated as primary SCADA meter with DNP data delivered to the primary control center.
A second meter will be designated as backup SCADA meter with DNP data delivered to the alternate control center. The metering data will include bidirectional KWH and KVARH revenue quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps data.
An Ethernet connection is required for retail sales and generation accounting via the MV-90 translation system. Station Service/Construction Power
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Prior to construction, Interconnection Customer must arrange construction power with the Transmission Provider holding the certificated service territory rights for the area in which the
load is physically located. Station service and temporary construction power metering shall conform to the Transmission Provider’s requirements. Please note, prior to back feed, Interconnection Customer must arrange retail meter service for electricity consumed by the Project with the Transmission Provider holding the certificated
service territory rights for the area in which the load is physically located.
8.0 CONTINGENT FACILITIES
The following Interconnection Facilities and/or upgrades to the Transmission Provider’s system are Contingent Facilities applicable to this Cluster Area.
Houston Lake – Ponderosa 115 kV Transmission Line Table 8.1 below identifies that the addition of the generation proposed for CA8 will increase potential overloads on the existing Houston Lake – Stearns Butte 115 kV transmission line. The Transmission Provider has a preliminarily planned project to install a new 115 kV transmission line between Ponderosa substation and Houston Lake substation by Q4 2025. The project is
currently being evaluated for approval. For the purposes of this study, the Transmission Provider assumes this project will be approved to proceed forward as a Transmission Provider project. If not, this transmission line will become a requirement of the Interconnection Requests in this Cluster Area.

9.0 COST ESTIMATE
The following estimate represents only scopes of work that will be performed by the Transmission
Provider. Costs for any work being performed by the Interconnection Customer and/or Affected
Systems are not included.
9.1 Interconnection Facilities
The following facilities are directly assigned to Interconnection Customer(s) using such facilities. If multiple Interconnection Requests are utilizing the same Transmission Provider
Interconnection Facilities the costs shall be shared pursuant to Section 39.2.3 of Transmission
Provider’s OATT. TCS-43
Table 8.1: Contingent Facility Identification
Potential Contingent Facility Description
Outage(s) Level Level % Change Facility (Yes/No) Responsible Entity Planned ISD
Lake – Ponderosa 115 kV transmission line addition
Road – Q0731 POI 115 kV transmission line (HS)
Lake – Stearns Butte 147% overloaded
Lake – Stearns Butte 170% overloaded
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TCS-43 Collector Substation $342,000 Metering and communications equipment
Shared Facility Substation $391,000
Control building, relaying, metering, and communications equipment Stearns Butte Substation $200,000
Line termination and breaker
TCS-44 TCS-44 Collector Substation $380,000 Metering and communications equipment
Ponderosa Substation $400,000
Line termination and metering TCS-45
TCS-45 Collector Substation $342,000
Metering and communications equipment
Shared Facility Substation $391,000 Control building, relaying, metering, and communications equipment
Stearns Butte Substation $200,000
Line termination and metering TCS-52
TCS-52 Collector Substation $106,000
Metering and communications equipment
Shared Facility Substation $175,000 Control building, relaying, metering, and communications equipment
Ponderosa Substation $134,000 Line position and metering TCS-53 Collector Substation $106,000
Metering and communications equipment Shared Facility Substation $175,000 Control building, relaying, metering, and communications equipment Ponderosa Substation $134,000 Line position and metering
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TCS-54 TCS-54 Collector Substation $339,000
Metering and communications equipment
Shared Facility Substation $175,000 Control building, relaying, metering, and communications equipment
Ponderosa Substation $134,000
Line position and metering
9.2 Station Equipment
The following are Network Upgrades which are allocated based on the number of Generating Facilities interconnecting at an individual station on a per Interconnection Request basis.
Interconnection Requests utilizing the same Interconnection Facilities shall be consider one
request for this allocation. Ponderosa Substation $2,873,000 Substation expansion, generator line positions and breakers
Stearns Butte Substation $744,000
Line position and breaker
9.3 Network Upgrades
The funding responsibility for Network Upgrades other than those identified in the previous
section shall be allocated based on the proportional capacity of each individual Generating
Facility. Ponderosa Substation $9,744,000 Substation expansion, line position, breaker, transformer
Corral Substation $2,500,000
Line position Corral-Ponderosa Transmission Line $1,840,000
Install transmission line
Total Network Upgrades $14,084,000
9.4 Total Estimated Project Costs
TCS-43 Interconnection Facilities $933,000 Station Equipment $372,000
Network Upgrades $2,348,000 Total $3,653,000
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TCS-44 Interconnection Facilities $780,000
Station Equipment $1,437,000 Network Upgrades $4,695,000 Total $6,912,000 TCS-45
Interconnection Facilities $933,000 Station Equipment $372,000 Network Upgrades $2,348,000 Total $3,353,000
TCS-52 Interconnection Facilities $414,000 Station Equipment $479,000 Network Upgrades $1,174,000 Total $2,067,000
TCS-53 Interconnection Facilities $414,000 Station Equipment $479,000 Network Upgrades $1,174,000
Total $2,067,000 TCS-54 Interconnection Facilities $647,000 Station Equipment $479,000
Network Upgrades $2,348,000 Total $3,474,000
10.0 SCHEDULE
The Transmission Provider estimates it will require approximately 30 months to design, procure and construct the facilities described in this report following the execution of Interconnection
Agreements. The schedule will be further developed and optimized during the Facilities Studies.
11.0 AFFECTED SYSTEMS
Transmission Provider has identified the following affected systems: - Bonneville Power Administration (BPA) - Portland General Electric (PGE)
A copy of this report will be shared with each Affected System.
12.0 APPENDICES
Appendix 1: Cluster Area Power Flow and Stability Study Results Appendix 2: Higher Priority Requests
Appendix 3: Property Requirements
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12.1 Appendix 1: Cluster Area Power Flow and Stability Study Results
• In addition to the normal configuration, ten (10) contingency configurations were studied
in power flow simulation at the transmission level:
o Normal Configuration is defined as follows: Ponderosa substation 115 kV bus supplied from the energized 230 kV and 500 kV grids via two existing 500-230 kV transformers and two existing 230-115 kV transformers; the existing 115 kV Line CO19 path
(Ponderosa-Stearns Butte and Stearns Butte-Houston Lake substation) is closed; the
proposed 115 kV line from Ponderosa to Houston Lake is in service and closed; the existing 115 kV Line CO14 path (Ponderosa-Baldwin Road, Baldwin Road-Prineville and Prineville-Houston Lake) is closed; the 115 kV Line CO3 and CO7 path between Houston Lake substation and BPA Redmond substation is closed between PAC
Redmond and Powell Butte; BPA Redmond substation is supplied from the energized
230 kV grid.
The following contingency cases start from the Normal Configuration described above;
the described element is then removed from service in a power flow simulation. The
response of the transmission system is then tested. o Contingency Configuration #1: one 230-115 kV transformer at Ponderosa substation out of service.
o Contingency Configuration #2: one BPA 500-230 kV transformer at BPA Ponderosa out of service. o Contingency Configuration #3: Ponderosa – 115 kV transmission line between Ponderosa and the proposed Q0731 POI substation out of service o Contingency Configuration #4: 115 kV transmission line between the proposed Q0731
POI substation and Baldwin Road out of service
o Contingency Configuration #5: 115 kV transmission line between Baldwin Rd and Prineville out of service o Contingency Configuration #6: 115 kV transmission line between Houston Lake and Prineville out of service
o Contingency Configuration #7: 115 kV transmission line between Houston Lake and Stearns Butte out of service o Contingency Configuration #8: 115 kV transmission line between Ponderosa and Stearns Butte out of Service o Contingency Configuration #9: 115 kV transmission line between Houston Lake and
Ponderosa out of service
o Contingency Configuration #10: 230 kV transmission line between Ponderosa substation and Pilot Butte substation out of service
A power flow simulation of the addition of TCA-8 generation to the Transmission Provider’s
system was performed with the following system conditions:
• Minimum daytime loading of 123.7 MW on the 115 kV system (not including Friend), including Redmond and Powell Butte loads. o Includes network loads and non-network loads
o Data center loads modeled at daily minimums seen in the past 12 months
• Peak Summer loading of 285.6 MW on the 115 kV system (not including Friend)
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o Prineville substation loads modeled at 2025 projected maximums, including expected block load additions.
o Data center loads (network and non-network) modeled at contractual maximums for the purposes of a power flow study. Network Resource Interconnection Service deliverability was determined based on the
following system conditions:
• Peak Summer network loads of 297 MW on the 115 kV and 230 kV systems o Prineville substation loads modeled at 2025 projected maximums, including expected block load additions
o Data Center Loads at Houston Lake and Friend substations modeled at 2025 projected maximums. o Non-network loads at Baldwin Road not included Addition of the TCA-8 Cluster Generation to the 115 kV system in Prineville, Oregon, causes overloads for contingency configurations #1 and 2 during minimum daylight loading conditions as shown in Table 12.1 below.
Table 12.1 – Identified Overloads (Min Daylight Loading)

Addition of the TCA-8 Cluster Generation to the 115 kV system in Prineville, Oregon,
causes overloads for contingency configurations #1, 4, 5, 9, and 10 during heavy summer loading conditions as shown in Table 12.2 below.
Transmission
Configuration
Number Contingency description Overloaded element (MDL loading, heavy generation)
Min.
Daytime
Post
project
loading
Normal Config.
Contingency
Config. #1
Contingency
Config. #2
Contingency
Config. #3
Contingency
Config. #4
Contingency
Config. #5
Contingency
Config. #6
Contingency
Config. #7
Contingency
Config. #8
Contingency
Config. #9Contingency
Config. #10
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Table 12.2 – Identified Overloads (Heavy Summer Loading)

Voltages and post transient voltage steps are projected in power flow simulation to remain within
permissible limits during the interruption of the TCA-8 generation in the Transmission Provider’s normal transmission configuration and all contingency configurations for all load levels. The following table summarizes the transient voltage for various network configurations:
Transmission
Configuration
Number Contingency description Overloaded element (heavy summer loading, heavy generation)
Heavy
Summer
Post
project
loading
Normal Config.
Contingency
Config. #1
Contingency
Config. #2
Contingency
Config. #3
Contingency
Config. #4
Contingency
Config. #5
Contingency
Config. #6
Contingency
Config. #7
Contingency
Config. #8
Contingency
Config. #9 106%
Contingency
Config. #10
145%
104%
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(Ponderosa – Q0731 POI 115 kV transmission line trips offline)

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12.2 Appendix 2: Higher Priority Requests
All active higher priority Transmission Provider projects, and transmission service and/or
generator interconnection requests will be considered in this cluster area study and are identified below. If any of these requests are withdrawn, the Transmission Provider reserves the right to restudy this request, as the results and conclusions contained within this study could significantly change.
Transmission/Generation Interconnection Queue Requests considered:
Responsible
Utility
Project
Number
POI: Size
(MW)
PAC Q443 Ponderosa 115 kV bus 34.56
PAC Q594 Ponderosa 115 kV bus –in service 56
PAC Q621 Baldwin Road substation 55
PAC Q731 Baldwin Road-Ponderosa 115 kV line 55
PAC Q734 Ponderosa 115 kV bus (shared tie with Q594) 63.5
PAC Q824 Ponderosa 115 kV bus (shared tie with Q594) 40
PAC Q850 Stearns Butte 115 kV substation – in service 61

Oregon Community Solar Projects:
PAC OCS001 Prineville 5D69 1.46
PAC OCS002 Prineville 5D126 0.9

Distributed Energy Resources (DER) – in service
PAC DER Prineville sub (transformer 1 aggregate) 0.897
PAC DER Prineville sub (transformer 2 aggregate) 0.188
PAC DER Powell Butte substation 1.355
PAC DER Redmond sub(transformer 1 aggregate) 0.801
PAC DER Redmond sub (transformer 2 aggregate) 0.757

Foreign Utility Requests:
BPA G0501 Captain Jack 500 kV substation 1100
BPA G0527 Fort Rock 500 kV substation 105
BPA G0539 BPA Ponderosa 230 kV Bus 600
BPA G0640 Captain Jack 500 kV substation 238.5

PGE 17-065 Fort Rock 500 kV substation 400
PGE QF17-068 Pelton-Round Butte 230 kV line 65
PGE 18-071 Grizzly - Malin 500 kV line (near Fort Rock) 600
PGE 19-080 Redmond - Round Butte 230 kV line 80
PGE QF19-081 Redmond - Round Butte 230 kV line 53

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12.3 Appendix 3: Property Requirements
Property Requirements for Point of Interconnection Substation
Requirements for rights of way easements Rights of way easements will be acquired by the Interconnection Customer in the Transmission Provider’s name for the construction, reconstruction, operation, maintenance, repair, replacement and removal of Transmission Provider’s Interconnection Facilities that will be owned and operated by PacifiCorp. Interconnection Customer will acquire all necessary
permits for the Project and will obtain rights of way easements for the Project on Transmission Provider’s easement form. Real Property Requirements for Point of Interconnection Substation Real property for a POI substation will be acquired by an Interconnection Customer to
accommodate the Interconnection Customer’s Project. The real property must be acceptable to Transmission Provider. Interconnection Customer will acquire fee ownership for interconnection substation unless Transmission Provider determines that other than fee ownership is acceptable; however, the form and instrument of such rights will be at Transmission Provider’s sole discretion. Any land rights that Interconnection Customer is
planning to retain as part of a fee property conveyance will be identified in advance to Transmission Provider and are subject to the Transmission Provider’s approval. The Interconnection Customer must obtain all permits required by all relevant jurisdictions for the planned use including but not limited to conditional use permits, Certificates of Public
Convenience and Necessity, California Environmental Quality Act, as well as all construction permits for the Project. If eligible, Interconnection Customer will not be reimbursed through network upgrades for more than the market value of the property.
As a minimum, real property must be environmentally, physically, and operationally acceptable to Transmission Provider. The real property shall be a permitted or able to be permitted use in all zoning districts. The Interconnection Customer shall provide Transmission Provider with a title report and shall transfer property without any material defects of title or
other encumbrances that are not acceptable to Transmission Provider. Property lines shall be surveyed and show all encumbrances, encroachments, and roads. Examples of potentially unacceptable environmental, physical, or operational conditions could include but are not limited to:
1. Environmental: known contamination of site; evidence of environmental contamination by any dangerous, hazardous or toxic materials as defined by any governmental agency; violation of building, health, safety, environmental, fire, land use, zoning or other such regulation; violation of ordinances or statutes of any governmental entities having
jurisdiction over the property; underground or above ground storage tanks in area; known remediation sites on property; ongoing mitigation activities or monitoring activities;
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asbestos; lead-based paint, etc. A phase I environmental study is required for land being acquired in fee by the Transmission Provider unless waived by Transmission Provider.
2. Physical: inadequate site drainage; proximity to flood zone; erosion issues; wetland overlays; threatened and endangered species; archeological or culturally sensitive areas; inadequate sub-surface elements, etc. Transmission Provider may require Interconnection Customer to procure various studies and surveys as determined necessary by Transmission
Provider. Operational: inadequate access for Transmission Provider’s equipment and vehicles; existing structures on land that require removal prior to building of substation; ongoing maintenance for landscaping or extensive landscape requirements; ongoing homeowner's or other
requirements or restrictions (e.g., Covenants, Codes and Restrictions, deed restrictions, etc.) on property which are not acceptable to the Transmission Provider.

Generation Interconnection Transition Cluster
Transition Cluster Study Report

Cluster Area 4
October 22, 2021

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TABLE OF CONTENTS
1.0 SCOPE OF THE STUDY ................................................................................................................. 1 2.0 STUDY ASSUMPTIONS ................................................................................................................. 1 3.0 GENERATING FACILITY REQUIREMENTS .............................................................................. 3 3.1 Transmission Voltage Interconnection Requests .............................................................................. 3 3.2 Distribution Voltage Interconnection Requests ................................................................................ 6
4.0 CLUSTER AREA DEFINITIONS ................................................................................................... 6 5.0 CLUSTER AREA 4 (CA4) ............................................................................................................... 7 5.1 Description of Interconnection Request – TCS-07 ........................................................................... 7 5.2 Description of Interconnection Request – TCS-09 ........................................................................... 9 5.3 Description of Interconnection Request – TCS-25 ......................................................................... 10 5.4 Description of Interconnection Request – TCS-41 ......................................................................... 10 6.0 SITE SPECIFIC GENERATING FACILITY REQUIREMENTS ................................................. 13 7.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS - ERIS .......................................... 13 7.1 Transmission System Requirements ............................................................................................... 13 7.2 Distribution System Requirements ................................................................................................. 14 7.3 Transmission Line Requirements .................................................................................................... 14 7.4 Existing Circuit Breaker Upgrades – Short Circuit ......................................................................... 14 7.5 Protection Requirements ................................................................................................................. 15 7.6 Data (RTU) Requirements .............................................................................................................. 17 7.7 Substation Requirements ................................................................................................................. 20 7.8 Communication Requirements ........................................................................................................ 24 7.9 Metering Requirements ................................................................................................................... 24 8.0 CONTINGENT FACILITIES (ERIS) ............................................................................................ 28 9.0 COST ESTIMATE (ERIS) ............................................................................................................. 29 9.1 Interconnection Facilities ................................................................................................................ 29 9.2 Station Equipment ........................................................................................................................... 30 9.3 Network Upgrades .......................................................................................................................... 30 9.4 Total Estimated Project Costs ......................................................................................................... 32 10.0 SCHEDULE (ERIS) ....................................................................................................................... 32 11.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS – NRIS ......................................... 32 12.0 AFFECTED SYSTEMS ................................................................................................................. 32 13.0 APPENDICES ................................................................................................................................ 33 13.1 Appendix 1: Cluster Area Power Flow and Stability Study Results ............................................... 34 13.2 Appendix 2: Higher Priority Requests ............................................................................................ 35 13.3 Appendix 3: Property Requirements ............................................................................................... 36
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1.0 SCOPE OF THE STUDY
This cluster restudy is being performed due to the withdrawal of several interconnection requests
that were included in the original cluster study. Cluster Area 4 (CA4) is generally described as the Transmission Provider’s southern Utah area and includes the following Interconnection Request: TCS-07, TCS-09, TCS-25 and TCS-41
Consistent with Attachment W, Section 3.4.2 and Section 51.4 of PacifiCorp’s (“Transmission Provider”) Open Access Transmission Tariff (“OATT”), this interconnection Transition Cluster Study (“Cluster Study”) evaluated the impact of the proposed interconnections on the reliability of the Transmission System. The Cluster Study considered the Base Case as well as all generating
facilities (and with respect to (iii) below, any identified Network Upgrades associated with such
higher queued interconnection) that, on the date the Cluster Request Window closes: (i) are existing and directly interconnected to the Transmission System; (ii) are existing and interconnected to Affected Systems and may have an impact on the
Interconnection Request;
(iii) have a pending higher queued or higher clustered interconnection request to interconnect to the transmission system; and (iv) have executed an LGIA or requested that an unexecuted LGIA be filed with FERC.
The Cluster Study consisted of power flow, stability, and short circuit analyses.
This Cluster Study report provides the following information:
• identification of any circuit breaker short circuit capability limits exceeded as a result of the
interconnection;
• identification of any thermal overload or voltage limit violations resulting from the interconnection;
• identification of any instability or inadequately damped response to system disturbances
resulting from the interconnection and
• description and non-binding, good faith estimated cost of facilities required to interconnect the Generating Facilities to the Transmission System and to address the identified short circuit, instability, and power flow issues.
2.0 STUDY ASSUMPTIONS
• All active higher priority transmission service and/or generator interconnection requests that were considered in this study are listed in Appendix 2. If any of these requests are withdrawn, the Transmission Provider reserves the right to restudy this request, and the results and conclusions could significantly change.
• For study purposes there are two separate queues:
o Transmission Service Queue: to the extent practical, all network upgrades that are required to accommodate active transmission service requests were modeled in this study.
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o Generation Interconnection Queue: Interconnection Facilities and network upgrades associated with higher queued or higher clustered interconnection
requests were modeled in this study.
• The Interconnection Customers’ request for energy or network resource interconnection service in and of itself does not request or convey transmission service. Only a Network Customer may make a request to designate a generating resource as a Network Resource.
Because the queue of higher priority transmission service requests may be different when
a Network Customer requests network resource designation for this Generating Facility, the available capacity or transmission modifications, if any, necessary to provide Network Integration Transmission Service may be significantly different. Therefore, Interconnection Customers should regard the results of this study as informational rather
than final.
• Under normal conditions, the Transmission Provider does not dispatch or otherwise directly control or regulate the output of generating facilities. Therefore, the need for transmission modifications, if any, that may be required to provide Network Resource
Interconnection Service will be evaluated on the basis of 100 percent deliverability (i.e.,
this study did not model displacement of other resources in the same area).
• This study assumed the Projects will be integrated into the Transmission Provider’s system at agreed upon and/or proposed Points of Interconnection (“POI” or “POIs”).
• If Interconnection Customers proceed through the interconnection process, they will be required to construct and own any facilities required between the Point of Change of Ownership and the Project unless specifically identified by the Transmission Provider.
• Line reconductor or fiber underbuild required on existing poles were assumed to follow the
most direct path on the Transmission Provider’s system. If during detailed design the path must be modified it may result in additional cost and timing delays for the Interconnection Customer’s Project.
• Generator tripping may be required for certain outages.
• All facilities will meet or exceed the minimum Western Electricity Coordinating Council
(“WECC”), North American Electric Reliability Corporation (“NERC”), and the Transmission Provider’s performance and design standards.
• Power flow analysis requires WECC base cases to reliably balance under peak load
conditions the aggregate of generation in the local area, with the Generating Facility at full
output, to the aggregate of the load in the Transmission Provider’s Transmission System. As the PacifiCorp East (“PACE”) balancing authority area (“BAA”) has more existing and proposed generation than load, it is necessary to assume some portion of other resources are displaced by this Project’s output in order to assess the impact of interconnecting this
Project’s generation to transmission system operations. For the purposes of this study,
generation in the Transmission Provider’s Wyoming area was assumed to be displaced.
• The following transmission system improvements were assumed in-service: o Energy Gateway South (12/2024) o Lakeside I Remedial Action Scheme (RAS) modification Planned (4/2022)
o Milford 138 kV three breaker ring bus and Blundell 138 kV breaker(Q0820)
o New South Milford – Milford 46 kV line (Q0820)
o Rebuild of Cameron – Tushar - Sevier Tap – Sigurd 138 kV line (Q0820) o Upgrade of the Emery 345-138 kV transformers (Q0823) o Magna Cap Bank (Not contingent) Planned (2023)
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o Camp Williams bus improvements (Not contingent) (2024) o Lakeside II RAS modifications (TSR Q2867)
o Cottonwood - Snyderville Reconductor (Planned project) (2024)
• The Transmission Provider assumes it will be required to meter DC coupled solar and battery storage separately. This may result in a significant amount of Interconnection Facilities for Interconnection Customer’s proposing this type of design. It may also result
in significant, annual maintenance costs for Interconnection Customers. Please note that
the Transmission Provider does not currently have an approved meter capable of this function therefore cost estimates and schedules are preliminary at this time. The Transmission Provider assumes it will not be able to support a Commercial Operation Date for any Interconnection Request with DC coupled battery storage prior to Q4 2023.
• This report is based on information available at the time of the study. It is the
Interconnection Customer’s responsibility to check the Transmission Provider’s web site regularly for Transmission System updates at https://www.oasis.oati.com/ppw
3.0 GENERATING FACILITY REQUIREMENTS
The following requirements are applicable to all Interconnection Requests. The Transmission
Provider will identify any site-specific generating facility requirements in addition to the
following in this report and in facilities studies. Certain Interconnection Requests requesting service at a voltage level traditionally defined as distribution may be subject to the transmission interconnection request requirements listed below should the Transmission Provider make that determination.
3.1 Transmission Voltage Interconnection Requests
All interconnecting synchronous and non-synchronous generators are required to design their Generating Facilities with reactive power capabilities necessary to operate within the full power factor range of 0.95 leading to 0.95 lagging. This power factor range shall be dynamic and can be met using a combination of the inherent dynamic reactive power capability of the generator or
inverter, dynamic reactive power devices and static reactive power devices to make up for losses. For synchronous generators, the power factor requirement is to be measured at the Point of Interconnection. For non-synchronous generators, the power factor requirement is to be measured at the high side of the generator substation.
The Generating Facility must provide dynamic reactive power to the system in support of both voltage scheduling and contingency events that require transient voltage support and must be able to provide reactive capability over the full range of real power output.
If the Generating Facility is not capable of providing positive reactive support (i.e., supplying reactive power to the system) immediately following the removal of a fault or other transient low voltage perturbations, the facility must be required to add dynamic voltage support equipment. These additional dynamic reactive devices shall have correct protection settings such that the devices will remain online and active during and immediately following a fault event.
Generators shall be equipped with automatic voltage-control equipment and normally operated with the voltage regulation control mode enabled unless written authorization (or directive) from
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the Transmission Provider is given to operate in another control mode (e.g. constant power factor control). The control mode of generating units shall be accurately represented in operating studies.
The generators shall be capable of operating continuously at their maximum power output at its rated field current within +/- 5% of its rated terminal voltage. All generators are required to ensure the primary frequency capability of their Facility by installing, maintaining, and operating a functioning governor or equivalent controls as indicated
in FERC Order 842. As required by NERC standard VAR-001-4.2, the Transmission Provider will provide a voltage schedule for the Point of Interconnection. In general, Generating Facilities should be operated so
as to maintain the voltage at the Point of Interconnection, typically between 1.00 per unit to 1.04
per unit, or other designated point as deemed appropriated by Transmission Provider. The Transmission Provider may also specify a voltage and/or reactive power bandwidth as needed to coordinate with upstream voltage control devices such as on-load tap changers. At the Transmission Provider’s discretion, these values might be adjusted depending on operating
conditions.
Generating Facilities capable of operating with a voltage droop are required to do so. Voltage droop control enables proportionate reactive power sharing among Generation Facilities. Studies will be required to coordinate voltage droop settings if there are other facilities in the area. It will
be the Interconnection Customer’s responsibility to ensure that a voltage coordination study is
performed, in coordination with Transmission Provider, and implemented with appropriate coordination settings prior to unit testing. For areas with multiple generating facilities additional studies may be required to determine
whether or not critical interactions, including but not limited to control systems, exist. These
studies, to be coordinated with Transmission Provider, will be the responsibility of the Interconnection Customer. If the need for a master controller is identified, the cost and all related installation requirements will be the responsibility of the Interconnection Customer. Participation by the generation facility in subsequent interaction/coordination studies will be required pre- and
post-commercial operation in order ensure system reliability.
Interconnection Requests that are 75 MVA or larger may be required to facilitate collection and validation of accurate modeling data to meet NERC modeling standards. The Transmission
Provider, in its roles as the Planning Coordinator, requires Phasor Measurement Units (PMUs) at
all new Generating Facilities with an individual or aggregate nameplate capacity of 75 MVA or greater. In addition to owning and maintaining the PMU, the Generating Facility will be responsible for collecting, storing (for a minimum of 90 days) and retrieving data as requested by the Planning Coordinator. Data must be stored for a minimum of 90 days. Data must be collected
and be able to stream to Planning Coordinator for each of the Generating Facility’s step-up
transformers measured on the low side of the GSU at a sample rate of at least 60 samples per second and synchronized within +/- 2 milliseconds of the Coordinated Universal Time (UTC). Initially, the following data must be collected:
• Three phase voltage and voltage angle (analog)
• Three phase current (analog)
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Data requirements are subject to change as deemed necessary to comply with local and federal regulations.
All generators must meet the Federal Energy Regulatory Commission (FERC), North American Electric Reliability Corporation (NERC) and WECC low voltage ride-through requirements as specified in the interconnection agreement. Inverters must be designed to stay connected to the grid in the case of severe faults and may not momentarily cease output within the no-trip area of
the voltage curves. Figure 2 illustrates the voltage ride-through capability as per NERC PRC-024. Importantly, inverters should be designed such that a trip outside of the curves is a “may-trip” area (if needed to protect equipment) not a “must-trip” area. Inverters that momentarily cease active power output for these voltage excursions should be configured to restore output to pre-
disturbance levels in no greater than five seconds, provided the inverter is capable of these changes.
Generators must provide test results to the Transmission Provider verifying that the inverters for this Project have been programmed to meet all PRC-024 requirements rather than manufacturer IEEE distribution standards.

As the Transmission Provider cannot submit a user written model to WECC for inclusion in base cases, a standard model from the WECC Approved Dynamic Model Library is required 180 days prior to trial operation. The list of approved generator models is continually updated and is
available on the http://www.WECC.biz website.
Interconnection Customer with an Interconnection Request for a Generating Facility that is both 75 MVA or larger as well as being interconnected at a voltage higher than 100 kV shall register with NERC as the Generator Owner (“GO”) and Generator Operator (“GOP”) for the Large
Generating Facility and provide the Transmission Provider documentation demonstrating
registration in order to be approved for Commercial Operation. This registration must be maintained throughout the lifetime of the Interconnection Agreement.
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Interconnection Customers are responsible for the protection of transmission lines between the Generating Facility and the Point of Interconnection substation. For Interconnection Requests that
are smaller than 75 MVA or are interconnected at a voltage less than 100 kV which have a tie line that is longer than 1,000 feet the Interconnection Customer shall construct and own a tie-line substation to be located at the change of ownership (separate fenced facility adjacent to the Transmission Provider’s Point of Interconnection substation). The tie line substation shall include an Interconnection Customer owned protective device and associated transmission line
relaying/communications. The ground grids of the Transmission Provider’s Point of Interconnection substation and the Interconnection Customer’s tie-line substation will be connected to support the use of a bus differential protection scheme which will protect the overhead bus connection between the two facilities.
3.2 Distribution Voltage Interconnection Requests
The Generating Facility and interconnection equipment owned by the Interconnection Customers are required to operate under constant power factor mode with a unity power factor setting unless specifically requested otherwise by the Transmission Provider. The Generating Facilities are expressly forbidden from actively participating in voltage regulation of the Transmission
Provider’s system without written request or authorization from the Transmission Provider. The
Generating Facilities shall have sufficient reactive capacity to enable the delivery of 100 percent of the plant output to the applicable POI at unity power factor measured at 1.0 per unit voltage under steady state conditions.
Generators capable of operating under voltage control with voltage droop are required to do so.
Studies will be required to coordinate the voltage droop setting with other facilities in the area. In general, the Generating Facility and Interconnection Equipment should be operated so as to maintain the voltage at the Point of Interconnection between 1.01 pu to 1.04 pu. At the Public Utility’s discretion, these values might be adjusted depending on the operating conditions. Within
this voltage range, the Generating Facility should operate so as to minimize the reactive
interchange between the Generating Facility and the Public Utility’s system (delivery of power at the Point of Interconnection at approximately unity power factor). The voltage control settings of the Generating Facility must be coordinated with the Public Utility prior to energization (or interconnection). The reactive compensation must be designed such that the discreet switching of
the reactive device (if required by the Interconnection Customer) does not cause step voltage
changes greater than +/-3% on the Public Utility’s system. All generators must meet applicable WECC low voltage ride-through requirements as specified in the interconnection agreement.

As per NERC standard VAR-001-1, the Public Utility is required to specify voltage or reactive power schedule at the Point of interconnection. Under normal conditions, the Public Utility’s system should not supply reactive power to the Generating Facility.
4.0 CLUSTER AREA DEFINITIONS
The Transmission Provider will perform the cluster study based on geographically and/or
electrically relevant areas on the Transmission Provider’s Transmission System known as Cluster
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Areas. The Transmission Provider has determined that this Cluster Study will be comprised of the following Cluster Areas:
5.0 CLUSTER AREA 4 (CA4)
The Transmission Provider performed the Transition Cluster Study based on geographically and/or electrically relevant areas on the Transmission Provider’s Transmission System known as Cluster Areas. The Transmission Provider has determined that the Interconnection Requests discussed in Section 5.0 are located in a geographically and/or electrically relevant area on
Transmission Provider’s Transmission System, and thus, were assigned Cluster Area 4 in the Transition Cluster Study process.

5.1 Description of Interconnection Request – TCS-07
The Interconnection Customer has proposed to interconnect 20 MW of new generation to the Transmission Provider’s Nebo-Vickers-Scipio 46 kV transmission line located in Juab County, Utah. The Interconnection Request is proposed to consist of eleven (11) 2,200 KVA SMA Sunny Central SC2200-US solar inverters a total output of 20 MW at the Point of Interconnection. The
requested commercial operation date is October 1, 2022. Figure 6 below, is a one-line diagram that illustrates the interconnection of the proposed Generating Facility to the Transmission Provider’s system. Interconnection Customer will operate this generator as a Qualified Facility as defined by the
Public Utility Regulatory Policies Act of 1978 (PURPA).
The Interconnection Request will be studied for Network Resource Interconnection Service (“NRIS”).
The Transmission Provider has assigned the Project Cluster Number “TCS-07”

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Change ofOwnership
Point of Interconnection
M
46 kV
TCS-07 POI
Substation
3.0 miles
2.6 miles
VickersSubstation
46 kV12.5 kV
TCS-07 CollectorSubstation
R
R
41
Nebo Nebo Nebo
Gunnison
Nephi City
8.59 miles
Moroni FeedIFA
Coastal States
Kuhni
15/19.95/24.94 MVAZ = 6.0 %
2.2 MVADC/AC
385 V
2.5 MVAZ = 6.0 %
34.5 kV11 transformer / inverterstotal
Figure 6: Simplified System One Line Diagram for the TCS-07 Project
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5.2 Description of Interconnection Request – TCS-09
The Interconnection Customer has proposed to interconnect 300 MW of new generation to the
Transmission Provider’s Camp Williams-Mona #1 345 kV transmission line located in Utah County, Utah. The Interconnection Request is proposed to consist of eighty-six (86) 4,200 KVA SMA SC4200-UP-US solar inverters for a total output of 300 MW at the Point of Interconnection. The Interconnection Request also consists of 150 MW of DC coupled battery storage with no capability to charge from the Transmission Provider’s grid. The requested commercial operation
date is November 30, 2023. Figure 8 below, is a one-line diagram that illustrates the interconnection of the proposed Generating Facility to the Transmission Provider’s system. Interconnection Customer will NOT operate this generator as a Qualified Facility as defined by
the Public Utility Regulatory Policies Act of 1978 (PURPA).
The Interconnection Request will be studied for Energy Resource Interconnection Service (“ERIS”).
The Transmission Provider has assigned the Project Cluster Number “TCS-09”
Change of ownership
M
TCS-09
POI
Substation
100/133.3/166.7 MVAZ = 9.5 %
34.5 kV
F6
F5
F4
F2 7 Transformer /Inverter Units
7 Transformer /Inverter Units
Point of Interconnection F1
600 V
4.2 MVA Z = 6.5%
7 Transformer /Inverter Units Total
4.2 MVA DC/AC
DC/DC
SolarArray
7 Transformer /Inverter UnitsF3
8 Transformer /Inverter Units
7 Transformer /Inverter Units
100/133.3/166.7 MVAZ = 9.5 %
34.5 kV
F12
F11
F10
F8 7 Transformer /Inverter Units
7 Transformer /Inverter Units
F7 7 Transformer /Inverter Units
7 Transformer /Inverter UnitsF9
8 Transformer /Inverter Units
7 Transformer /Inverter Units
M
M
345 kV
TCS-09Collector
Substation
L1
Camp Williams
Mona

Figure 8: Simplified System One Line Diagram for the TCS-9 Project
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5.3 Description of Interconnection Request – TCS-25
The Interconnection Customer has proposed to interconnect 30 MW of new generation to the
Transmission Provider’s West Cedar-Red Butte 138 kV transmission line located in Iron County, Utah. The Interconnection Request is proposed to consist of nine (9) 4,000 KVA TMEIC Solar Ware Samurai PVH-L4000GR solar inverters for a total output of 30 MW at the Point of Interconnection. The requested commercial operation date is December 31, 2022. Figure 10 below, is a one-line diagram that illustrates the interconnection of the proposed Generating Facility
to the Transmission Provider’s system. Interconnection Customer will NOT operate this generator as a Qualified Facility as defined by the Public Utility Regulatory Policies Act of 1978 (PURPA).

The Interconnection Request will be studied for both Energy Resource Interconnection Service and Network Resource Interconnection Service (“NRIS”). The Transmission Provider has assigned the Project Cluster Number “TCS-25”

Change of ownership
138 kV
Point of Interconnection
3.6 MW DC/AC
Holt
M
TCS-25 POISubstation
8.67 miles 138 kV bus
WestCedarSubstation
23/30.6/38.3 MVAZ = 7%
H1
C1 F1
6 MVAR
3.8 Miles
34.5 kV
TCS-25 CollectorSubstation
3.6 MVAZ = 5.75 %
630 V
9 InvertersTotal
TCS-03
Three Peaks
Figure 10: Simplified System One Line Diagram for the TCS-25 Project
5.4 Description of Interconnection Request – TCS-41
The Interconnection Customer has proposed to interconnect 31.1 MW of new generation to the
Transmission Provider’s South Milford 46 kV substation located in Beaver County, Utah. The
Interconnection Request is proposed to consist of a 31,176 KVA Brush DG185ZL-04 geothermal steam turbine for a total output of 31.1 MW at the Point of Interconnection. The requested
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commercial operation date is December 31, 2021. Figure 11 below, is a one-line diagram that illustrates the interconnection of the proposed Generating Facility to the Transmission Provider’s
system. Interconnection Customer will NOT operate this generator as a Qualified Facility as defined by the Public Utility Regulatory Policies Act of 1978 (PURPA).
The Interconnection Request will be studied for both Energy Resource Interconnection Service and Network Resource Interconnection Service (“NRIS”). The Transmission Provider has assigned the Project Cluster Number “TCS-41”
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Change ofOwnership
Point of Interconnection
M
12.5 kV
25 kV
South
Milford
Substation
12.5 kV
Blundell
Substation
Sevier
WUCC
46 kV
138 kV
MilfordSubstation
46 kV
Q0820
Cameron
TCS-41
Plant
Cameron
7.2 Miles
16.2 Miles
CB1
CBX
CBTX
13.8 kV
31.176 MVA
35 MVAZ = 14 %
Figure 11: Simplified System One Line Diagram for the TCS-41 Project
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6.0 SITE SPECIFIC GENERATING FACILITY REQUIREMENTS
In addition to the requirements described above the following Generating Facility are required for the specific Interconnection Requests listed below.
TCS-41 The winding configuration of the Interconnection Customer’s proposed 46–13.8 kV step-up transformer will not be acceptable. The step-up transformer must be a source of ground current for phase to ground faults on the 46 kV transmission system. The transformer will be required to have a wye winding on the 46 kV side, with the neutral grounded, and a delta on the 13.8 kV side.
If a ground reference is needed for the 13.8 kV system then a grounding transformer could be added or a three winding transformer could be used for the step-up transformer. The three winding transformer would have wye windings with the neutrals ground for both the 46 kV and 13.8 kV side along with a delta tertiary winding.
7.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS - ERIS
7.1 Transmission System Requirements
The following transmission system improvements are required to accommodate the Interconnection Requests in this Cluster Area:
• Construction of a new 50-mile Spanish Fork -Mercer 345 kV transmission line. The new
line will be terminated in an existing bay in the Spanish Fork substation. A new circuit breaker will be installed in Mercer substation.
• Replace jumpers on the Huntington end of the Emery-Huntington 345 kV transmission
line.
• Upgrade the existing 75 MVA, 138-46 kV LTC transformer at Milford substation to 125 MVA.
• Rebuild both the existing and the new (identified for Q0820) 46 kV Milford – South
Milford transmission lines.
The following are station upgrades required for each of the Interconnection Requests within this Cluster Area.
TCS-07
Install 46 kV single breaker substation on the Nebo-Vickers-Scipio 46 kV line. TCS-09 Construct a new 345 kV three breaker ring bus substation on the Camp Williams – Mona 345 kV
line at the Point of Interconnection, with associated line terminations, switches, etc.
TCS-25 Construct a new 138 kV three breaker ring bus substation on the Red Butte-West Cedar 138 kV line at the Point of Interconnection, with associated line terminations, switches, etc.

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TSC-41 Install a 46 kV circuit breaker at the South Milford substation.
7.2 Distribution System Requirements
No upgrades to the Transmission Provider’s distribution system have been identified for the Interconnection Requests in this Cluster Area.
7.3 Transmission Line Requirements
It is assumed that each POI substation will be located directly adjacent to the existing
transmission line. Coordination of the exact location for each POI substation will be required and the exact line route/length and resulting cost for the new transmission line loop in/out could vary. Each of the Interconnection Requests in this Cluster Area shall construct its last structure and
span/bus connection into the POI substation to Transmission Provider standards. The
Transmission Provider will review the design of the Interconnection Customer line for the last span into the POI substations. The Interconnection Customers shall coil enough fiber and conductor on the last deadend structure to make the span into the POI substations. The Transmission Provider shall construct the final terminations into the POI substations.

If the Interconnection Customer’s tie line is required to cross a Transmission Provider line, the Interconnection Custer shall make application with the Transmission Provider to do so. The Interconnection Customer’s line shall cross below the Transmission Provider’s line in all cases unless is Interconnection Customer’s line is of a higher voltage.
7.4 Existing Circuit Breaker Upgrades – Short Circuit
The increase in the fault duty on the system as the result of the addition of each of the individual Interconnection Requests in this Cluster Area along with the modifications to the transmission system to support these Interconnection Requests does not push the fault duty over the ratings of the present current interrupting equipment.

The combination of all four Interconnection Requests in this Cluster Area do result in the requirement to increase the interrupting capacity of the following circuit breakers:
Substation Circuit breakers to upgrade interrupting capacity
OQUIRRH O 138.kV CBB145
MONA 345.kV CB349
SIGURD 230.kV CB253
CAMP WILLIAM 345.kV CB301, CB307, CB323, CB326, CB327, CBC363
MIDVALLEY E 138.kV CBC142, CBC141, CB133
TCS-07 The TCS-07 Interconnection Request will have photovoltaic arrays fed through 11 – 2.2 MVA inverters connected to 11 – 34.5 kV – 385 V 2.5 MVA transformers with 6 % impedance
connected to the transmission network via a 46 – 34.5 kV 15/19.95/24.94 MVA transformer with impedance of 6 %.
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TCS-09
The TCS-09 Interconnection Request will have photovoltaic arrays and batteries fed through 86
– 4.2 MVA inverters connected to 86 – 34.5 kV – 600 V 4.2 MVA transformers with 6.5 % impedance connected to the transmission network via two 345 – 34.5 kV 100/133/166.7 MVA transformers with impedance of 9.5 %. TCS-25 The TCS-25 Interconnection Request will have photovoltaic arrays fed through 9 – 3.6 MVA inverters connected to 9 – 34.5 kV – 630 V 3.6 MVA transformers with 5.75 % impedance connected to the transmission network via a 138 – 34.5 kV 23/30.6/38.3 MVA transformer with
impedance of 7 %.
TCS-41 The TCS-41 Interconnection Request will have a 31.176 MVA generator fed through a 35 MVA 46 – 13.8 kV transformer with 14 % impedance.
7.5 Protection Requirements
TCS-07 The proposed TCS-07 project will be connected to the transmission network via the Vickers substation 46 kV bus. For the opening of the 46 kV line breaker 41 at Vickers substation the TCS-07 Generating Facility will need to disconnect in a high-speed manner. This will permit the
automatic high-speed reclosing of the line breaker. Most faults on overhead transmission circuits
are temporary so that after all sources of power to the fault are disconnected the circuit can be re-energized. The circuit can then continue to carry the connected load. The 46 kV system is lightly loaded. The minimum daytime load on the 46 kV circuits that is fed out of Vickers substation on circuit CB 41 is 20 kVA. Because the potential unbalance between the generation and the load
following the opening of the breaker cannot be relied upon to cause a high-speed disconnection of
the Generating Facility a transfer trip communication circuit will be needed between Vickers and the TCS-07 POI substations. A communication circuit will be required to carry the transfer trip signals.
Since the POI and the collector substations will be adjacent to each other, the ground mats of the
two substations can be tied together. This will permit the use of metallic control cables between the substations. The line between POI substation and the Interconnection Customer’s collector substation will be protected with a bus differential relay system. The bus differential relays will be in the POI substation. The Interconnection Customer will need to provide the output from a set of
current transformers from the 46 kV transformer breaker’s bushings. These currents will be fed
into the bus differential relays. If a fault is detected on the 46 kV bus the 46 kV breakers in the collector substation and POI substation will be tripped. In addition to the bus relay, a relay used for under/over voltage and over/under frequency
protection of the system will be installed at the POI substation. If the voltage, magnitude or
frequency, is outside of the normal operation range this relay will trip open the 46 kV transformer breaker in the collector substation.
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A control circuit will be installed at Vickers substation to delay the automatic reclosing of the 46 kV line breaker until there is indication that the line to the TCS-07 Project in no longer energized.
This control circuit is required to prevent potential damage to existing customer equipment if the transfer trip signal does not get to the TCS-07 POI substation or was delayed in disconnecting the generation. At Vickers substation an instrument voltage transformer will be installed on the line side of the breaker to accommodate the control circuit. A relay will be installed at Vickers substation to delay the automatic reclosing of CB 41 until there is indication that the line is no
longer energized. TCS-09 The proposed TCS-09 project will be connected to the Camp Williams – Mona #3 345 kV line. A
three breaker 345 kV ring bus substation will be built adjacent to the line. The installation of
protective relays for line fault detection will be required at the Transmission Provider’s new 345 kV POI substation for the protection of the line to the Interconnection Customer’s collector substation and the lines to Camp Williams and Mona substations. The lines to Camp Williams and Mona substations will be protected with line current differential relay systems. The line relays
at Camp Williams and Mona substations will need to be replaced with line relays that will
compatible with the relays to be installed at the TCS-09 POI substation. It is planned that the collector substation will be adjacent to the POI substation. With the two substations sharing a common fence the ground mats of the two substations can be tied together
and metallic control cables can be used for protection and control circuits. The line between POI
substation and the Interconnection Customer’s collector substation will be protected with redundant bus differential relay systems. The bus differential relays will be in the POI substation. The Interconnection Customer will need to provide the output from two sets of current transformers from the 52L1 345 kV breaker. These currents will be fed into redundant sets of bus
differential relays. If a fault is detected both the 345 kV breakers in the POI substation and the
345 kV breaker in the collector substation will be tripped. In addition to the line protective relaying a relay used for under/over voltage and over/under frequency protection of the system will be installed at the POI substation. If the voltage, magnitude
or frequency, is outside of the normal operation range this relay will trip the Interconnection
Customer’s 345 kV breaker at the collector substation. TCS-25 The proposed TCS-25 project will be connected to the West Cedar – Holt 138 kV line with a three-
breaker ring bus at the TCS-25 POI substation. The installation of protective relays for line fault
detection will be required at the Transmission Provider’s new 138 kV POI substation for the protection of the line to the Interconnection Customer’s collector substation and the lines to West Cedar and Holt substations. The line to West Cedar substation will be protected with line current differential relay systems. The line to Holt substation will be protected with a permissive
overreaching line relays system. The line relays at West Cedar substation will need to be replaced
with line relays that will compatible with the relays to be installed at the TCS-25 POI substation. The line relays at Holt Substation will need to have new relays settings developed for them.
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It is planned that the collector substation will be adjacent to the POI substation. With the two substations sharing a common fence the ground mats of the two substations can be tied together
and metallic control cables can be used for protection and control circuits. The line between POI substation and the Interconnection Customer’s collector substation will be protected with a bus differential relay system. The bus differential relays will be in the POI substation. The Interconnection Customer will need to provide the output from a set of current transformers from the 52H1 138 kV breaker. These currents will be fed into the bus differential relays. If a fault is
detected both the 138 kV breakers in the POI substation and the 138 kV breaker in the collector substation will be tripped. In addition to the line protective relaying a relay used for under/over voltage and over/under
frequency protection of the system will be installed at the POI substation. If the voltage, magnitude
or frequency, is outside of the normal operation range this relay will trip the Interconnection Customer’s 138 kV breaker at the collector substation. TCS-41
The proposed TCS-41 project will be connected to the same 46 kV ring bus switchyard in South
Milford substation planned for the Q0820 project. Another 46 kV breaker will be added to the ring bus. The Interconnection Customer will be required to build a tie line substation adjacent to South Milford substation with a 46 kV breaker. The ground mats of the South Milford substation and the Interconnection Customer’s tie line substation will be tie together so that metallic control
cables can be used for protection and control circuits between the two substations. The
Interconnection Customer will be responsible for the line relays to detect faults on the 46 kV tie line between its tie line substation and collector substation. The Interconnection Customer’s breaker and line relay system must detect and isolate any fault on the 46 kV tie line in 7 cycles or less. The tie line between South Milford substation the Interconnection Customer’s tie line
substation will be protected with a bus differential relay system. The Interconnection Customer
will need to provide the output from a set of current transformers from the 46 kV tie line breaker. These currents will be fed into the bus differential relays. If a fault is detected both the 46 kV breakers in the South Milford substation and the 46 kV breaker in the tie line substation will be tripped. A set of line relays set in a backup mode will be installed in South Milford substation to
monitor the current and voltages on the tie line. Relay elements in the line relays monitor the line
voltages. If the voltage, magnitude or frequency, is outside of the normal operation range these relay elements will trip open the 46 kV tie line breaker.
7.6 Data (RTU) Requirements
The Transmission Provider will remotely monitor and operate new infrastructure to be installed
for this Cluster Area in the substations in which new transmission lines will be connected. TCS-07
The Interconnection Customer will hard wire its source devices from its collector substation to a
marshalling cabinet to be installed on the POI substation fence line. The following points will be
required for this Interconnection Request.

TCS-07 POI substation:
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Analogs:
 Net Generation MW
 Net Generator MVAR
 Interchange metering kWH TCS-07 collector substation: Analog Written to the RTU:
 Max Gen Limit MW Set Point Analogs:
 Max Gen Limit MW Set Point Feed Back
 Potential Power MW
 Average Horizontal Irradiance (GHI)
 Average Plant Atmospheric Pressure (Bar)
 Average Plant Temperature (Celsius) Status:
 46 kV transformer breaker
 34.5 kV collector line breaker
TCS-09 The Interconnection Customer will hard wire its source devices from its collector substation to a marshalling cabinet to be installed on the POI substation fence line. The following points will be
required for this Interconnection Request.
TCS-09 collector substation: Analog Written to the RTU:
 Max Gen Limit MW Set Point
Analogs:
 Max Gen Limit MW Set Point Feed Back
 Potential Power MW
 Average Horizontal Irradiance (GHI)
 Average Plant Atmospheric Pressure (Bar)
 Average Plant Temperature (Celsius)
 345 – 34.5 kV transformer #1 MW
 345 – 34.5 kV transformer #1 MVAR
 345 – 34.5 kV transformer #2 MW
 345 – 34.5 kV transformer #2 MVAR
 34.5 kV Collector circuit #1 MW
 34.5 kV Collector circuit #1 MVAR
 34.5 kV Collector circuit #2 MW
 34.5 kV Collector circuit #2 MVAR
 34.5 kV Collector circuit #3 MW
 34.5 kV Collector circuit #3 MVAR
 34.5 kV Collector circuit #4 MW
 34.5 kV Collector circuit #4 MVAR
 34.5 kV Collector circuit #5 MW
 34.5 kV Collector circuit #5 MVAR
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 34.5 kV Collector circuit #6 MW
 34.5 kV Collector circuit #6 MVAR
 34.5 kV Collector circuit #7 MW
 34.5 kV Collector circuit #7 MVAR
 34.5 kV Collector circuit #8 MW
 34.5 kV Collector circuit #8 MVAR
 34.5 kV Collector circuit #9 MW
 34.5 kV Collector circuit #9 MVAR
 34.5 kV Collector circuit #10 MW
 34.5 kV Collector circuit #10 MVAR
 34.5 kV Collector circuit #11 MW
 34.5 kV Collector circuit #11 MVAR
 34.5 kV Collector circuit #12 MW
 34.5 kV Collector circuit #12 MVAR
Status:
 345 kV transformer breaker L1
 34.5 kV collector line breaker F1
 34.5 kV collector line breaker F2
 34.5 kV collector line breaker F3
 34.5 kV collector line breaker F4
 34.5 kV collector line breaker F5
 34.5 kV collector line breaker F6
 34.5 kV collector line breaker F7
 34.5 kV collector line breaker F8
 34.5 kV collector line breaker F9
 34.5 kV collector line breaker F10
 34.5 kV collector line breaker F11
 34.5 kV collector line breaker F12

TCS-25
The Interconnection Customer will hard wire its source devices from its collector substation to a marshalling cabinet to be installed on the POI substation fence line. The following points will be required for this Interconnection Request.
TCS-25 POI Substation:
Analogs:
 Net Generation MW
 Net Generator MVAR
 Interchange metering kWH

TCS-25 collector substation: Analog Written to the RTU:
 Max Gen Limit MW Set Point Analogs:
 Max Gen Limit MW Set Point Feed Back
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 Potential Power MW
 Average Horizontal Irradiance (GHI)
 Average Plant Atmospheric Pressure (Bar)
 Average Plant Temperature (Celsius)
 34.5 kV Collector circuit MW
 34.5 kV Collector circuit MVAR
 34.5 kV Capacitor circuit MVAR
Status:
 138 kV transformer breaker H1
 34.5 kV collector line breaker F1
 34.5 kV capacitor breaker C1
TCS-41
The Interconnection Customer will install a Transmission Provider approved data concentrator in its collector substation and hard wire its source devices to the data concentrator. The data points are to be brought back to the POI substation by the Interconnection Customer. The following points will be required for this Interconnection Request.

South Milford Substation: Analogs:
 Net Generation MW
 Net Generator MVAR
 Interchange metering kWH
Status:
 46 kV tie line breaker TCS-41 plant substation:
Analog Written to the RTU:
 Max Gen Limit MW Set Point Analogs:
 Max Gen Limit MW Set Point Feed Back
 Potential Power MW
 46 kV A phase voltage
 46 kV B phase voltage
 46 kV C phase voltage Status:
 46 kV transformer circuit switcher CBTX
 13.8 kV transformer breaker CBX
 13.8 kV generator breaker CB1
7.7 Substation Requirements
Mercer Substation
Existing substation will be expanded. A new line from Spanish Fork will be terminated at the
substation. The following is a preliminary list of the major equipment required for this project and may change during detailed design.
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(2) – 345 kV breakers
(1) – 345 kV shunt reactor (4) – 345 kV group operated switches (3) – 345 kV CCVTs (3) – surge arresters
Spanish Fork Substation Existing substation will be expanded to accommodate a new 345 kV bay. Existing lines will be relocated to minimize line crossing. The following is a preliminary list of the major equipment required for this project and may change during detailed design.

(2) – 345 kV breaker (7) – 345 kV group operated switches (1) – 345 kV shunt reactor (3) – 345 kV CCVTs

Milford Substation The 138-46 kV, 75 MVA transformer will be replaced with a 125 MVA unit. Conductor inside the substation will be replaced with higher rated conductor to support the capacity increase along with six (6), 46 kV hook stick operated breaker disconnect switches.

Huntington Substation Conductor associated with the 345 kV line to Emery Substation will be upgraded. Camp Williams Substation
Five (5), 345 kV circuit breaker will be replaced with a breaker with a higher interrupting
capability. If the ground fault duty increases above the growth factor, a CDEGS grounding analysis will be required. Mona Substation
One (1), 345 kV circuit breaker will be replaced with a breaker with a higher interrupting
capability. If the ground fault duty increases above the growth factor, a CDEGS grounding analysis will be required. Oquirrh Substation
One (1), 138 kV circuit breaker will be replaced with a breaker with a higher interrupting
capability. If the ground fault duty increases above the growth factor, a CDEGS grounding analysis will be required. Sigurd Substation
One (1), 230 kV circuit breaker will be replaced with a breaker with a higher interrupting
capability. If the ground fault duty increases above the growth factor, a CDEGS grounding analysis will be required. Vickers Substation
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A voltage transformer will be installed at Vickers substation.
Camp Williams Substation
A relay panel will be replaced at the substation. Mona Substation A relay panel will be replaced at the substation.
Holt Substation Relay settings will be updated.
West Cedar Substation
A relay panel will be replaced at the substation. TCS-07 TCS-07 POI Substation
A single breaker (built to 4 breaker ring bus) POI substation will be required for this project.
The Interconnection Customer’s collector substation will be located adjacent to the TCS-07 POI substation. The ground grids for the two substations will be tied together. A marshalling cabinet will be installed to facilitate the installation of protection, control, and indication cables. The following is a preliminary list of major equipment required for this project and may change
during detailed design.
(1) – 72.5 kV breaker (9) – 69 kV group operated switches (1) – control house
(1) – 46 kV VT
(1) – 46 kV SSVT (6) – Surge arresters (1) – marshalling cabinet
TCS-09
TCS-09 POI Substation A 345 kV substation will be built. The Interconnection Customer’s collector substation will be located adjacent to the Clover substation. The ground grids for the two substations will be tied together. A marshalling cabinet will be installed to facilitate the installation of protection,
control, and indication cables. The following is a preliminary list of major equipment required
for this project and may change during detailed design. (3) – 345 kV breakers (11) – 345 kV group operated switches
(6) – 345 kV CCVTs
(1) – 345 kV SSVT (3) – 345 kV CT/VT metering combination units (1) – control house (2) – bus differential CT junction cabinets
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(1) – marshalling cabinet (6) – Surge arresters

TCS-09 Collector Substation The Interconnection Customer will provide a separate graded, grounded and fenced area along the perimeter of the Interconnection Customer’s Generating Facility for the Transmission Provider to install a control house for any required metering, protection and/or communication
equipment. This area will share a fence and ground grid with the Generating Facility and have separate, unencumbered access for the Transmission Provider. The Interconnection Customer shall perform and provide a CDEGS grounding analysis. The TCS-09 POI substation ground grid will be tied to the TCS-09 collector substation ground grid. AC station service will be
supplied by the Interconnection Customer. DC power for the control house will be supplied by
the Transmission Provider. Six (6), 345 kV combined CT/VT metering instrument transformers will be installed. TCS-25
TCS-25 POI Substation
A new 138 kV ring bus will be required. The Interconnection Customer’s collector substation will be located adjacent to the POI substation. The ground grids for the two substations will be tied together. A marshalling cabinet will be installed to facilitate the installation of protection, control, and indication cables. The following is a preliminary list of major equipment required
for this project and may change during detailed design.
(3) – 138 kV breakers (6) – 138 kV CCVTs (11) – 138 kV group operated switches
(3) – 138 kV CT/VT metering combination units
(1) – control house (1) – 138 kV SSVT (3) – surge arresters (1) – marshalling cabinet
TCS-41 South Milford Substation It is assumed that the Q820 project will be responsible for the yard expansion, build out the 46 kV ring bus, and install a new control house at South Milford, and that it will be in-service
before the start of this project. The Interconnection Customer’s tie line substation will be located
adjacent to the South Milford substation. The ground grids for the two substations will be tied together. A marshalling cabinet will be installed to facilitate installation of protection, control, and indication cables. The following is a preliminary list of major equipment required for this project and may change during detailed design.

(1) – 72.5 kV breaker (4) – 69 kV group operated switch (3) – 46 kV CT/VT metering combination units (1) – marshalling cabinet
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7.8 Communication Requirements
TCS-07
The Transmission Provider will install fiber optic cable on approximately 14.19 miles of transmission line on a line between Vickers Substation and the TCS-07 POI substation. This fiber cable will provide the communications path required for the project metering and the relaying between Vickers substation and the TCS-07 POI substation. Communications equipment will be installed in the Vickers substation to support the relaying, metering, and
SCADA communications. TCS-09 The existing Mona – Camp Williams line fiber will be looped in/out of the new POI substation,
creating a fiber ring and allowing for redundant communications paths. This will accommodate
required relaying between the TCS-09 POI substation and the Mona substation and between the TCS-09 substation and the Camp Williams substation. Communications equipment will be installed in the TCS-09 POI substation and the Transmission Provider’s collector substation control building to support the relaying, metering, and SCADA communications.

Communications equipment will be installed to support the metering equipment required for this Interconnection Request. It is assumed that a significant number of enclosures will need to be installed in the Interconnection Customer’s solar facility.
TCS-25
This project requires that approximately 8.67 miles of OPGW be installed on the existing 138 kV line between the West Cedar substation and the TCS-25 POI substation. This will accommodate the required relaying between the TCS-25 POI substation and the West Cedar substation and between the TCS-25 POI substation and the Holt Substation.

Communications equipment will be installed in the POI substation to support the relaying, the net metering, and SCADA communications. TCS-41
The Interconnection Customer will install Transmission Provider approved fiber optic cable on
its tie line between its collector substation and the POI substation in order to provide the Transmission Provider the required data. The Transmission Provider will terminate the fiber in the POI substation. Communications equipment will be installed in the POI substation to support the net metering and SCADA communications.
7.9 Metering Requirements
TCS-07 Interchange Metering The overall project metering will be located at Point of Interconnection substation. This will
require one metering point. This metering will be rated for the total net generation of the Project. The Transmission Provider will specify and order all interconnection revenue metering, including
the instrument transformers, meters, meter panel, junction box, and secondary metering wire. The primary metering transformers will be combination 46kV CT/VT units with extended range CTs
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for high-accuracy metering.
The metering design package will include two revenue quality meters with DNP real time digital data terminated at a metering interposition block. One meter will be designated as primary SCADA meter with DNP data delivered to the primary control center. A second meter will be designated as backup SCADA meter with DNP data delivered to the alternate control center. The metering
data will include bidirectional KWH and KVARH revenue quantities. The meter data will also
include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps data.
An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.
Station Service The Project is within the Transmission Provider’s service territory. Please note that prior to back feed, Interconnection Customer must arrange transmission retail meter service for electricity consumed by the Project that will be drawn from the transmission system when the Project is not
generating. Interconnection Customer must call the Help Desk at 1-800‐625‐6078 to arrange this
service. Approval for back feed is contingent upon obtaining station service.
TCS-09
Interchange Metering The overall project metering will be located at the Point of Interconnection substation. This will require one metering point. This metering will be rated for the total net generation of the Project. The Transmission Provider will specify and order all interconnection revenue metering, including the instrument transformers, meters, meter panel, junction box, and secondary metering wire. The
primary metering transformers will be combination 345kV CT/VT units with extended range CTs for high-accuracy metering.
The metering design package will include two revenue quality meters with DNP real time digital data terminated at a metering interposition block. One meter will be designated as primary SCADA
meter with DNP data delivered to the primary control center. A second meter will be designated as backup SCADA meter with DNP data delivered to the alternate control center. The metering data will include bidirectional KWH and KVARH revenue quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps data.
A Direct Serial connection is required for retail sales and generation accounting via the MV-90 translation system. GSU Metering Each of the Interconnection Customer’s GSU transformers will require metering, which will require two metering points at 345kV. The metering will be located at the Interconnection Customer’s collector substation, and each metering point will be rated per transformer size.
The Transmission Provider will specify and order all interconnection revenue metering, including the instrument transformers, meters, meter panel, junction box, and secondary metering wire. The
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primary metering transformers will be combination 345kV CT/VT units with extended range CTs for high-accuracy metering.
The metering design package will include two revenue quality meters for each meter point with DNP real time digital data terminated at a metering interposition block. One meter will be
designated as primary SCADA meter with DNP data delivered to the primary control center. A
second meter will be designated as backup SCADA meter with DNP data delivered to the alternate control center. The metering data will include bidirectional KWH and KVARH revenue quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps data.
An Ethernet connection is required for retail sales and generation accounting via the MV-90 translation system. Generation Metering
The solar and battery activity will be metered separately. Metering for this purpose will be located
at the Interconnection Customer’s collector substation on the DC side of each inverter. Separate metering will be required for each individual battery resource and each individual solar resource. The metering will be rated for the capacity of each source. The Transmission Provider will specify and order all interconnection revenue metering, including the current and voltage
sensors/converters, meters, meter enclosures, and secondary metering wire.
The Interconnection Request consists of 86 inverters, with battery and solar attached at the DC side of each inverter. This will require 172 metering points to measure battery and solar separately. For meters measuring generation, the Transmission Provider requires primary and backup meters
at each point. Therefore, this project is expected to require 344 DC meters.
The metering design package will include two revenue quality meters at each metering point with
real time digital data to the Transmission providers SCADA system. One meter will be designated as primary SCADA meter with data delivered to the primary control center. A second meter will be designated as backup SCADA meter with data delivered to the alternate control center. The metering data will include bidirectional KWH revenue quantities. The meter data will also include instantaneous MW, voltage, and amps data.

Station Service The Project is within the Transmission Provider’s service territory. Please note that prior to back
feed, Interconnection Customer must arrange transmission retail meter service for electricity
consumed by the Project that will be drawn from the transmission system when the Project is not
generating. Interconnection Customer must call the Help Desk at 1-800‐625‐6078 to arrange this
service. Approval for back feed is contingent upon obtaining station service.
TCS-25
Interchange Metering The overall project metering will be located at Point of Interconnection substation. This will
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require one metering point. This metering will be rated for the total net generation of the Project. The Transmission Provider will specify and order all interconnection revenue metering, including the instrument transformers, meters, meter panel, junction box, and secondary metering wire. The primary metering transformers will be combination 138kV CT/VT units with extended range CTs for high-accuracy metering.
The metering design package will include two revenue quality meters with DNP real time digital
data terminated at a metering interposition block. One meter will be designated as primary SCADA meter with DNP data delivered to the primary control center. A second meter will be designated as backup SCADA meter with DNP data delivered to the alternate control center. The metering data will include bidirectional KWH and KVARH revenue quantities. The meter data will also
include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps data.
An Ethernet connection is required for retail sales and generation accounting via the MV-90 translation system.

Station Service
The Project is within the Transmission Provider’s service territory. Please note that prior to back feed, Interconnection Customer must arrange transmission retail meter service for electricity consumed by the Project that will be drawn from the transmission system when the Project is not generating. Interconnection Customer must call the Help Desk at 1-800‐625‐6078 to arrange this service. Approval for back feed is contingent upon obtaining station service.
TCS-41 Interchange Metering The overall project metering will be located at South Milford substation. This will require one metering point. This metering will be rated for the total net generation of the Project.
The Transmission Provider will specify and order all interconnection revenue metering, including the instrument transformers, meters, meter panel, junction box, and secondary metering wire. The primary metering transformers will be combination 46kV CT/VT units with extended range CTs
for high-accuracy metering.
The metering design package will include two revenue quality meters with DNP real time digital data terminated at a metering interposition block. One meter will be designated as primary SCADA meter with DNP data delivered to the primary control center. A second meter will be designated
as backup SCADA meter with DNP data delivered to the alternate control center. The metering
data will include bidirectional KWH and KVARH revenue quantities. The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps data.
An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system. Station Service
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The Project is within the Transmission Provider’s service territory. Please note that prior to back feed, Interconnection Customer must arrange transmission retail meter service for electricity
consumed by the Project that will be drawn from the transmission system when the Project is not
generating. Interconnection Customer must call the Help Desk at 1-800‐625‐6078 to arrange this
service. Approval for back feed is contingent upon obtaining station service.
8.0 CONTINGENT FACILITIES (ERIS)
The following Interconnection Facilities and/or upgrades to the Transmission Provider’s system are Contingent Facilities applicable to this Cluster Area.

Potential Contingent Facility Outage(s) Overload/ Violation Overload/ Violation % Change
Contingent Facility (Yes/No)
Responsible Entity Planned ISD
Four breaker
ring bus adjacent to South Milford
substation
N/A N/A N/A N/A Yes Q0820 TBD
Milford 138-46 kV XFMR upgrade to 112 MVA
N-0 113% 150% 37% Yes Q0820 TBD
Milford 2nd 397 ACSR 46 kV
line and additional 46 kV
breaker at
Milford-South Milford 46 kV
128%
(Brooklawn-Cameron)
185% (estimated. Case won't solve)
57% Yes Q0820 TBD
Tushar - Sevier Tap- Sigurd 138 CB 112 @ Parowan 105% 110% 101% 108% 112% 103% 3% 2% 2% Yes Q0820 TBD
Gateway South N-2 Mona - Mercer #2 & #4 78% 84% 6% No PAC 4Q24
Lakeside I RAS Modification
City and
Dynamo - Shoreline - Tri
City 345 kV lines (credible
Highland -
Hale 123.6% Timp -
Cherrywood 125.8%
Highland -
Hale 124.2% Timp -
Cherrywood 126.2%
0.6% 0.4% No PAC 1Q22
0.02 PAC 2Q22
transformer and yard project N-1-1 No PAC
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9.0 COST ESTIMATE (ERIS)
The following estimate represents only scopes of work that will be performed by the Transmission Provider. Costs for any work being performed by the Interconnection Customer and/or Affected Systems are not included.
9.1 Interconnection Facilities
The following facilities are directly assigned to Interconnection Customer(s) using such facilities. If multiple Interconnection Requests are utilizing the same Transmission Provider Interconnection Facilities the costs shall be shared pursuant to Section 39.2.3 of Transmission Provider’s OATT.
TCS-07 TCS-07 Collector substation $20,000 Develop new relay settings
POI substation $540,000
Line position and metering
Total: $560,000 TCS-09
TCS-09 Collector substation $4,630,000
Control house, metering and communications equipment POI substation $980,000 Line termination and metering

Total: $5,610,000 TCS-25 TCS-25 Collector substation $80,000
Relay settings and communications POI substation $560,000 Line termination and metering
Total: $640,000 TCS-41 South Milford substation $520,000 Line termination and metering
Total: $520,000
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9.2 Station Equipment
The following are Network Upgrades which are allocated based on the number of Generating
Facilities interconnecting at an individual station on a per Interconnection Request basis. Interconnection Requests utilizing the same Interconnection Facilities shall be consider one request for this allocation. TCS-07 POI substation $4,400,000
New single 46kV breaker substation Total: $4,400,000
TCS-09 POI substation $11,240,000 Install new 345kV three breaker ring bus with three line positions
Total: $11,240,000 TCS-25 POI substation $6,470,000 New 138kV breaker & a half substation with three line positions
&transformer protection panel

Total: $6,470,000 TCS-41
South Milford substation $1,200,000
Add 46kV breaker, switches, line relay panel, and buss differential panel
Total: $1,200,000
9.3 Network Upgrades
The funding responsibility for Network Upgrades other than those identified in the previous
section shall be allocated based on the proportional capacity of each individual Generating Facility. Mercer substation $5,200,000
New 345kV line position, breaker, & shunt reactor
Spanish Fork substation $9,360,000 New 345kV bay, breakers, shunt reactor, and yard expansion
Camp Williams substation $4,820,000
Replace 345kV breakers, install bus differential and breaker control panels Mona substation $1,480,000
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Replace 345kV breaker, install bus differential and breaker control panels
Oquirrh substation $344,000
Replace 138kV breaker Sigurd substation $506,000 Replace 230kV breaker
Milford substation $2,350,000 Increase Transformer Capacity
Mercer – Spanish Fork 345kV Transmission line $96,640,000
Construct new 50-mile 345 kV transmission line Milford – Q0820 POI 46kV #1 tie line $4,880,000 Reconductor approximately 7.22 miles
Milford – Q0820 POI 46kV #2 tie line $4,880,000
Reconductor approximately 7.22 miles Nebo substation $40,000
Modify communications
Vickers substation $380,000 Install 46kV VT’s, relaying, and communications
Scipio – Vickers 46kV tie line $180,000
Loop in/loop out of new TCS-07 POI substation
Camp Williams – Mona 345kV tie line $1,720,000 Loop in/loop out of new TCS-09 POI substation
West Cedar substation $230,000
Replace line relay panel and modify communications Holt substation $40,000
Update relay settings
Red Butte – West Cedar 138kV tie line $320,000 Loop in/loop out of new TCS-25 POI substation
Network Upgrade Total: $133,370,000

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9.4 Total Estimated Project Costs
TCS-07 Interconnection Facilities $560,000 Station Equipment $4,400,000 Network Upgrades $6,999,000 Total: $11,959,000 TCS-09 Interconnection Facilities $5,610,000 Station Equipment $11,240,000
Network Upgrades $104,988,000 Total: $121,838,000 TCS-25 Interconnection Facilities $640,000
Station Equipment $6,470,000 Network Upgrades $10,499,000 Total: $17,609,000 TCS-41
Interconnection Facilities $520,000 Station Equipment $1,200,000 Network Upgrades $10,884,000 Total: $12,604,000
Grand Total $164,010,000
10.0 SCHEDULE (ERIS)
The Transmission Provider estimates it will require approximately 72 months to design, procure and construct the facilities described in this report following the execution of Interconnection Agreements. The schedule will be further developed and optimized during the Facilities Studies.
11.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS – NRIS
The Transmission Provider has not identified any additional requirements to provide NRIS to those Interconnection Customer’s requesting NRIS beyond the ERIS requirements identified in this report.
12.0 AFFECTED SYSTEMS
Transmission Provider has identified the following affected systems: NV Energy, UAMPS,
Deseret Power A copy of this report will be shared with each Affected System.
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13.0 APPENDICES
Appendix 1: Cluster Area Power Flow and Stability Study Results
Appendix 2: Higher Priority Requests Appendix 3: Property Requirements
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13.1 Appendix 1: Cluster Area Power Flow and Stability Study Results
A Western Electricity Coordinating Council (WECC) approved 2025 Heavy Summer case was
used to perform the power flow studies using PSS/E version 34.6.0. Power flow studies were performed on a peak load base case. Local 345 kV, 230 kV and 138 kV transmission system outages were considered. The following table describes the outage, the issue(s) that arises from each outage and the proposed mitigation.

line 345 kV line
overloads to 101% of
Huntington on the
Emery – Huntington
345 kV line
Steel Mill – Spanish Fork 345 kV 138 kV line overloads to 100.2% Spanish Fork – Mercer 345 kV line
Camp Williams – Steel Mill 345
kV lines
138 kV line overloads to 104.3%

Spanish Fork – Mercer 345 kV line

Replace the 75 MVA 138 – 46 kV transformer at Milford Substation with a 125 MVA unit. Reduction of generation to 22 MW would avoid transformer replacement.
Rebuild both the existing and the new (identified for Q0820) 46 kV Milford-South Milford lines
to 795 ACSR. Reduction of generation to 15.1 MW would avoid required line rebuilds from Milford to South Milford.
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13.2 Appendix 2: Higher Priority Requests
All active higher priority Transmission Provider projects, and transmission service and/or
generator interconnection requests will be considered in this cluster area study and are identified below. If any of these requests are withdrawn, the Transmission Provider reserves the right to restudy this request, as the results and conclusions contained within this study could significantly change.
Transmission/Generation Interconnection Queue Requests considered:

LGI Q# MW
TSR Q#
632 2.99
634 99
636 99
642 58
752 40 2867
763 200 2872/2873
777 100
778 200 2879
787 200
788 200
792 80
799 67
804 80 2602
805 95
815 20
823 178
838 525

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13.3 Appendix 3: Property Requirements
Property Requirements for Point of Interconnection Substation
Requirements for rights of way easements Rights of way easements will be acquired by the Interconnection Customer in the Transmission Provider’s name for the construction, reconstruction, operation, maintenance, repair, replacement and removal of Transmission Provider’s Interconnection Facilities that will be owned and operated by PacifiCorp. Interconnection Customer will acquire all necessary permits for the
Project and will obtain rights of way easements for the Project on Transmission Provider’s easement form. Real Property Requirements for Point of Interconnection Substation
Real property for a point of interconnection substation will be acquired by an Interconnection
Customer to accommodate the Interconnection Customer’s Project. The real property must be acceptable to Transmission Provider. Interconnection Customer will acquire fee ownership for interconnection substation unless Transmission Provider determines that other than fee ownership is acceptable; however, the form and instrument of such rights will be at Transmission
Provider’s sole discretion. Any land rights that Interconnection Customer is planning to retain as
part of a fee property conveyance will be identified in advance to Transmission Provider and are subject to the Transmission Provider’s approval. The Interconnection Customer must obtain all permits required by all relevant jurisdictions for
the planned use including but not limited to conditional use permits, Certificates of Public
Convenience and Necessity, California Environmental Quality Act, as well as all construction permits for the Project. If eligible, Interconnection Customer will not be reimbursed through network upgrades for more
than the market value of the property.
As a minimum, real property must be environmentally, physically, and operationally acceptable to Transmission Provider. The real property shall be a permitted or able to be permitted use in all zoning districts. The Interconnection Customer shall provide Transmission Provider with a title
report and shall transfer property without any material defects of title or other encumbrances that
are not acceptable to Transmission Provider. Property lines shall be surveyed and show all encumbrances, encroachments, and roads. Examples of potentially unacceptable environmental, physical, or operational conditions could
include but are not limited to:
1. Environmental: known contamination of site; evidence of environmental contamination by any dangerous, hazardous or toxic materials as defined by any governmental agency; violation of building, health, safety, environmental, fire,
land use, zoning or other such regulation; violation of ordinances or statutes of
any governmental entities having jurisdiction over the property; underground or above ground storage tanks in area; known remediation sites on property; ongoing mitigation activities or monitoring activities; asbestos; lead-based paint, etc. A
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phase I environmental study is required for land being acquired in fee by the Transmission Provider unless waived by Transmission Provider.
2. Physical: inadequate site drainage; proximity to flood zone; erosion issues; wetland overlays; threatened and endangered species; archeological or culturally sensitive areas; inadequate sub-surface elements, etc. Transmission Provider may require Interconnection Customer to procure various studies and surveys as
determined necessary by Transmission Provider. Operational: inadequate access for Transmission Provider’s equipment and vehicles; existing structures on land that require removal prior to building of substation; ongoing maintenance for
landscaping or extensive landscape requirements; ongoing homeowner's or other requirements or
restrictions (e.g., Covenants, Codes and Restrictions, deed restrictions, etc.) on property which are not acceptable to the Transmission Provider.

Generation Interconnection Transition Cluster
Transition Cluster Study Report
Cluster Area 5

October 22, 2021

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Transition Cluster Area 5 Page i October 22, 2021

TABLE OF CONTENTS
1.0 SCOPE OF THE STUDY ................................................................................................................. 1 2.0 STUDY ASSUMPTIONS ................................................................................................................. 1 3.0 GENERATING FACILITY REQUIREMENTS .............................................................................. 3 3.1 Transmission Voltage Interconnection Requests .............................................................................. 3 3.2 Distribution Voltage Interconnection Requests ................................................................................ 6
4.0 CLUSTER AREA DEFINITIONS ................................................................................................... 6 5.0 CLUSTER AREA 5 .......................................................................................................................... 6 5.1 Description of Interconnection Request – TCS-11 ........................................................................... 7 6.0 SITE SPECIFIC GENERATING FACILITY REQUIREMENTS ................................................... 8 7.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS - NRIS ............................................ 9 7.1 Transmission System Requirements ................................................................................................. 9 7.2 Distribution System Requirements ................................................................................................... 9 7.3 Transmission Line Requirements ...................................................................................................... 9 7.4 Existing Circuit Breaker Upgrades – Short Circuit ........................................................................... 9 7.5 Protection Requirements ................................................................................................................. 10 7.6 Data (RTU) Requirements .............................................................................................................. 10 7.7 Substation Requirements ................................................................................................................. 12 7.8 Communication Requirements ........................................................................................................ 13 7.9 Metering Requirements ................................................................................................................... 13 8.0 CONTINGENT FACILITIES (NRIS) ............................................................................................ 14 9.0 COST ESTIMATE (NRIS) ............................................................................................................. 14 9.1 Interconnection Facilities ................................................................................................................ 14 9.2 Station Equipment ........................................................................................................................... 15 9.3 Network Upgrades .......................................................................................................................... 15 9.4 Total Estimated Project Costs ......................................................................................................... 16 10.0 SCHEDULE (NRIS) ....................................................................................................................... 16 11.0 AFFECTED SYSTEMS ................................................................................................................. 16 12.0 APPENDICES ................................................................................................................................ 16 12.1 Appendix 1: Cluster Area Power Flow and Stability Study Results ............................................... 17 12.2 Appendix 2: Higher Priority Requests ............................................................................................ 18 12.3 Appendix 3: Property Requirements ............................................................................................... 19
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1.0 SCOPE OF THE STUDY
This cluster restudy is being performed due to the withdrawal of several interconnection requests
that were included in the original cluster study. Cluster Area 5 (CA5) is generally described as eastern Idaho and includes the following Interconnection Request: TCS-11
Consistent with Attachment W, Section 3.4.2 and Section 51.4 of PacifiCorp’s (“Transmission Provider”) Open Access Transmission Tariff (“OATT”), this interconnection Transition Cluster Study (“Cluster Study”) evaluated the impact of the proposed interconnections on the reliability of the Transmission System. The Cluster Study considered the Base Case as well as all generating
facilities (and with respect to (iii) below, any identified Network Upgrades associated with such
higher queued interconnection) that, on the date the Cluster Request Window closes: (i) are existing and directly interconnected to the Transmission System; (ii) are existing and interconnected to Affected Systems and may have an impact on the
Interconnection Request;
(iii) have a pending higher queued or higher clustered interconnection request to interconnect to the transmission system; and (iv) have executed an LGIA or requested that an unexecuted LGIA be filed with FERC.
The Cluster Study consisted of power flow, stability, and short circuit analyses.
This Cluster Study report provides the following information:
• identification of any circuit breaker short circuit capability limits exceeded as a result of the
interconnection;
• identification of any thermal overload or voltage limit violations resulting from the interconnection;
• identification of any instability or inadequately damped response to system disturbances
resulting from the interconnection and
• description and non-binding, good faith estimated cost of facilities required to interconnect the Generating Facilities to the Transmission System and to address the identified short circuit, instability, and power flow issues.
2.0 STUDY ASSUMPTIONS
• All active higher priority transmission service and/or generator interconnection requests that were considered in this study are listed in Appendix 2. If any of these requests are withdrawn, the Transmission Provider reserves the right to restudy this request, and the results and conclusions could significantly change.
• For study purposes there are two separate queues:
o Transmission Service Queue: to the extent practical, all network upgrades that are required to accommodate active transmission service requests were modeled in this study.
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o Generation Interconnection Queue: Interconnection Facilities and network upgrades associated with higher queued or higher clustered interconnection
requests were modeled in this study.
• The Interconnection Customers’ request for energy or network resource interconnection service in and of itself does not request or convey transmission service. Only a Network Customer may make a request to designate a generating resource as a Network Resource.
Because the queue of higher priority transmission service requests may be different when
a Network Customer requests network resource designation for this Generating Facility, the available capacity or transmission modifications, if any, necessary to provide Network Integration Transmission Service may be significantly different. Therefore, Interconnection Customers should regard the results of this study as informational rather
than final.
• Under normal conditions, the Transmission Provider does not dispatch or otherwise directly control or regulate the output of generating facilities. Therefore, the need for transmission modifications, if any, that may be required to provide Network Resource
Interconnection Service will be evaluated on the basis of 100 percent deliverability (i.e.,
this study did not model displacement of other resources in the same area).
• This study assumed the Projects will be integrated into the Transmission Provider’s system at agreed upon and/or proposed Points of Interconnection (“POI” or “POIs”).
• If Interconnection Customers proceed through the interconnection process, they will be required to construct and own any facilities required between the Point of Change of Ownership and the Project unless specifically identified by the Transmission Provider.
• Line reconductor or fiber underbuild required on existing poles were assumed to follow the
most direct path on the Transmission Provider’s system. If during detailed design the path must be modified it may result in additional cost and timing delays for the Interconnection Customer’s Project.
• Generator tripping may be required for certain outages.
• All facilities will meet or exceed the minimum Western Electricity Coordinating Council
(“WECC”), North American Electric Reliability Corporation (“NERC”), and the Transmission Provider’s performance and design standards.
• Power flow analysis requires WECC base cases to reliably balance under peak load
conditions the aggregate of generation in the local area, with the Generating Facility at full
output, to the aggregate of the load in the Transmission Provider’s Transmission System. As the (“PACE”) balancing authority area (“BAA”) has more existing and proposed generation than load, it is necessary to assume some portion of other resources are displaced by this Project’s output in order to assess the impact of interconnecting this
Project’s generation to transmission system operations. For the purposes of this study,
generation in the Transmission Provider’s southern Utah area was assumed to be displaced.
• The following Transmission Provider planned system improvements were assumed in service:
o Path C improvement project, Bridgerland 345 kV substation (Q4 2023)
o Third Goshen 345/161 kV transformer (Q4 2022)
o Goshen – Ammon – Sugar Mill 161 kV line (Q2 2022)
o Antelope – Goshen 345 kV line
• This report is based on information available at the time of the study. It is the Interconnection Customer’s responsibility to check the Transmission Provider’s web site
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regularly for Transmission System updates at https://www.oasis.oati.com/ppw
3.0 GENERATING FACILITY REQUIREMENTS
The following requirements are applicable to all Interconnection Requests. The Transmission Provider will identify any site-specific generating facility requirements in addition to the following in this report and in facilities studies. Certain Interconnection Requests requesting service at a voltage level traditionally defined as distribution may be subject to the transmission interconnection request requirements listed below should the Transmission Provider make that
determination.
3.1 Transmission Voltage Interconnection Requests
All interconnecting synchronous and non-synchronous generators are required to design their Generating Facilities with reactive power capabilities necessary to operate within the full power
factor range of 0.95 leading to 0.95 lagging. This power factor range shall be dynamic and can be
met using a combination of the inherent dynamic reactive power capability of the generator or inverter, dynamic reactive power devices and static reactive power devices to make up for losses. For synchronous generators, the power factor requirement is to be measured at the POI. For non-
synchronous generators, the power factor requirement is to be measured at the high-side of the
generator substation. The Generating Facility must provide dynamic reactive power to the system in support of both voltage scheduling and contingency events that require transient voltage support, and must be able
to provide reactive capability over the full range of real power output.
If the Generating Facility is not capable of providing positive reactive support (i.e., supplying reactive power to the system) immediately following the removal of a fault or other transient low voltage perturbations, the facility must be required to add dynamic voltage support equipment.
These additional dynamic reactive devices shall have correct protection settings such that the
devices will remain on line and active during and immediately following a fault event. Generators shall be equipped with automatic voltage-control equipment and normally operated with the voltage regulation control mode enabled unless written authorization (or directive) from
the Transmission Provider is given to operate in another control mode (e.g. constant power factor
control). The control mode of generating units shall be accurately represented in operating studies. The generators shall be capable of operating continuously at their maximum power output at its rated field current within +/- 5% of its rated terminal voltage.
All generators are required to ensure the primary frequency capability of their Facility by
installing, maintaining, and operating a functioning governor or equivalent controls as indicated in FERC Order 842. As required by NERC standard VAR-001-4.2, the Transmission Provider will provide a voltage
schedule for the POI. In general, Generating Facilities should be operated so as to maintain the
voltage at the POI, typically between 1.00 per unit to 1.04 per unit, or other designated point as deemed appropriated by Transmission Provider. The Transmission Provider may also specify a
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voltage and/or reactive power bandwidth as needed to coordinate with upstream voltage control devices such as on-load tap changers. At the Transmission Provider’s discretion, these values
might be adjusted depending on operating conditions. Generating Facilities capable of operating with a voltage droop are required to do so. Voltage droop control enables proportionate reactive power sharing among Generation Facilities. Studies will be required to coordinate voltage droop settings if there are other facilities in the area. It will
be the Interconnection Customer’s responsibility to ensure that a voltage coordination study is performed, in coordination with Transmission Provider, and implemented with appropriate coordination settings prior to unit testing.
For areas with multiple generating facilities additional studies may be required to determine
whether or not critical interactions, including but not limited to control systems, exist. These studies, to be coordinated with Transmission Provider, will be the responsibility of the Interconnection Customer. If the need for a master controller is identified, the cost and all related installation requirements will be the responsibility of the Interconnection Customer. Participation
by the Generation Facility in subsequent interaction/coordination studies will be required pre- and
post-commercial operation in order ensure system reliability.
Interconnection Requests that are 75 MVA or larger may be required to facilitate collection and
validation of accurate modeling data to meet NERC modeling standards. The Transmission
Provider, in its roles as the Planning Coordinator, requires Phasor Measurement Units (PMUs) at all new Generating Facilities with an individual or aggregate nameplate capacity of 75 MVA or greater. In addition to owning and maintaining the PMU, the Generating Facility will be responsible for collecting, storing (for a minimum of 90 days) and retrieving data as requested by
the Planning Coordinator. Data must be stored for a minimum of 90 days. Data must be collected
and be able to stream to Planning Coordinator for each of the Generating Facility’s step-up transformers measured on the low side of the GSU at a sample rate of at least 60 samples per second and synchronized within +/- 2 milliseconds of the Coordinated Universal Time (UTC). Initially, the following data must be collected:
• Three phase voltage and voltage angle (analog)
• Three phase current (analog) Data requirements are subject to change as deemed necessary to comply with local and federal
regulations.
All generators must meet the Federal Energy Regulatory Commission (FERC), North American Electric Reliability Corporation (NERC) and WECC low voltage ride-through requirements as specified in the interconnection agreement. Inverters must be designed to stay connected to the
grid in the case of severe faults and may not momentarily cease output within the no-trip area of
the voltage curves. Figure 1 illustrates the voltage ride-through capability as per NERC PRC-024. Importantly, inverters should be designed such that a trip outside of the curves is a “may-trip” area (if needed to protect equipment) not a “must-trip” area. Inverters that momentarily cease active power output for these voltage excursions should be configured to restore output to pre-
disturbance levels in no greater than five seconds, provided the inverter is capable of these changes.
Generators must provide test results to the Transmission Provider verifying that the inverters for
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this Project have been programmed to meet all PRC-024 requirements rather than manufacturer IEEE distribution standards.

Figure 1 – Voltage Ride-Through Curve As the Transmission Provider cannot submit a user written model to WECC for inclusion in base cases, a standard model from the WECC Approved Dynamic Model Library is required 180 days
prior to trial operation. The list of approved generator models is continually updated and is available on the http://www.WECC.biz website. Interconnection Customer with an Interconnection Request for a Generating Facility that is both
75 MVA or larger as well as being interconnected at a voltage higher than 100 kV shall register
with NERC as the Generator Owner (“GO”) and Generator Operator (“GOP”) for the Large Generating Facility and provide the Transmission Provider documentation demonstrating registration in order to be approved for Commercial Operation. This registration must be maintained throughout the lifetime of the Interconnection Agreement.

Interconnection Customers are responsible for the protection of transmission lines between the Generating Facility and the POI substation. For Interconnection Requests that are smaller than 75 MVA or are interconnected at a voltage less than 100 kV which have a tie line that is longer than 1,000 feet the Interconnection Customer shall construct and own a tie-line substation to be located
at the change of ownership (separate fenced facility adjacent to the Transmission Provider’s POI
substation). The tie line substation shall include an Interconnection Customer owned protective device and associated transmission line relaying/communications. The ground grids of the Transmission Provider’s POI substation and the Interconnection Customer’s tie-line substation will be connected to support the use of a bus differential protection scheme which will protect the
overhead bus connection between the two facilities.
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3.2 Distribution Voltage Interconnection Requests
The Generating Facility and interconnection equipment owned by the Interconnection Customers
are required to operate under constant power factor mode with a unity power factor setting unless specifically requested otherwise by the Transmission Provider. The Generating Facilities are expressly forbidden from actively participating in voltage regulation of the Transmission Provider’s system without written request or authorization from the Transmission Provider. The Generating Facilities shall have sufficient reactive capacity to enable the delivery of 100 percent
of the plant output to the applicable POI at unity power factor measured at 1.0 per unit voltage under steady state conditions. Generators capable of operating under voltage control with voltage droop are required to do so.
Studies will be required to coordinate the voltage droop setting with other facilities in the area. In
general, the Generating Facility and Interconnection Equipment should be operated so as to maintain the voltage at the POI between 1.01 pu to 1.04 pu. At the Public Utility’s discretion, these values might be adjusted depending on the operating conditions. Within this voltage range, the Generating Facility should operate so as to minimize the reactive interchange between the
Generating Facility and the Public Utility’s system (delivery of power at the POI at approximately
unity power factor). The voltage control settings of the Generating Facility must be coordinated with the Public Utility prior to energization (or interconnection). The reactive compensation must be designed such that the discreet switching of the reactive device (if required by the Interconnection Customer) does not cause step voltage changes greater than +/-3% on the Public
Utility’s system.
All generators must meet applicable WECC low voltage ride-through requirements as specified in the interconnection agreement.
As per NERC standard VAR-001-1, the Public Utility is required to specify voltage or reactive
power schedule at the POI. Under normal conditions, the Public Utility’s system should not supply reactive power to the Generating Facility.
4.0 CLUSTER AREA DEFINITIONS
The Transmission Provider performed the Transition Cluster Study based on geographically and/or
electrically relevant areas on the Transmission Provider’s Transmission System known as Cluster
Areas. The Transmission Provider has determined that the Interconnection Requests discussed in Section 5.0 are located in a geographically and/or electrically relevant area on Transmission Provider’s Transmission System, and thus, were assigned Cluster Area 5 in the Transition Cluster Study process.
5.0 CLUSTER AREA 5
Cluster Area 5 (CA5) is generally described as eastern Idaho. It is electrically defined as Amps 230 kV and Big Grassy 161 kV substations on the northern border, the Midpoint 345 kV substation on the western border, the Threemile Knoll 345 kV substation on the eastern border, and the Populus 345 kV substation on the southern border. This Cluster Area consists of the following
Interconnection Request.
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5.1 Description of Interconnection Request – TCS-11
The Interconnection Customer has proposed to interconnect 600 megawatts (“MW”) of new
generation to PacifiCorp’s (“Transmission Provider”) Antelope 230 kV substation located in Butte County, Idaho. The Interconnection Request is proposed to consist of twelve (12) 70.59 MVA Siemens nuclear powered steam turbine generators for a total output of 600 MW at the POI. The requested commercial operation date is September 1, 2030. Figure 2 below, is a one-line diagram that illustrates the interconnection of the proposed Generating Facility to the Transmission
Provider’s system. Interconnection Customer will NOT operate this generator as a Qualified Facility as defined by the Public Utility Regulatory Policies Act of 1978 (PURPA).

The Interconnection Request will be studied for Network Resource Interconnection Service (“NRIS”). The Transmission Provider has assigned the Project Cluster Number “TCS-11”

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230 kV
345 kV
161 kV
Change of Ownership
11 Miles
230 kV
138 kV 70
.4
MV
A

13
.8
kV

a
c
h
240/320/400 MVAZ = 7.5 % Each
TC-11Generation
Facility
Points of Interconnection
AntelopeSubstation
15.5 MVAR
420/560/700 MVAZ = 7 %
Brady
Lost River
MM
M
1 2 3
4 5
6 7 8
1 2 3
4 5 6
7 8 9
10 11 12
13 14 15
16 17 18
19 20 21
22 23 24
Amps
Goshen Figure 2: Simplified System One Line Diagram TCS-11
6.0 SITE SPECIFIC GENERATING FACILITY REQUIREMENTS
In addition to the requirements described above the following Generating Facility are required for
the specific Interconnection Requests listed below. Nothing additional identified.
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7.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS - NRIS
7.1 Transmission System Requirements
The following transmission system improvements are required to accommodate the Interconnection Requests in this Cluster Area:
• Rebuild 44-miles of the Goshen–Fish Creek 161 kV transmission line.
• Rebuild 25-miles of the Grace–Oneida–Treasureton 138 kV transmission line.
• Improvements to West of Populus path (Adelaide – Borah 345 kV). Mitigation to be coordinated with Idaho Power Company who is a joint owner.

Refer to Appendix 1 for more details regarding the necessity for these required upgrades. The following are station upgrades required for each of the Interconnection Requests within this Cluster Area.
TCS-11 Expand the Antelope substation to the east to incorporate two additional 230 kV bays and line positions to serve as the POI.
7.2 Distribution System Requirements
No upgrades to the Transmission Provider’s distribution system have been identified for the
Interconnection Requests in this Cluster Area.
7.3 Transmission Line Requirements
The requirement to rebuild the 44-mile Goshen – Fish Creek 161kV line to accommodate a larger conductor has been identified. It is assumed this will be a complete line rebuild with pole
for pole structure replacements.
The requirement to rebuild the 25-mile Grace – Oneida – Treasureton 138kV line with a larger conductor has also been identified. This will also be a pole for pole line rebuild. The Interconnection Customer shall construct the last structures of each of its two tie lines and span/bus connection into the POI substation to Transmission Provider standards. The Transmission Provider will review the design of the Interconnection Customer lines for the last span into the POI substations. The Interconnection Customers shall coil enough fiber and
conductor on the last deadend structures to make the span into the POI substation. The
Transmission Provider shall construct the final terminations into the POI substation. If the Interconnection Customer’s tie lines are required to cross a Transmission Provider line, the Interconnection Customer shall make application with the Transmission Provider to do so. The
Interconnection Customer’s line(s) shall cross below the Transmission Provider’s line in all cases
unless the Interconnection Customer’s line is of a greater voltage.
7.4 Existing Circuit Breaker Upgrades – Short Circuit
TCS-11
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The TCS-11 project will have 12 – 70.4 MW nuclear reactor generators each fed through a 75 MVA 138 – 13.8 kV transformer with 9 % impedance and then the power from the generators is
fed through 3 – 230 – 138 kV 240/320/400 MVA transformers with 7.5 % impedance.
7.5 Protection Requirements
Due to the rebuilding of the Goshen–Grace 161 kV line, and the Grace–Oneida and Oneida–Treasureton 138 kV lines; new line relay settings will need to be developed for each terminal of these transmission lines.
TCS-11 The proposed TCS-11 project will be connected to the transmission network via the Antelope
substation 230 kV bus. The Amps 230 kV line will be moved two bays to the east to accommodate the termination of the two 230 kV tie lines at Antelope substation. The west tie line will be terminated in the old Amps line position. Line current differential relay systems will be applied for each of the three 230 kV lines. The Transmission Provider will install, own, and maintain two relay panels at the TCS-11 collector substation with line relays that will be compatible with the
line relays to be installed at Antelope substation. The line relays at the collector substation will communicate with the line relays at Antelope substation. The relays on this panel will be connected to monitor the current through the 230 kV line breakers at the collector substation that the 230 kV lines are terminated between and the voltage on the 230 kV line. For faults on the tie lines the line breakers at both terminals will be tripped.
Relay elements in the line relays at the Antelope substation will monitor the line voltages. If the voltage, magnitude or frequency, is outside of the normal operation range these relay elements will trip open the 230 kV tie line breakers at Antelope substation.
7.6 Data (RTU) Requirements
The Transmission Provider will remotely monitor and operate the new breakers at the POI
substations using the RTU at those substations. RTUs will need to be installed in TCS-11 collector substation to monitor activities in those substations. The following data must be monitored for these projects in the individual substations:
TCS-11 Collector Substation:
Analog Written to the RTU:
 Max Gen Limit MW Set Point Analogs:
 Max Gen Limit MW Set Point Feed Back
 Potential Power MW
 230 – 138 kV transformer #1 MW
 230 – 138 kV transformer #1 MVAR
 230 – 138 kV transformer #2 MW
 230 – 138 kV transformer #2 MVAR
 230 – 138 kV transformer #3 MW
 230 – 138 kV transformer #3 MVAR
 230 kV A phase voltage
 230 kV B phase voltage
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 230 kV C phase voltage
 Generator #1 MW
 Generator #1 MVAR
 Generator #2 MW
 Generator #2 MVAR
 Generator #3 MW
 Generator #3 MVAR
 Generator #4 MW
 Generator #4 MVAR
 Generator #5 MW
 Generator #5 MVAR
 Generator #6 MW
 Generator #6 MVAR
 Generator #7 MW
 Generator #7 MVAR
 Generator #8 MW
 Generator #8 MVAR
 Generator #9 MW
 Generator #9 MVAR
 Generator #10 MW
 Generator #10 MVAR
 Generator #11 MW
 Generator #11 MVAR
 Generator #12 MW
 Generator #12 MVAR Status:
 230 kV breaker #1
 230 kV breaker #2
 230 kV breaker #3
 230 kV breaker #4
 230 kV breaker #5
 230 kV breaker #6
 230 kV breaker #7
 230 kV breaker #8
 138 kV breaker #1
 138 kV breaker #2
 138 kV breaker #3
 138 kV breaker #4
 138 kV breaker #5
 138 kV breaker #6
 138 kV breaker #7
 138 kV breaker #8
 138 kV breaker #9
 138 kV breaker #10
 138 kV breaker #11
 138 kV breaker #12
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 138 kV breaker #13
 138 kV breaker #14
 138 kV breaker #15
 138 kV breaker #16
 138 kV breaker #17
 138 kV breaker #18
 138 kV breaker #19
 138 kV breaker #20
 138 kV breaker #21
 138 kV breaker #22
 138 kV breaker #23
 138 kV breaker #24
 13.8 kV breaker Gen #1
 13.8 kV breaker Gen #2
 13.8 kV breaker Gen #3
 13.8 kV breaker Gen #4
 13.8 kV breaker Gen #5
 13.8 kV breaker Gen #6
 13.8 kV breaker Gen #7
 13.8 kV breaker Gen #8
 13.8 kV breaker Gen #9
 13.8 kV breaker Gen #10
 13.8 kV breaker Gen #11
 13.8 kV breaker Gen #12
 Tie line #1 relay alarm
 Tie line #2 relay alarm
7.7 Substation Requirements
The following substation modifications have been identified as required and may change during the detailed design: TCS-11:
TCS-11 Collector Substation
The Interconnection Customer will provide a separate graded, grounded and fenced area along the perimeter of the Interconnection Customer’s Generating Facility for the Transmission Provider to install a control house for any required metering, protection or communication equipment. This area will share a fence and ground grid with the
Interconnection Customer’s collector substation and have separate, unencumbered access
for the Transmission Provider. Moreover, The interconnect customer shall provide120/240VAC power to the Transmission Provider’s control building. The DC power to the control building will be provided by the Transmission Provider.
Antelope Substation
Expand the substation yard to the east. Expand the 230kV bus and build (2) new 230kV bays. Move the 230kV Amps line two bays to the east to make room for the (2) 230kV
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generation tie lines. The following equipment has been identified as required and may change during the detailed design:
(4) 230 kV 3000 A 40 kA breakers (6) 230kV CT/VT Combined Metering units (6) 230kV (144kV MCOV) arrestors (5) 230kV, 2000A Group Operated Switches (8) 230kV, 3000A Group Operated Switches
7.8 Communication Requirements
TCS-11 To support proposed new relay circuits from Antelope substation to the TCS-11 site, the Interconnection Customer will install approximately 11 miles of OPGW fiber optic cable on the
line between the two sites. The Transmission Provider will terminate the fiber into Antelope
substation as well as into its portion of the collector substation control building. At Antelope, Amps and the TCS-11 substation, install the electronic communications required to support the new relay circuits. At the TCS-11 collector substation it is assumed that the
Interconnection Customer will provide space in its control building for the Transmission
Provider to install its electronic communications equipment.
7.9 Metering Requirements
TSC-11 Interchange Metering
The overall Project metering will be located at the POI at Antelope substation and rated for the total net generation of the Project. There will be two lines connecting into the POI, which will require two metering points. The Transmission Provider will specify and order all interconnection revenue metering, including the instrument transformers, meters, meter panels, junction boxes, and secondary metering wire. The primary metering transformers will be combination 230kV CT/VT units with extended range CTs for high-accuracy metering.
The metering design package will include two revenue quality meters for each meter point with DNP real time digital data terminated at a metering interposition block. One meter will be designated as primary SCADA meter with DNP data delivered to the primary control center. A second meter will be designated as backup SCADA meter with DNP data delivered to the alternate
control center. The metering data will include bidirectional KWH and KVARH revenue quantities.
The meter data will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps data.
A direct serial connection is required for retail sales and generation accounting via the MV-
90 translation system.
The Interconnection Customer’s proposed Generating Facility, as currently planned, appears to be in Lost River Electric Coop retail service territory. Therefore, Lost River Electric, through its Transmission Provider, will need to submit a transmission service request to obtain the rights to
wheel station service power over the Transmission Provider’s system. Should Lost River Electric
desire to receive data from the POI meters they would need to submit a request. Following which
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the Transmission Provider will plan to install communications equipment to provide KYZs from
the meters to a device that can be installed at the substation fence by Lost River Electric.

Generation Facility Metering Interconnection Customer will be expected to provide metering at the Generation Facility. Real-time and profile data outputs from Generation Facility meters to the Transmission Provider SCADA system and Meter Data Management system will be required.

Station Service/Construction Power Prior to construction, Interconnection Customer must arrange construction power with the Public Utility holding the certificated service territory rights for the area in which the load is physically
located. Please note, prior to back feed, Interconnection Customer must arrange retail meter service
for electricity consumed by the Project when not generating.
8.0 CONTINGENT FACILITIES (NRIS)
The following Interconnection Facilities and/or upgrades to the Transmission Provider’s system are Contingent Facilities applicable to this Cluster Area.

The Transmission Provider’s planned Path C Improvement project is considered contingent for the Interconnection Requests in this Cluster Area and must be complete before any of the Cluster Area generators can be interconnected. The projected in-service date of the Path C Improvement project is Q4 2023.

A new, approximately 45-mile, Antelope-Goshen 345 kV transmission line as identified in the Transmission Service Request (TSR) study Q2611 is considered contingent and must be complete before any of the Cluster Area generators can be interconnected.
9.0 COST ESTIMATE (NRIS)
The following estimate represents only scopes of work that will be performed by the Transmission
Provider. Costs for any work being performed by the Interconnection Customer and/or Affected Systems are not included.
9.1 Interconnection Facilities
The following facilities are directly assigned to Interconnection Customer(s) using such
facilities. If multiple Interconnection Requests are utilizing the same Transmission Provider
Interconnection Facilities the costs shall be shared pursuant to Section 39.2.3 of Transmission Provider’s OATT. TCS-11
Collector substation $1,100,00
Install line relay panels and control house Antelope substation $1,500,000 Two line terminations and metering
Total: $2,600,000

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9.2 Station Equipment
The following are Network Upgrades which are allocated based on the number of Generating
Facilities interconnecting at an individual station on a per Interconnection Request basis. Interconnection Requests utilizing the same Interconnection Facilities shall be consider one request for this allocation. TCS-11 Antelope substation $5,300,000
New 230kV bay, line positions, and four 230kv breakers Total: $5,300,000
9.3 Network Upgrades
The funding responsibility for Network Upgrades other than those identified in the previous
section shall be allocated based on the proportional capacity of each individual Generating Facility. Goshen substation $80,000
Develop new line relay settings
Grace substation $17,000 Develop new line relay settings
Oneida substation $17,000
Develop new line relay settings
Treasureton substation $10,000 Develop new line relay settings
Antelope – Amps 230kV transmission line $120,000
Reroute the Antelope-Amps/Peterson Flat 230kV line Goshen – Fish Creek 161kV transmission line $36,100,000
Rebuild 44 miles of transmission line
Grace – Oneida – Treasureton 138kV transmission line $24,800,000 Rebuild 26 miles of transmission line
Goshen substation $95,000
Install communication equipment Amps substation $25,000 Install communication equipment

Network Upgrade Total: $61,000,000
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9.4 Total Estimated Project Costs
TCS11 Interconnection Facilities $2,600,000 Station Equipment $5,300,000
Network Upgrades $61,000,000 Total: $68,900,000
10.0 SCHEDULE (NRIS)
The Transmission Provider estimates it will require approximately 48 months to design, procure and construct the facilities described in this report following the execution of Interconnection
Agreements. The schedule will be further developed and optimized during the Facilities Studies.
11.0 AFFECTED SYSTEMS
Transmission Provider has identified the following affected systems: Idaho Power Company A copy of this report will be shared with each Affected System.
12.0 APPENDICES
Appendix 1: Cluster Area Power Flow and Stability Study Results Appendix 2: Higher Priority Requests Appendix 3: Property Requirements
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12.1 Appendix 1: Cluster Area Power Flow and Stability Study Results
The Western Electricity Coordinating Council (WECC) approved 2020 Heavy Summer case was
used to perform the power flow studies using PSS/E version 34.8. The 2020 Heavy Summer case was modified for the study year, 2025. The local 345 kV, 230 kV and 138 kV transmission system outages were considered during the study.
kV line #1 overloads to 105% of its Idaho Power Company. Coordinate
transformer 161 kV line overloads to 104% of of Goshen – Fish Creek 161 kV line
Treasureton 138 kV line overloads to
107% of its
of Grace – Oneida – Treasureton 138 kV
line
Three Mile Knoll 161 kV line overloads to 103% of of Goshen – Fish Creek 161 kV line
115, or CBL 102 internal breaker
fault at Treasureton
Treasureton 138 kV line overloads to 107% of its
of Grace – Oneida – Treasureton 138 kV line
138 kV lines Treasureton 138 kV
line overloads to 120% of its
of Grace – Oneida –
Treasureton 138 kV line

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12.2 Appendix 2: Higher Priority Requests
All active higher priority Transmission Provider projects, and transmission service and/or
generator interconnection requests will be considered in this cluster area study and are identified below. If any of these requests are withdrawn, the Transmission Provider reserves the right to restudy this request, as the results and conclusions contained within this study could significantly change.
Transmission/Generation Interconnection Queue Requests considered: Q0255 (152 MW) TSR Q2611
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12.3 Appendix 3: Property Requirements
Property Requirements for Point of Interconnection Substation
Requirements for rights of way easements Rights of way easements will be acquired by the Interconnection Customer in the Transmission Provider’s name for the construction, reconstruction, operation, maintenance, repair, replacement and removal of Transmission Provider’s Interconnection Facilities that will be owned and operated by Transmission Provider. Interconnection Customer will acquire all necessary permits
for the Project and will obtain rights of way easements for the Project on Transmission Provider’s easement form. Real Property Requirements for Point of Interconnection Substation
Real property for a POI substation will be acquired by an Interconnection Customer to
accommodate the Interconnection Customer’s Project. The real property must be acceptable to Transmission Provider. Interconnection Customer will acquire fee ownership for interconnection substation unless Transmission Provider determines that other than fee ownership is acceptable; however, the form and instrument of such rights will be at Transmission Provider’s sole
discretion. Any land rights that Interconnection Customer is planning to retain as part of a fee
property conveyance will be identified in advance to Transmission Provider and are subject to the Transmission Provider’s approval. The Interconnection Customer must obtain all permits required by all relevant jurisdictions for
the planned use including but not limited to conditional use permits, Certificates of Public
Convenience and Necessity, California Environmental Quality Act, as well as all construction permits for the Project. If eligible, Interconnection Customer will not be reimbursed through network upgrades for more
than the market value of the property.
As a minimum, real property must be environmentally, physically, and operationally acceptable to Transmission Provider. The real property shall be a permitted or able to be permitted use in all zoning districts. The Interconnection Customer shall provide Transmission Provider with a title
report and shall transfer property without any material defects of title or other encumbrances that
are not acceptable to Transmission Provider. Property lines shall be surveyed and show all encumbrances, encroachments, and roads. Examples of potentially unacceptable environmental, physical, or operational conditions could
include but are not limited to:
1. Environmental: known contamination of site; evidence of environmental contamination by any dangerous, hazardous or toxic materials as defined by any governmental agency; violation of building, health, safety, environmental, fire,
land use, zoning or other such regulation; violation of ordinances or statutes of
any governmental entities having jurisdiction over the property; underground or above ground storage tanks in area; known remediation sites on property; ongoing mitigation activities or monitoring activities; asbestos; lead-based paint, etc. A
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phase I environmental study is required for land being acquired in fee by the Transmission Provider unless waived by Transmission Provider.
2. Physical: inadequate site drainage; proximity to flood zone; erosion issues; wetland overlays; threatened and endangered species; archeological or culturally sensitive areas; inadequate sub-surface elements, etc. Transmission Provider may require Interconnection Customer to procure various studies and surveys as
determined necessary by Transmission Provider. Operational: inadequate access for Transmission Provider’s equipment and vehicles; existing structures on land that require removal prior to building of substation; ongoing maintenance for
landscaping or extensive landscape requirements; ongoing homeowner's or other requirements or
restrictions (e.g., Covenants, Codes and Restrictions, deed restrictions, etc.) on property which are not acceptable to the Transmission Provider.

Generation Interconnection Transition Cluster
Transition Cluster Study Report

Cluster Area 9
October 22, 2021

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TABLE OF CONTENTS
1.0 SCOPE OF THE STUDY ................................................................................................................. 1 2.0 STUDY ASSUMPTIONS ................................................................................................................. 1 3.0 GENERATING FACILITY REQUIREMENTS .............................................................................. 3 3.1 Transmission Voltage Interconnection Requests .............................................................................. 3 3.2 Distribution Voltage Interconnection Requests ................................................................................ 6
4.0 CLUSTER AREA DEFINITIONS ................................................................................................... 6 5.0 CLUSTER AREA 9 .......................................................................................................................... 6 5.1 Description of Interconnection Request – TCS-28 ........................................................................... 7 5.2 Description of Interconnection Request – TCS-30 ........................................................................... 8 6.0 SITE SPECIFIC GENERATING FACILITY REQUIREMENTS ................................................. 10 6.1 Interconnection Request .................................................................................................................. 10 7.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS - ERIS .......................................... 10 7.1 Transmission System Requirements ............................................................................................... 10 7.2 Distribution System Requirements ................................................................................................. 11 7.3 Transmission Line Requirements .................................................................................................... 11 7.4 Existing Circuit Breaker Upgrades – Short Circuit ......................................................................... 11 7.5 Protection Requirements ................................................................................................................. 12 7.6 Data (RTU) Requirements .............................................................................................................. 13 7.7 Substation Requirements ................................................................................................................. 14 7.8 Communication Requirements ........................................................................................................ 14 7.9 Metering Requirements ................................................................................................................... 15 8.0 CONTINGENT FACILITIES (ERIS) ............................................................................................ 16 9.0 COST ESTIMATE (ERIS) ............................................................................................................. 16 9.1 Interconnection Facilities ................................................................................................................ 16 9.2 Station Equipment ........................................................................................................................... 17 9.3 Network Upgrades .......................................................................................................................... 17 9.4 Total Estimated Project Costs ......................................................................................................... 17 10.0 SCHEDULE (ERIS) ....................................................................................................................... 18 11.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS - NRIS .......................................... 18 12.0 AFFECTED SYSTEMS ................................................................................................................. 18 13.0 APPENDICES ................................................................................................................................ 18 13.1 Appendix 1: Cluster Area Power Flow and Stability Study Results ............................................... 19 13.2 Appendix 2: Higher Priority Requests ............................................................................................ 35 13.3 Appendix 3: Property Requirements ............................................................................................... 36
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1.0 SCOPE OF THE STUDY
This cluster restudy is being performed due to the withdrawal of several interconnection requests
that were included in the original cluster study. Cluster Area 9 (“CA9”) generally covers the geographic area of the Transmission Provider’s in the southern Oregon and northern California region and includes the following Interconnection Requests: TCS-28 and TCS-30
Consistent with Attachment W, Section 3.4.2 and Section 51.4 of PacifiCorp’s (“Transmission Provider”) Open Access Transmission Tariff (“OATT”), this interconnection Transition Cluster Study (“Cluster Study”) evaluated the impact of the proposed interconnections on the reliability
of the Transmission System. The Cluster Study considered the Base Case as well as all generating
facilities (and with respect to (iii) below, any identified Network Upgrades associated with such higher queued interconnection) that, on the date the Cluster Request Window closes: (i) are existing and directly interconnected to the Transmission System;
(ii) are existing and interconnected to Affected Systems and may have an impact on the
Interconnection Request; (iii) have a pending higher queued or higher clustered interconnection request to interconnect to the transmission system; and (iv) have executed an LGIA or requested that an unexecuted LGIA be filed with FERC.

The Cluster Study consisted of power flow, stability, and short circuit analyses. This Cluster Study report provides the following information:
• identification of any circuit breaker short circuit capability limits exceeded as a result of the
interconnection;
• identification of any thermal overload or voltage limit violations resulting from the interconnection;
• identification of any instability or inadequately damped response to system disturbances
resulting from the interconnection and
• description and non-binding, good faith estimated cost of facilities required to interconnect the Generating Facilities to the Transmission System and to address the identified short circuit, instability, and power flow issues.
2.0 STUDY ASSUMPTIONS
• All active higher priority transmission service and/or generator interconnection requests that were considered in this study are listed in Appendix 2. If any of these requests are withdrawn, the Transmission Provider reserves the right to restudy this request, and the
results and conclusions could significantly change.
• For study purposes there are two separate queues: o Transmission Service Queue: to the extent practical, all network upgrades that are required to accommodate active transmission service requests were modeled in this
study.
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o Generation Interconnection Queue: Interconnection Facilities and network upgrades associated with higher queued or higher clustered interconnection
requests were modeled in this study.
• The Interconnection Customers’ request for energy or network resource interconnection service in and of itself does not request or convey transmission service. Only a Network Customer may make a request to designate a generating resource as a Network Resource.
Because the queue of higher priority transmission service requests may be different when
a Network Customer requests network resource designation for this Generating Facility, the available capacity or transmission modifications, if any, necessary to provide Network Integration Transmission Service may be significantly different. Therefore, Interconnection Customers should regard the results of this study as informational rather
than final.
• Under normal conditions, the Transmission Provider does not dispatch or otherwise directly control or regulate the output of generating facilities. Therefore, the need for transmission modifications, if any, that may be required to provide Network Resource
Interconnection Service will be evaluated on the basis of 100 percent deliverability (i.e.,
this study did not model displacement of other resources in the same area).
• This study assumed the Projects will be integrated into the Transmission Provider’s system at agreed upon and/or proposed Points of Interconnection (“POI” or “POIs”).
• If Interconnection Customers proceed through the interconnection process, they will be required to construct and own any facilities required between the Point of Change of Ownership and the Project unless specifically identified by the Transmission Provider.
• Line reconductor or fiber underbuild required on existing poles were assumed to follow the
most direct path on the Transmission Provider’s system. If during detailed design the path must be modified it may result in additional cost and timing delays for the Interconnection Customer’s Project.
• Generator tripping may be required for certain outages.
• All facilities will meet or exceed the minimum Western Electricity Coordinating Council
(“WECC”), North American Electric Reliability Corporation (“NERC”), and the Transmission Provider’s performance and design standards.
• Solar generators are assumed to operate during daylight hours, 7 days per week, 12 months
per year.
• TCS-28 Interconnection Request: distribution system line extension is assumed to originate at the closest Transmission Provider pole to the POI shown on the Interconnection Customer’s site plan.
• TCS-28 Interconnection Requests: the Interconnection Customer will provide constant
power factor control at unity power factor (100% power factor).
• TCS-28 Interconnection Requests: daytime minimum load values were based on SCADA measurements. For the proposed interconnections to distribution system, the new
generation is expected to provide reverse flow to the circuit and in some cases the
substation transformer.
• TCS-30 Interconnection Request: the technical analysis performed in this study modeled the TCS-30 generating plant with a maximum nameplate generating capability of 10 MW and with 2.56 MW of total plant-side loads. However, the scope of the Cluster Study does
not address load service requirements associated with the Interconnection Customer’s site
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loads. A separate request needs to be submitted to the Transmission Provider through a separate load interconnection process.
• This report is based on information available at the time of the study. It is the
Interconnection Customer’s responsibility to check the Transmission Provider’s web site regularly for Transmission System updates at https://www.oasis.oati.com/ppw
3.0 GENERATING FACILITY REQUIREMENTS
The following requirements are applicable to all Interconnection Requests. The Transmission
Provider will identify any site-specific generating facility requirements in addition to the following in this report and in Facilities Studies. Certain Interconnection Requests requesting service at a voltage level traditionally defined as distribution may be subject to the transmission interconnection request requirements listed below should the Transmission Provider make that
determination.
3.1 Transmission Voltage Interconnection Requests
All interconnecting synchronous and non-synchronous generators are required to design their Generating Facilities with reactive power capabilities necessary to operate within the full power factor range of 0.95 leading to 0.95 lagging. This power factor range shall be dynamic and can be
met using a combination of the inherent dynamic reactive power capability of the generator or
inverter, dynamic reactive power devices and static reactive power devices to make up for losses. For synchronous generators, the power factor requirement is to be measured at the POI. For non-synchronous generators, the power factor requirement is to be measured at the high-side of the
generator substation.
The Generating Facility must provide dynamic reactive power to the system in support of both voltage scheduling and contingency events that require transient voltage support, and must be able to provide reactive capability over the full range of real power output.

If the Generating Facility is not capable of providing positive reactive support (i.e., supplying reactive power to the system) immediately following the removal of a fault or other transient low voltage perturbations, the facility must be required to add dynamic voltage support equipment. These additional dynamic reactive devices shall have correct protection settings such that the
devices will remain on line and active during and immediately following a fault event.
Generators shall be equipped with automatic voltage-control equipment and normally operated with the voltage regulation control mode enabled unless written authorization (or directive) from the Transmission Provider is given to operate in another control mode (e.g. constant power factor
control). The control mode of generating units shall be accurately represented in operating studies.
The generators shall be capable of operating continuously at their maximum power output at its rated field current within +/- 5% of its rated terminal voltage. All generators are required to ensure the primary frequency capability of their Facility by
installing, maintaining, and operating a functioning governor or equivalent controls as indicated
in FERC Order 842.
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As required by NERC standard VAR-001-4.2, the Transmission Provider will provide a voltage schedule for the POI. In general, Generating Facilities should be operated so as to maintain the
voltage at the POI, typically between 1.00 per unit to 1.04 per unit, or other designated point as deemed appropriated by Transmission Provider. The Transmission Provider may also specify a voltage and/or reactive power bandwidth as needed to coordinate with upstream voltage control devices such as on-load tap changers. At the Transmission Provider’s discretion, these values might be adjusted depending on operating conditions.
Generating Facilities capable of operating with a voltage droop are required to do so. Voltage droop control enables proportionate reactive power sharing among Generation Facilities. Studies will be required to coordinate voltage droop settings if there are other facilities in the area. It will
be the Interconnection Customer’s responsibility to ensure that a voltage coordination study is
performed, in coordination with Transmission Provider, and implemented with appropriate coordination settings prior to unit testing. For areas with multiple Generating Facilities additional studies may be required to determine
whether or not critical interactions, including but not limited to control systems, exist. These
studies, to be coordinated with Transmission Provider, will be the responsibility of the Interconnection Customer. If the need for a master controller is identified, the cost and all related installation requirements will be the responsibility of the Interconnection Customer. Participation by the generation facility in subsequent interaction/coordination studies will be required pre- and
post-commercial operation in order ensure system reliability.
Interconnection Requests that are 75 MVA or larger may be required to facilitate collection and validation of accurate modeling data to meet NERC modeling standards. The Transmission
Provider, in its roles as the Planning Coordinator, requires Phasor Measurement Units (PMUs) at
all new Generating Facilities with an individual or aggregate nameplate capacity of 75 MVA or greater. In addition to owning and maintaining the PMU, the Generating Facility will be responsible for collecting, storing (for a minimum of 90 days) and retrieving data as requested by the Planning Coordinator. Data must be stored for a minimum of 90 days. Data must be collected
and be able to stream to Planning Coordinator for each of the Generating Facility’s step-up
transformers measured on the low side of the GSU at a sample rate of at least 60 samples per second and synchronized within +/- 2 milliseconds of the Coordinated Universal Time (UTC). Initially, the following data must be collected:
• Three phase voltage and voltage angle (analog)
• Three phase current (analog) Data requirements are subject to change as deemed necessary to comply with local and federal regulations.

All generators must meet the Federal Energy Regulatory Commission (FERC), North American Electric Reliability Corporation (NERC) and WECC low voltage ride-through requirements as specified in the interconnection agreement. Inverters must be designed to stay connected to the grid in the case of severe faults and may not momentarily cease output within the no-trip area of
the voltage curves. Figure 1 illustrates the voltage ride-through capability as per NERC PRC-
024. Importantly, inverters should be designed such that a trip outside of the curves is a “may-trip” area (if needed to protect equipment) not a “must-trip” area. Inverters that momentarily cease
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active power output for these voltage excursions should be configured to restore output to pre-disturbance levels in no greater than five seconds, provided the inverter is capable of these changes.
Generators must provide test results to the Transmission Provider verifying that the inverters for
this Project have been programmed to meet all PRC-024 requirements rather than manufacturer IEEE distribution standards.
Figure 1 – Voltage Ride-Through Curve
As the Transmission Provider cannot submit a user written model to WECC for inclusion in base cases, a standard model from the WECC Approved Dynamic Model Library is required 180 days prior to trial operation. The list of approved generator models is continually updated and is
available on the http://www.WECC.biz website.
Interconnection Customer with an Interconnection Request for a Generating Facility that is both 75 MVA or larger as well as being interconnected at a voltage higher than 100 kV shall register with NERC as the Generator Owner (“GO”) and Generator Operator (“GOP”) for the Large
Generating Facility and provide the Transmission Provider documentation demonstrating
registration in order to be approved for Commercial Operation. This registration must be maintained throughout the lifetime of the Interconnection Agreement. Interconnection Customers are responsible for the protection of transmission lines between the
Generating Facility and the POI substation. For Interconnection Requests that are smaller than 75
MVA or are interconnected at a voltage less than 100 kV which have a tie line that is longer than 1,000 feet the Interconnection Customer shall construct and own a tie-line substation to be located at the change of ownership (separate fenced facility adjacent to the Transmission Provider’s POI substation). The tie line substation shall include an Interconnection Customer owned protective
device and associated transmission line relaying/communications. The ground grids of the
Transmission Provider’s POI substation and the Interconnection Customer’s tie-line substation will be connected to support the use of a bus differential protection scheme which will protect the overhead bus connection between the two facilities.
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3.2 Distribution Voltage Interconnection Requests
The Generating Facility and interconnection equipment owned by the Interconnection Customers
are required to operate under constant power factor mode with a unity power factor setting unless specifically requested otherwise by the Transmission Provider. The Generating Facilities are expressly forbidden from actively participating in voltage regulation of the Transmission Provider’s system without written request or authorization from the Transmission Provider. The Generating Facilities shall have sufficient reactive capacity to enable the delivery of 100 percent
of the plant output to the applicable POI at unity power factor measured at 1.0 per unit voltage under steady state conditions. Generators shall be capable of operating under Voltage-reactive power mode, Active power-
reactive power mode, and Constant reactive power mode as per IEEE Std. 1547-2018. This project
shall be capable of activating each of these modes one at a time. The Transmission Provider reserves the right to specify any mode and settings within the limits of IEEE Std 1547-2018 needed before or after the Generation Facility enters service. The Interconnection Customer shall be responsible for implementing settings modifications and mode selections as requested by the
Transmission Provider within an acceptable timeframe. The reactive compensation must be
designed such that the discreet switching of the reactive device (if required by the Interconnection Customer) does not cause step voltage changes greater than +/-3% on the Transmission Provider’s system. In all cases the minimum power quality requirements in PacifiCorp’s Engineering Handbook section 1C shall be met and are available at https://www.pacificpower.net/about/power-
quality-standards.html. Requirements specified in the System Impact Study that exceed
requirements in the Engineering Handbook section 1C power quality standards shall apply. All generators must meet applicable WECC low voltage ride-through requirements as specified in the interconnection agreement.

As per NERC standard VAR-001-1, the Transmission Provider is required to specify voltage or reactive power schedule at the POI. Under normal conditions, the Transmission Provider’s system should not supply reactive power to the Generating Facility.
4.0 CLUSTER AREA DEFINITIONS
The Transmission Provider performed the Transition Cluster Study based on geographically and/or
electrically relevant areas on the Transmission Provider’s Transmission System known as Cluster Areas. The Transmission Provider has determined that the Interconnection Requests discussed in Section 5.0 are located in a geographically and/or electrically relevant area on Transmission Provider’s Transmission System, and thus, were assigned Cluster Area 9 in the Transition Cluster
Study process.
5.0 CLUSTER AREA 9
Cluster Area 9 (“CA9”) generally covers the geographic area of the Transmission Provider’s in the southern Oregon and northern California region including Grants Pass, Medford, Klamath Falls and Lakeview, Oregon as well as Alturas, Crescent City and Yreka, California. This Cluster
Area consists of two sub-clusters. The first, referred to as CA9A, consists of one Interconnection
Request proposed on the distribution network located in Jackson County, Oregon. The second,
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referred to as CA9B, consists of one Interconnection Request proposed on the transmission system in Klamath County, Oregon.
5.1 Description of Interconnection Request – TCS-28
The Interconnection Customer has proposed to interconnect 2.99 MW of new generation to the Transmission Provider’s distribution circuit 5R110 out of Vilas Road substation located in Jackson County, Oregon. The Interconnection Request is proposed to consist of twenty-four (24) 600 KVA Chint CSP SCA125KTL-DO/US-600-UL solar inverters for a total output of 2.99 MW
at the POI. The requested commercial operation date is July 15, 2021. Figure 2 below, is a one-line diagram that illustrates the interconnection of the proposed Generating Facility to the Transmission Provider’s system.
Interconnection Customer will operate this generator as a Qualified Facility as defined by the
Transmission Provider Regulatory Policies Act of 1978 (PURPA). The Interconnection Request will be studied for Network Resource Interconnection Service (“NRIS”).

The Transmission Provider has assigned the Project Cluster Number “TCS-28” and is part of CA9A.
M
Change of Ownership
Vilas RoadSubstation
Optical Fiber Cable
Point of Interconnection
1.5 Miles
Lone Pine
Q0578
3 MWDC/AC
3.3 MVA 12.47 kV – 600 VZ=5.75%
1000 KVAZ=7%
R
Figure 2: Simplified System One Line Diagram

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5.2 Description of Interconnection Request – TCS-30
The Interconnection Customer has proposed to interconnect 10 MW of new generation to the
Transmission Provider’s Klamath Falls-Fishhole 69 kV transmission line (Line 9) located in Klamath County, Oregon. The proposed POI is between structures 7/12 and 8/12 on the Lakeview Junction-Dairy section of Line 9. The proposed POI is located approximately 5.48 miles from Transmission Provider’s Dairy substation and 3.90 miles from Lakeview Junction. The Interconnection Request is proposed to consist of a 12,000 KVA Exergy GEX 1000 organic
rankine cycle expander generator for a total output of 10 MW at the POI. The Interconnection Customer’s facility is specified with customer site loads totaling 2,560 kW, including in-plant loads of 1,560 kW and wellfield loads of 1,000 kW. The requested commercial operation date is July 1, 2021. Figure 5 below, is a one-line diagram that illustrates the interconnection of the
proposed Generating Facility to the Transmission Provider’s system.
Interconnection Customer will operate this generator as a Qualified Facility as defined by the Transmission Provider Regulatory Policies Act of 1978 (PURPA).
The Interconnection Request will be studied for Network Resource Interconnection Service
(“NRIS”). The Transmission Provider has assigned the Project Cluster Number “TCS-30” and is part of CA9B.

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Change of ownership
13.2 kV
12.5 MVA
69kV
Point of Interconnection
TCS-30 POISUB
M
DAIRY SUB
TO FISHHOLESUBNO
NO
TO MALINSUB
KLAMATH FALLSSUB
3L9
3L8
3L6
NO
NO
NO
BRYANTSUB
TEXUMSUB
ROSS AVESUBLAKEPORTSUB
WESTSIDESUB
HENLEYSUB
MERRILLSUB
HORNETSUB
TO BONAZA & CASEBEERSUB
New Proposed Facilities
Loads
TCS-30 SUB
3.86 miles 5.52 miles
M
Figure 3: Simplified System One Line Diagram

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6.0 SITE SPECIFIC GENERATING FACILITY REQUIREMENTS
In addition to the requirements described above the following Generating Facility requirements
apply for the specific Interconnection Requests listed below.
6.1 Interconnection Request
TCS-28 The Interconnection Customer will be required to install a transformer that will hold the phase to neutral voltages within limits when the Generating Facility is isolated with the Transmission
Provider’s local system until the generation disconnects. The proposed grounded-wye/ungrounded-wye step-up transformer will not accomplish the stabilization of the phase to neutral voltages on the 12 kV system. The circuit that the Project is connecting to is a four wire multi-grounded circuit with line to neutral connected load. Figure 2 shows the addition of a wye
– delta grounding transformer of adequate power size and impedance that will meet the
requirement.
7.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS - ERIS
7.1 Transmission System Requirements
TCS-30
The following transmission system improvements are required to accommodate the TCS-30
Interconnection Request in this Cluster Area: A new 69 kV substation will need to be constructed to serve as the POI. Transmission line switching devices on the 69 kV Line 9 toward Lakeview Junction and Dairy substation require a
combination of loop opening and line dropping capability or circuit breakers with SCADA
control. The 69 kV circuit breaker at the TCS-30 POI substation toward the generating plant requires SCADA control to allow disconnecting the Interconnection Customer’s generating facility from the Transmission Provider’s system during certain system conditions when generation from TCS-30 could not be accepted.

Protective relaying systems may need to be modified or installed to accommodate increased reverse power flow on the following transmission facilities:
• 69 kV Line 9 (K5) at Klamath Falls circuit breaker 3L9
• 69 kV Line 56 (K7) at Klamath Falls circuit breaker 3L6
• Klamath Falls substation 230-69 kV transformers Generation could not be accepted from TCS-30 when the Transmission Provider’s system is operated in contingency transmission configurations no. 2 and 3 (fully defined in Appendix 1)
due to limitations on the existing system until a planned reinforcement project is in service. Interim operating procedures will be developed to curtail the generating facility when the transmission system is in one of the abnormal configurations. These contingency transmission configurations will be replaced with the future transmission configuration no. 4, as described in Appendix 1, following completion of a planned capital project on the Transmission Provider’s
system to construct a new 69 kV transmission line between Malin substation and Bonanza substation. The future 69 kV transmission line will provide a new contingency source to several substations in the area including the proposed TCS-30 POI, eliminating the use of contingency
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configurations no. 1, 2 and 3 for an outage of the Klamath Falls-Hornet, Hornet-Lakeview Junction and Lakeview Junction-Dairy sections of 69 kV Line 9.
Refer to Appendix 1 for more details regarding these requirements.
7.2 Distribution System Requirements
TCS-28 The load flow model was modified from its present state to its future state by extending 12.47 kV
circuitry from the existing facility point 01336001.0330341 to the new POI. This line extension will require a minimum of two new utility poles. A three-phase gang-operated, load break disconnect switch is required on the first pole. A primary metering assembly is required on the second pole. Note that the Interconnection Customer’s one-line diagram shows a utility owned
recloser; instead, the Transmission Provider requires an Interconnection Customer owned
recloser on the customer side of the POI. This recloser will replace what the one-line diagram shows as “FUSED CUTOUT.” The load flow model identified that the substation Load Tap Changer requires a decrease in
voltage from the present setting of 123 base volts with no compensation to 122 base volts with
no compensation. The daytime minimum load condition at full generation showed excessive overvoltage on the Vilas Road 5R110 circuit; the Load Tap Changer setting change is required to provide tolerable voltage.
Reverse power flow of -10.92 MW is projected at the Vilas Road 5R110 circuit breaker during
the daytime minimum load with full generation condition. Reverse power flow of -5.30 MW is projected on the Vilas Road substation transformer T-3877 during the daytime minimum load and full generation condition. The calculated voltage fluctuation from full generation to no generation in the daytime minimum load case was 1.7%.
7.3 Transmission Line Requirements
TCS-30 A new tap from the Klamath Falls-Fishhole 69 kV transmission line has been identified as a requirement for this connection. This will require the installation of a new tap structure in the existing line along with one existing structure in each direction being replaced with a
transmission line switch structure.
7.4 Existing Circuit Breaker Upgrades – Short Circuit
TCS-28 The increase in the fault duty on the system as the result of the addition of the Generating Facility with photovoltaic arrays, inverters and transformers as specified in the Interconnection
Customer’s application as shown in Figure 2, assuming transformers with 5.75% impedance will
not push the fault duty above the interrupting rating of any of the existing fault interrupting equipment. TCS-30
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The increase in the fault duty on the system as a result of the addition of the generation facility fed through a 8 MVA step-up transformer with 7% impedance will not push the fault duty above
the interrupting rate of any of the existing fault interrupting equipment.

7.5 Protection Requirements
TCS-28 Protective relaying systems will need to be installed that will detect faults and cause the disconnection of the generation facility for 12.5 kV line faults on circuit 5R110 out of Vilas Road substation. Circuit 5R110 is lightly loaded during the majority of the year. The reaction of the generation facility after being isolated with the load will not cause a timely disconnection of
the generation for power system faults. Faults on the 12.5 kV circuit must result in the disconnection of the generation facility in a timely manner. The circuit can be quickly restored to service after the fault is cleared. Most faults on overhead lines are temporary in nature so that after all the sources of energy to the fault have been disconnected the circuit can be reenergized and the service to the loads restored. A transfer trip system will be needed between Vilas Road
substation and the solar facility. When a fault is detected at Vilas Road substation on circuit 5R110, a trip signal will be sent to the solar facility to cause the 12.5 kV breaker or recloser to open. Fiber optic cable was installed on a portion of circuit 5R110 as part of a previous interconnection
project. That fiber will be tapped and extended to the TCS-28 facility to provide the communication circuit for the transfer trip. At the solar site the Interconnection Customer will need to install an SEL 351R/651R protective relay to perform the following functions:
• Receive transfer trip from Vilas Road substation
• Detect faults on the 12.5 kV at the generation facility
• Detect faults on the 12.5 kV line to Vilas Road substation
• Monitor the voltage and react to under or over frequency, and / or magnitude of the
voltage TCS-30 Figure 3 illustrates the interconnection of the proposed generation facility to the 69 kV line out of
Klamath Falls substation. The normal operating configuration for the interconnection will be to
over the 69 kV line out of Klamath Falls substation through breaker 3L9. Two possible alternate feeds include Klamath Falls substation through breaker 3L6 and from Malin substation. The generation facility needs to disconnect from the 69 kV system any time breaker 3L9 opens at Klamath Falls substation or for the alternate feeds any time breaker 3L6 at Klamath Falls
substation or 3L179 at Malin substation opens. During some periods of time the potential power
output from this generation facility will be greater than the connected load on the 69 kV line. When this occurs, the load/generation unbalance cannot be relied upon to cause the generators to disconnect.
Protective relays will need to be installed at the Transmission Provider’s POI substation to detect
faults on the 69 kV system. When a fault occurs on the 69 kV system, the generator will need to be disconnected in less than 10 cycles so that the 69 kV breakers at Klamath Falls substation can
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automatically reclose to reenergize the line. Most faults are not permanent. The fast interruption of the fault and the re-energization of the system will restore service to the connected load. The
relay package will be installed at the Transmission Provider’s POI substation will receive a transfer trip signal from Klamath Falls substation. The relay package at the Transmission Provider’s POI substation will detect line faults independent of the transfer trip if the signal fails to reach the Transmission Provider’s POI substation relays but will function after a time delay. This delayed clearing will delay the restoration of the load and will not be acceptable for normal operation. The
relays will be set to be time coordinated with the other relays on the lines out of Klamath Falls substation. The controls for both breaker 3L6 and 3L9 will be configured to send the transfer trip. A control switch will be used to enable the correct controls based on the configuration of the transmission system. For the occasional operation of the transmission system with the primary
source being from Malin substation via Line 78 and 5, an alternate relay setting group will be
enabled in the line relay at the POI substation to provide the line protection for this configuration. The protective relaying systems for the 69/12.5 kV transformer will be the responsibility of the Interconnection Customer. The protection for the transformer needs to detect faults in the
transformer in two cycles or less. The POI substation and the Interconnection Customer’s
generation facility substation will be adjacent to each other and located on a common ground mat. Bus differential protection shall be provided for the short tie between the POI and the Interconnection Customer’s substation. The Interconnection Customer will need to supply a set of 2000A C800 CTs for connection to the differential circuit. The bus lockout relay will trip the
Interconnection Customer’s 69 kV breaker as well as the Transmission Provider’s breaker.
In addition to the line protective relaying, a relay used for under/over voltage and over/under frequency protection of the system will be installed at the Transmission Provider’s POI substation. If the voltage, magnitude or frequency, is outside of the normal operation range this relay will trip
open the tie breaker
. At Klamath Falls substation a dead line checking exists on this control circuit to block the automatic reclosing from closing the breaker if due to a failure of the protective systems leads to delayed tripping of the 69 kV breaker at the generation facility for a transmission line fault. A
similar dead line checking control circuit also exists on breaker 3L6 to accommodate the alternate
transmission feed. This type of control circuitry already exists on 3L179 at Malin substation.
7.6 Data (RTU) Requirements
TCS-30 The Transmission Provider will install an RTU in the new POI substation to collect all required
data points. The Interconnection Customer will hardwire all source devices from its collector
substation to a marshalling cabinet to be installed on the POI substation fence. The following points will be required: From the Customer collector station:
Analogs (Meter Data):
 13.2 kV A phase voltage
 13.2 kV B phase voltage
 13.2 kV C phase voltage
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 Real power MW (generator)
 Reactive power MVAR (generator)
 Energy Register KWH
 Energy Register KVARH Analogs:
 Unit GEN Setpoint MW (send/receive) Status:
 69 kV customer breaker
 13.2 kV customer breaker (transformer)
 13.2 kV customer breaker (generator)
From the POI: Analogs (Meter Data):
 69 kV A phase voltage
 69 kV B phase voltage
 69 kV C phase voltage
 Real power MW
 Reactive power MVAR
 Energy Register KWH
 Energy Register KVARH
7.7 Substation Requirements
TCS-30 A new 69 kV, single breaker substation will be built to serve as the POI. The substation will include a 69 kV breaker, two (2) 69kV group operated switches, three CT/VT metering units along with its support structures and a substation control house for housing the protective relay
and communication equipment. A ground grid and conduit system will be installed. The Interconnection Customer’s collector substation will be constructed adjacent to the POI substation and will share a ground grid. The Interconnection Customer shall provide a CDEGS grounding analysis of the collector substation location.
7.8 Communication Requirements
TCS-28 Existing ADSS fiber on the distribution line out of Vilas Road substation will be spliced and extended approximately 1.5 miles to the Interconnection Customer’s generating facility site. The fiber will be terminated in a patch panel in an enclosure to be installed at the generating facility site. Communications equipment will be installed in the enclosure to collect meter data from the
site. TCS-30 If FAA approval can be obtained, a 6 GHz Aviat Eclipse microwave link will be installed between the POI substation and the Transmission Provider’s Hamaker Mountain
communications site. A self-supporting tower will be installed at the POI substation, along with an antenna, waveguide, Aviat Eclipse radio, Loop AM3440-A channel bank, and support systems.
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If FAA approval can’t be obtained, fiber will be installed on the transmission line between the POI substation and the Transmission Provider’s Dairy substation. There, the fiber will be
terminated in a fiber optic transceiver, and circuits from the substations cross-connected to the existing microwave system at Dairy and on to Klamath substation and control centers.
7.9 Metering Requirements
TCS-28 Interchange Metering
The metering will be located on the high side of the customer generator step up transformer at the POI. The metering transformers will be installed overhead on a pole per distribution DM construction standards. The meter itself will be installed at the base of the pole. The Transmission Provider will procure, install, test, and own all revenue metering equipment. The
metering will be bi-directional to measure KWH and KVARH quantities for both generation
received and back feed retail load delivered. There will be no additional station service metering for supplying generation load. The metering generation and billing data will be remotely interrogated via the Transmission Provider’s MV90 data acquisition system.
Station Service/Construction Power
The Interconnection Customer must arrange distribution voltage retail meter service for electricity consumed by the Project when not generating. Temporary construction power metering shall conform to the Six State Electric Service Requirements manual. Interconnection Customer must call the PCCC Solution Center 1-800-640-2212 to arrange this service. Approval
for back feed is contingent upon obtaining station service.
TCS-30 Interchange Metering The overall Project metering will be located at the POI and rated for the total net generation of
the Project. The Transmission Provider will specify and order all interconnection revenue
metering, including the instrument transformers, meters, meter panel, junction box, and secondary metering wire. The primary metering transformers will be combination 69kV CT/VT units with extended range CTs for high-accuracy metering.
The metering design package will include two revenue quality meters with DNP real time digital
data terminated at a metering interposition block. One meter will be designated as primary SCADA meter with DNP data delivered to the primary control center. A second meter will be designated as backup SCADA meter with DNP data delivered to the alternate control center. The metering data will include bidirectional KWH and KVARH revenue quantities. The meter data
will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps
data. An Ethernet connection is required for retail sales and generation accounting via the MV-90 translation system.

Generator Metering The generation metering will be located in the Interconnection Customer’s facility and rated per the generator capacity. The Transmission Provider will specify and order all interconnection
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revenue metering, including the instrument transformers, meters, meter panel/enclosure, junction box, and secondary metering wire. The primary metering transformers will be discrete 13.2kV
CTs and VTs rated for high-accuracy metering. It is assumed that the Interconnection Customer will provide an enclosure for the CTs and VTs which is compliant with the Transmission Provider’s Electric Service Requirements.
The metering design package will include two revenue quality meters with DNP real time digital data terminated at a metering interposition block. One meter will be designated as primary SCADA meter with DNP data delivered to the primary control center. A second meter will be designated as backup SCADA meter with DNP data delivered to the alternate control center. The
metering data will include bidirectional KWH and KVARH revenue quantities. The meter data
will also include instantaneous PF, MW, MVAR, MVA, per-phase voltage, and per-phase amps data. An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.
Station Service/Construction Power The Project is within the Transmission Provider’s service territory. Please note that prior to back feed, Interconnection Customer must arrange transmission retail meter service for electricity
consumed by the Project that will be drawn from the transmission system when the Project is not
generating. Interconnection Customer must call the Help Desk at 1-800‐625‐6078 to arrange this service. Approval for back feed is contingent upon obtaining station service.
8.0 CONTINGENT FACILITIES (ERIS)
The following Interconnection Facilities and/or upgrades to the Transmission Provider’s system
are Contingent Facilities applicable to this Cluster Area.
None
9.0 COST ESTIMATE (ERIS)
The following facilities are directly assigned to Interconnection Customer(s) using such facilities.
If multiple Interconnection Requests are utilizing the same Transmission Provider Interconnection
Facilities the costs shall be shared pursuant to Section 39.2.3 of Transmission Provider’s OATT.
9.1 Interconnection Facilities
The following a directly assigned to Interconnection Customer(s) using such facilities. If multiple Interconnection Requests are utilizing the same Transmission Provider Interconnection
Facilities the costs shall be split equally between those requests. TCS-28 TCS-28 Collector Substation $59,000 Metering, relay settings
Distribution $49,000
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Line extension
Communications $167,000
Install 1.5 miles of fiber and communications equipment Total: $275,000 TCS-30 POI substation $600,000
Line termination and metering TCS-30 Generation Site $90,000 Metering

Total: $690,000
9.2 Station Equipment
The following are Network Upgrades which are allocated based on the number of Generating Facilities interconnecting at an individual station on a per Interconnection Request basis.
Interconnection Requests utilizing the same Interconnection Facilities shall be consider one
request for this allocation. TCS-30 POI substation $1,500,000
Construct new single breaker 72.5kV substation
9.3 Network Upgrades
The funding responsibility for Network Upgrades other than those identified in the previous section shall be allocated based on the proportional capacity of each individual Generating Facility.
Klamath Falls-Fishhole Transmission Line $390,000
Loop in/out of POI substation Hamaker Mountain Communication Site $60,000
Communication upgrades
Klamath Falls substation $20,000 Relay upgrades
9.4 Total Estimated Project Costs
TCS-28 Interconnection Facilities $275,000 Station Equipment N/A Network Upgrades N/A
Total: $275,000
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TCS-30 Interconnection Facilities $690,000
Station Equipment $1,500,000 Network Upgrades $470,000 Total: $2,660,000
10.0 SCHEDULE (ERIS)
The Transmission Provider estimates it will require approximately 60 months to design, procure
and construct the facilities described in the ERIS sections of this report following the execution of Interconnection Agreements. The schedule will be further developed and optimized during the Facilities Studies.
11.0 TRANSMISSION PROVIDER SYSTEM REQUIREMENTS - NRIS
There are no additional requirements for those Interconnection Requests that have requested
NRIS above those identified as required for ERIS.
12.0 AFFECTED SYSTEMS
Transmission Provider has identified the following affected systems: None
A copy of this report will be shared with each Affected System.
13.0 APPENDICES
Appendix 1: Cluster Area Power Flow and Stability Study Results Appendix 2: Higher Priority Requests Appendix 3: Property Requirements
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13.1 Appendix 1: Cluster Area Power Flow and Stability Study Results
Distribution
TCS-28 Interconnection Request: six cases were assembled and studied at the distribution voltage level.
• Daytime minimum load, no generation.
• Daytime minimum load, full generation.
• Summer peak, no generation.
• Summer peak, full generation.
• Winter peak, no generation.
• Winter peak, full generation. The Interconnection Customer’s Generating Facility must be operated in a manner so as not to cause objectionable power quality issues to other Distribution Provider customers. Voltage
fluctuations caused by the generation facility are required to meet the Distribution Provider’s Engineering Handbook, Voltage Fluctuation and Flicker, Standard 1C.5.1 which is found at https://www.pacificpower.net/about/power-quality-standards.html. Table 1 of Standard 1C.5.1 indicates that for this Project the medium voltage planning levels for voltage fluctuation under
any condition is a Pst < 0.9 and a Plt < 0.7. It is the Interconnection Customer’s responsibility to
design and construct a system capable of meeting these levels. Specific system information will be provided on request to the Interconnection Customer for design purposes. During operation if measured voltage fluctuation levels exceed the limits specified in Standard 1C.5.1 the Interconnection Customer is required to cease generation until the condition is mitigated. The
requirement for the Interconnection Customer’s system to meet Standard 1C.5.1 will be
incorporated in the interconnection contract. The Distribution Provider may, at its’ discretion, disconnect the Interconnection Customer’s Generating Facility until mitigations to meet these standards are made. The Interconnection Customer must also comply with all of the Distribution Provider’s Engineering Handbook standards addressing power quality, including but not limited
to Voltage Level, Voltage Balance, Harmonic Distortion, and Voltage Frequency.
For calculation of the forecasted voltage fluctuation, it was assumed that the power flow from the Interconnection Customer would change from full generation to no generation during a one-minute interval.

For some new interconnection sites, substation voltage regulation setting changes are required to mitigate projected overvoltage during the daytime minimum load and full generation condition.
Transmission
Steady state voltage is defined as the voltage after all voltage regulating devices, both electronic and mechanical, have reached a quiescent state for the power flow and voltage conditions at a specific time.
Post transient voltage is defined as the voltage measured after high speed switching transients
and the effects of generator exciter controls have settled out and before any mechanically operated load tap changing and voltage regulating devices have started to adjust to new system conditions.
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Post transient voltage deviation is defined as the difference between the voltage before an event
and the post transient voltage after the event. Transmission Provider’s Engineering Handbook, Voltage Fluctuation and Flicker, Standard 1C.5.1 limits post transient voltage deviation on distribution buses to a maximum of 6.0% for infrequent switching events such as the separation of a Generating Facility from the Transmission Provider’s system. In addition, the Western Electricity Coordinating Council (WECC) limits the post transient voltage deviation on
transmission buses to a maximum of 8.0% for single outage events including trip of a Generating Facility or generation tie line, disconnecting the generation from the transmission system. Any post transient voltage deviation occurring on the transmission system is imposed directly on customers in the region.

Reactive margin is a volt-ampere measure of power system voltage stability that may be reduced in magnitude by the connection of load or generation operating at constant power factor. Higher magnitude negative reactive margin indicates greater voltage stability. Zero magnitude and positive magnitude reactive margin indicate impending voltage collapse. The measurement of
reactive margin is made in a power flow simulation model.
Contingency transmission configuration for the Transmission Provider’s system is defined as any configuration other than normal transmission configuration. Eight initial base cases were developed for the Cluster Area 9 study, covering 2025 heavy summer (HS), 2025-26 heavy winter (HW) and 2025 daytime minimum load (DML) conditions in the Southern Oregon and Northern California region prior to and with the addition of the five Interconnection Requests. Transmission path flows for WECC Path 25 (PacifiCorp/PG&E 115 kV
Interconnection) were set the north-to-south transfer limit of 80 MW, while transfers on WECC
Path 76 (Reno-Alturas 345 kV line) were set to the north-to-south transfer limit of 300 MW. The daytime minimum load base cases were also stressed with the Path 76 transfers set to the south-to-north transfer limit of 300 MW.
Case Cluster Area 9 Flow (MW) and Flow (MW) and
1 2025 DML Out of service 80 N-S 300 N-S
2 2025 DML Out of service 80 N-S -300 S-N
3 2025 HS Out of service 80 N-S 300 N-S
4 2025 HW Out of service 80 N-S 300 N-S
5 2025 DML In service 80 N-S 300 N-S
6 2025 DML In service 80 N-S -300 S-N
7 2025 HS In service 80 N-S 300 N-S
8 2025 HW In service 80 N-S 300 N-S
Table 1: Cluster Area 9 Main Base Cases

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Power flow analysis was performed on all base cases for system normal conditions and category P1, P2, P4, P5 and P7 contingency events on the Transmission Provider’s Bulk Electric System
(BES) in Southern Oregon and Northern California region to evaluate impacts of the Cluster Area 9 Interconnection Requests on the transmission system. The analysis did not identify any planning events for which the system does not meet the performance criteria of the NERC TPL-001-4 Reliability Standard with the addition of two Interconnection Requests in Cluster Area 9.

Additional base cases were developed that focused on the local area system near each POI to evaluate different transmission system configurations and system conditions applicable to each POI. These base cases were studied as part of the detailed analysis described in the following sections.

TCS-28 Study Results The following 12 base cases were developed and studied in power flow simulation at the transmission level to evaluate different transmission system configurations and load levels prior to and with the TCS-28 Interconnection Request.
Case Transmission System Cluster Area 9 Interconnection
1 2025 DML Normal Out of service
2 2025 DML Normal In service
3 2025 DML Contingency 1 In service
4 2025 DML Contingency 2 In service
5 2025 HS Normal Out of service
6 2025 HS Normal In service
7 2025 HS Contingency 1 In service
8 2025 HS Contingency 2 In service
9 2025 HS Normal Out of service
10 2025-26 HW Normal In service
11 2025-26 HW Contingency 1 In service
12 2025-26 HW Contingency 2 In service
Table 2 – TCS-28 Additional Study Base Cases The study evaluated three transmission system configurations:
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• Normal transmission configuration: Vilas Road substation supplied by looped 115 kV
transmission system served from Lone Pine 230-115 kV substation and Whetstone 230-
115 kV substation via Line 40.
• Contingency transmission configuration 1: Lone Pine-Vilas Road segment of 115 kV Line 40 is out of service. Vilas Road substation supplied from Whetstone 230-115 kV source
via Line 40.
• Contingency transmission configuration 2: Whetstone-White City segment of 115 kV Line 40 is out of service. Vilas Road substation supplied from Lone Pine 230-115 kV source via Line 40.

The results of the transmission study show that the proposed TCS-28 Interconnection Request does not result in negative impacts to the Transmission Provider’s transmission system. Power flow simulation indicates that steady state and post transient voltages are projected to remain within acceptable limits and loading on transmission facilities is projected to remain within facility
ratings. TCS-30 Study Results The following 30 base cases were developed and studied in power flow simulation to evaluate different transmission system configurations and load levels prior to and with the TCS-30
Interconnection Request.

Case Year / Transmission System Cluster Area 9 Interconnection
1 2025 DML Normal Out of service
2 2025 DML Normal In service
3 2025 DML Contingency 1 Out of service
4 2025 DML Contingency 1 In service
5 2025 DML Contingency 2 Out of service
6 2025 DML Contingency 2 In service
7 2025 DML Contingency 3 Out of service
8 2025 DML Contingency 3 In service
9 2025 DML Contingency 4 Out of service
10 2025 DML Contingency 4 In service
11 2025 HS Normal Out of service
12 2025 HS Normal In service
13 2025 HS Contingency 1 Out of service
14 2025 HS Contingency 1 In service
15 2025 HS Contingency 2 Out of service
16 2025 HS Contingency 2 In service
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17 2025 HS Contingency 3 Out of service
18 2025 HS Contingency 3 In service
19 2025 HS Contingency 4 Out of service
20 2025 HS Contingency 4 In service
21 2025-26 HW Normal Out of service
22 2025-26 HW Normal In service
23 2025-26 HW Contingency 1 Out of service
24 2025-26 HW Contingency 1 In service
25 2025-26 HW Contingency 2 Out of service
26 2025-26 HW Contingency 2 In service
27 2025-26 HW Contingency 3 Out of service
28 2025-26 HW Contingency 3 In service
29 2025-26 HW Contingency 4 Out of service
30 2025-26 HW Contingency 4 In service
Table 3 – TCS-30 Additional Study Base Cases The Transmission Provider’s Klamath Falls-Fishhole 69 kV line (Line 9) is operated in an open loop configuration, with most sections of this line having a primary transmission source and one
or more alternate transmission sources. The proposed POI for TCS-30 is on the Lakeview Junction-
Dairy section of Line 9. The primary or normal transmission source to this line section is from the Klamath Falls 230-69 kV substation via 69 kV circuit breaker 3L9. Depending on the outage affecting the transmission supply of Line 9 and system conditions, there are three alternate transmission configurations available on the existing system and one future configuration as
described below.
The study evaluated five transmission system configurations to determine requirements associated with the proposed interconnection of TCS-30:
• Normal transmission configuration: Klamath Falls 230-69 kV substation supplies Hornet, Dairy, Casebeer and Bonanza substations as well as the proposed TCS-30 POI via 69 kV Line 9 (K5).
• Contingency transmission configuration 1: Klamath Falls-Hornet section of 69 kV Line 9 is out of service; Ross Avenue substation is transferred to Line 56 via Lakeport; Hornet substation is transferred to the Malin 230-69 kV source via Line 5; Casebeer and Bonanza substations are transferred to the Fishhole 115-69 kV source via Line 9; Bryant Tap-Lakeview Junction section of Line 56-2 is closed; Klamath Falls 230-69 kV substation
supplies Texum, Bryant and Dairy substations as well as the proposed TCS-30 POI via Line 56 (K7).
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• Contingency transmission configuration 2: Klamath Falls-Hornet section of 69 kV Line 9
is out of service; Hornet-Henley Tap section of Line 5 is closed; Malin 230 -69 kV
s ubstation supplies Newell, Clear Lake, Perez, Tulelake, Turkey Hill, Merrill, Henley, Hornet, Dairy, Casebeer and Bonanza substations as well as the proposed TCS-30 POI via Line 5 (K4).
• Contingency transmission configuration 3: Lakeview Junction-TCS-30 POI substation section of Line 9 is out of service; Bonanza Tap-Sprague River Tap section of Line 9 is closed; Fishhole 115-69 kV substation supplies Bly, Beatty, Sprague River, Casebeer, Bonanza and Dairy substations as well as the proposed TCS-30 POI via Line 9 (K5);

• Future contingency transmission configuration 4: planned Malin-Casebeer 69 kV line is in service; outage of Line 9 on the Klamath Falls-Hornet or Hornet-Lakeview Junction-TCS-30 POI sections; Malin 230-69 kV substation supplies Bonanza, Casebeer and Dairy
substations as well as the proposed TCS-30 POI via the planned 69 kV transmission line.
1. SUMMARY OF POWER FLOW SIMULATION
A power flow simulation of the TCS-30 generating facility (operating at 10 MW maximum) added to the Transmission Provider’s transmission system concluded the following:
• The Transmission Provider’s system is expected to have adequate thermal capacity
for the flow of TCS-30 generation in normal transmission configuration, in
contingency transmission configuration no. 1 and in future contingency configuration no. 4.
• The Transmission Provider’s system steady state voltages and post transient voltage deviation are predicted in power flow simulation to be acceptable in normal
transmission configuration, in contingency transmission configuration no. 1 and in
future contingency configuration no. 4.
• The Transmission Provider’s system does not have adequate thermal capacity for the flow of TCS-30 generation in transmission configurations no. 2 and 3.
• The Transmission Provider’s system voltages and post transient voltage deviation are predicted in power flow simulation to exceed acceptable limits in contingency transmission configuration no. 2.
• The Transmission Provider’s system voltage is predicted to collapse in contingency
transmission configuration no. 3 at moderate to heavy load levels.
• Generation can be accepted from TCS-30 in normal transmission configuration, in contingency transmission configuration no. 1 and in future contingency configuration
no. 4.
• Generation could not be accepted from TCS-30 in contingency transmission configurations no. 2 and 3. Operating procedures will be developed to curtail the generating facility when the transmission system is in one of the abnormal
configurations. This configuration will be replaced with the future transmission
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configuration no. 4 following completion of a planned capital project on the
Transmission Provider’s system. 2. NORMAL TRANSMISSION CONFIGURATION
In normal transmission configuration Klamath Falls 230-69 kV substation supplies Hornet, Dairy,
Casebeer and Bonanza substations as well as the proposed TCS-30 POI via 69 kV Line 9.
Power Flow Analysis
The following table summarizes loading on Line 9 and on the Klamath Falls 230-69 kV
transformers with the addition of TCS-30 generation in normal transmission configuration during
various seasonal load levels with maximum solar generation in the area.

Table 4: Power flow results with TCS-30 in normal transmission configuration
Monitored Facility Rating*
Klamath Falls-Hornet 69 kV line 60/90 -21.6 36% -7.3 12% -9.4 11%
Hornet-Lakeview Jct 69 kV line 60/90 -25.8 43% -12.5 21% -22.0 24%
TCS-30 POI-Lakeview Jct 69 kV line 60/90 -25.9 43% -12.6 21% -22.1 24%
Klamath Falls 230-69 kV XFMR 1 125/150 -30.0 24% 29.0 23% 25.8 17%
Klamath Falls 230-69 kV XFMR 2 125/150 -29.8 24% 28.8 23% 25.6 17%
*Seasonal facility rating (summer/winter) The power flow results show that the thermal rating of the 69 kV Line 9 transmission supply path is adequate to carry generation from TCS-30.

The existing generation and higher priority generation Interconnection Requests can exceed the local load on Line 9 and on the area 69 kV system during certain system conditions. There is reverse power flow on the 69 kV circuit breaker 3L9 and on the 230-69 kV transformers at Klamath Falls substation prior to the proposed interconnection of TCS-30. The addition of the
TCS-30 generation will increase the reverse power flow on these transmission facilities, but the
loading is projected to remain within the facility ratings. Protective relaying systems will need to be reviewed and modified/installed as necessary to accommodate reverse power flow on the 69 kV Line 9 (K5) and on the Klamath Falls 230-69 kV
transformers due to the addition of TCS-30 generation.
A higher priority interconnection request Q0907, with proposed interconnection on the Klamath Falls-Copco No. 2 230 kV line, requires a Remedial Action Scheme that will disconnect the Q0907 generation for an N-1-1 outage of the Meridian-Klamath Co-gen 500 kV line and Snow Goose-
Captain Jack 500 kV line to avoid an overload of the Malin-Snow Goose 230 kV line during
generation surplus in the Klamath Falls area. The addition of the proposed TCS-30 generation was tested for impacts on this contingency scenario. The contribution from the TCS-30 generation to
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the 230 kV line loading in this N-1-1 contingency is less than 1%. Therefore, the TCS-30 Interconnection Request will not be required to participate in the Remedial Action Scheme
associated with the Q0907 interconnection request. Voltage Deviation Analysis The following table compares the post-transient voltage deviation on the Bonanza substation 12
kV bus for a trip of the TCS-30 generation in normal transmission configuration during maximum solar generation and without solar generation on this system. Two scenarios were tested in the power flow simulation - a trip of the main step-up transformer and a trip of the generator, which leaves the plant-side loads supplied from the 69 kV system.

Table 5 Voltage deviation for TCS-30 generation trip in normal configuration
Season/Load Level Scenario Monitored Bus
Post-Transient
Solar Solar
Summer Peak Load Trip of TCS-30 69-13.2 kV XFMR Bonanza 12 kV -1.4% -2.3%
Summer Peak Load Trip of TCS-30 generator Bonanza 12 kV -2.3% -3.4%
Winter Peak Load Trip of TCS-30 69-13.2 kV XFMR Bonanza 12 kV -0.4% -0.8%
Winter Peak Load Trip of TCS-30 generator Bonanza 12 kV -1.1% -1.6%
DML Trip of TCS-30 69-13.2 kV XFMR Bonanza 12 kV -0.5%
DML Trip of TCS-30 generator Bonanza 12 kV -1.1%
Voltages and post-transient voltage steps are projected in power flow simulation to remain within
permissible limits during trip of the TCS-30 generation in normal transmission configuration
under various load and generation conditions. Reactive Margin Analysis
The following table compares reactive margin on the Bonanza substation 69 kV bus in normal
transmission configuration prior to and with the TCS-30 generation during summer peak load with maximum solar generation in the area. This analysis measures voltage stability, with more negative reactive margin magnitude indicating greater voltage stability. The WECC requires electric utilities to maintain adequate voltage stability to protect the operating integrity of the power grid.

Table 6: Reactive margin during normal transmission configuration
Contingency Event Monitored Bus
Voltage Stability Magnitude of Reactive Margin
System normal configuration Bonanza 69 kV -38.3 -40.1
Loss of Klamath Falls 230-69 kV XFMR #1 Bonanza 69 kV -31.3 -37.4
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Loss of Klamath Falls-Snow Goose 230 kV line Bonanza 69 kV -38.5 -33.5
The TCS-30 Interconnection Request does not negatively impact the reactive margin on the
Transmission Provider’s system. Generation can be accepted from TCS-30 in normal transmission configuration. 3. CONTINGENCY TRANSMISSION CONFIGURATION NO. 1
In contingency configuration no. 1 the Klamath Falls 230-69 kV substation supplies Texum, Bryant and Dairy substations as well as the proposed TCS-30 POI via 69 kV Line 56 (K7). This configuration is used for an outage of the Klamath Falls-Hornet section of Line 9 during the summer operating season or during heavy load periods as an alternate supply to Dairy substation
from Klamath Falls, while Hornet substation is transferred to the Malin 230-69 kV source and Casebeer and Bonanza substations are transferred to the Fishhole 115-69 kV source. This configuration will be replaced with the future transmission configuration no. 4 following completion of a planned capital project on Transmission Provider’s system.
Power Flow Analysis

The following two tables compare loading on Line 56 in contingency transmission configuration no. 1 with maximum solar generation in the area prior to and with the TCS-30 generation.
Table 7: Power flow results prior to TCS-30 in contingency configuration no. 1
Monitored Facility Rating*
Klamath Falls-Texum 69 kV line 60/90 -8.1 14% 30.2 51% 27.7 31%
Texum-Bryant 69 kV line 40/52 -7.9 20% 19.6 50% 16.3 31%
37/55 -14.9 40% -9.4 26% -15.3 28%
Lakeview Jct-TCS-30 POI 69 kV line 60/90 -15.0 25% -9.4 16% -15.4 17%
Klamath Falls 230-69 kV XFMR 1 125/150 -27.6 22% 23.1 18% 22.2 15%
Klamath Falls 230-69 kV XFMR 2 125/150 -27.4 22% 23.0 18% 22.0 15%
*Seasonal facility rating (summer/winter) Table 8: Power flow results with TCS-30 in contingency configuration no. 1
Monitored Facility Rating* (MVA)
Seasonal Loading
Heavy Summer Heavy Winter
MVA % MVA % MVA %
Klamath Falls-Texum 69 kV line 60/90 -14.4 24% 23.4 39% 20.7 23%
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Texum-Bryant 69 kV line 40/52 -14.7 37% 13.7 35% 9.5 18%
37/55 -22.4 60% -16.8 46% -22.6 41%
60/90 -22.5 37% -16.9 28% -22.7 25%
Klamath Falls 230-69 kV XFMR 1 125/150 -31.2 25% 21.1 17% 20.1 13%
Klamath Falls 230-69 kV XFMR 2 125/150 -30.9 25% 21.0 17% 19.9 13%
*Seasonal facility rating (summer/winter) The existing generation and higher priority generation Interconnection Requests can exceed the local load on Line 56 during certain system conditions. There is reverse power flow on the 69 kV circuit breaker 3L6 at Klamath Falls substation prior to the proposed interconnection of TCS-30.
The addition of the TCS-30 generation will increase the reverse power flow on these transmission
facilities, but the loading is projected to remain within the facility ratings. Protective relaying systems will need to be reviewed and modified/installed as necessary to accommodate reverse power flow on the 69 kV Line 56 (K7) due to the addition of TCS-30
generation.
Voltage Deviation Analysis
The following table compares the post-transient voltage deviation on the Dairy substation 12 kV
bus for a trip of the TCS-30 generation in contingency transmission configuration no. 1 during
maximum solar generation and without solar generation on this system. Table 9: Voltage deviation for TCS-30 generation trip in contingency configuration no. 1
Season/Load Level Scenario Monitored Bus
Post-Transient
Solar Solar
Summer Peak Load Trip of TCS-30 69-13.2 kV XFMR Dairy 12 kV -1.1% -1.9%
Summer Peak Load Trip of TCS-30 generator Dairy 12 kV -2.0% -3.0%
Winter Peak Load Trip of TCS-30 69-13.2 kV XFMR Dairy 12 kV -0.5% -1.0%
Winter Peak Load Trip of TCS-30 generator Dairy 12 kV -1.3% -1.8%
DML Trip of TCS-30 69-13.2 kV XFMR Dairy 12 kV -0.4%
DML Trip of TCS-30 generator Dairy 12 kV -1.3%
Voltages and post-transient voltage steps are projected in power flow simulation to remain within permissible limits during trip of the TCS-30 generation in contingency transmission configuration no. 1 under various load and generation conditions.
Reactive Margin Analysis
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The following table compares the reactive margin on the Dairy substation 69 kV bus in contingency transmission configuration no. 1 prior to and with the TCS-30 generation during
summer peak load with maximum solar generation in the area. Table 10: Reactive margin during contingency configuration no. 1
Contingency Event Monitored Bus
Voltage Stability Magnitude of Reactive Margin
System normal configuration Dairy 69 kV -62.3 -66.0
Loss of Klamath Falls 230-69 kV XFMR #1 Dairy 69 kV -50.0 -53.6
Loss of Klamath Falls-Snow Goose 230 kV line Dairy 69 kV -62.3 -66.0
The TCS-30 Interconnection Request does not negatively impact the reactive margin on the Transmission Provider’s system.
Generation can be accepted from TCS-30 in contingency transmission configuration no. 1.
4. CONTINGENCY TRANSMISSION CONFIGURATION NO. 2 This configuration is generally used for an outage of the Klamath Falls-Hornet section of Line 9 during the winter operating season or when the contingency supply out of Klamath Falls via Line
56 is unavailable to provide an alternate supply to Hornet, Dairy, Casebeer and Bonanza
substations from the Malin 230-69 kV substation via Line 5. This configuration will be replaced with the future transmission configuration no. 4 following completion of a planned capital project on Transmission Provider’s system.
Power Flow Analysis

The following two tables compare loading on the Malin 230-69 kV transformer and the Malin-Malin tap 69 kV line in contingency transmission configuration no. 2 with maximum solar generation in the area prior to and with the TCS-30 generation.
Table 11: Power flow results prior to TCS-30 in contingency configuration no. 2
Monitored Facility Rating*
Malin 230-69 kV XFMR 125/150 -23.1 18% 33.5 27% -3.1 2%
Malin-Malin Tap 69 kV line 73/109 -23.1 33% 33.5 45% -3.1 3%
*Seasonal facility rating (summer/winter)

Table 12: Power flow results with TCS-30 in contingency configuration no. 2
Monitored Facility Seasonal Loading
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Rating*
Malin 230-69 kV XFMR 125/150 -30.8 25% -21.4 17% -8.7 7%
Malin-Malin Tap 69 kV line 73/109 -30.8 44% -21.4 29% -8.7 12%
*Seasonal facility rating (summer/winter) The existing generation and higher priority generation Interconnection Requests can exceed the local load on Line 78/Line 5 and on the area 69 kV system during certain system conditions. The 69 kV circuit breaker 3L179 and the 230-69 kV transformer at Malin substation can experience
reverse power flow prior to the proposed interconnection of TCS-30. Addition of TCS-30 in
contingency transmission configuration no. 2 will increase the reverse power flow on these facilities, but the loading is projected to remain well under the facility ratings. Voltage Deviation Analysis

The following table compares the post-transient voltage deviation on the Bonanza substation 12 kV bus for a trip of the TCS-30 generation in contingency transmission configuration no. 2 during maximum solar generation on this system.
Table 13: Voltage deviation for TCS-30 generation trip in contingency configuration no. 2
Season/Load Level Scenario Monitored Bus
Post-Transient
Summer Peak Load Trip of TCS-30 69-13.2 kV XFMR Bonanza 12 kV -7.8%
Summer Peak Load Trip of TCS-30 generator Bonanza 12 kV -11.8%
Winter Peak Load Trip of TCS-30 69-13.2 kV XFMR Bonanza 12 kV -4.6%
Winter Peak Load Trip of TCS-30 generator Bonanza 12 kV -6.9%
DML Trip of TCS-30 69-13.2 kV XFMR Bonanza 12 kV -4.3%
DML Trip of TCS-30 generator Bonanza 12 kV -6.4%
The post-transient voltage deviation was shown in power flow simulation to exceed the 6.0% limit on the Bonanza substation 12 kV bus during trip of the TCS-30 generation in contingency
transmission configuration no. 2.
An additional simulation was performed to trip TCS-30 generation during summer peak load and during winter peak load without solar generation on this system. This condition was shown in the simulation to cause an excessive post-transient voltage deviation of up to 12.9% for a trip of the
main step-up transformer and up to 23.5% for a trip of the generator.
Generation from TCS-30 could not be accepted while the Transmission Provider’s system is operating in contingency transmission configuration no. 2.

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5. CONTINGENCY TRANSMISSION CONFIGURATION NO. 3
In this system configuration, Fishhole 115-69 kV substation supplies Bly, Beatty, Sprague River, Dairy, Casebeer and Bonanza substations via Line 9. This configuration is generally used for an
outage of the Dairy-Lakeview Junction section of Line 9 during light to moderate loading periods
as an alternate supply to Casebeer and Bonanza substations. Due to a potential risk of voltage collapse during heavy load conditions with low generation, Dairy substation can only be supplied in this configuration during the lightest loading conditions. This configuration will be replaced with the future transmission configuration no. 4 following completion of a planned capital project
on Transmission Provider’s system.

Power Flow Analysis
The following two tables compare loading on the Fishhole 115-69 kV substation equipment and on the Fishhole-Bly 69 kV line in contingency transmission configuration no. 3 with maximum solar generation in the area prior to and with the TCS-30 generation.
Table 14: Power flow results prior to TCS-30 in contingency configuration no. 3
Monitored Facility Rating*
Fishhole 115-69 kV XFMR 18.8/23.4 -25.6 136% - - -20.7 89%
Fishhole 69 kV regulator 28/35.5 -25.6 91% - - -20.7 58%
Fishhole-Bly 69 kV line 29/38 -17.6 68% - - -12.3 35%
*Seasonal facility rating (summer/winter)
Transmission line loading cannot be evaluated at moderate to heavy loading due to voltage
collapse discussed below.
Table 15: Power flow results with TCS-30 in contingency configuration no. 3
Monitored Facility Rating*
Fishhole 115-69 kV XFMR 18.8/23.4 -31.5 168% -16.6 88% -27.0 144%
Fishhole 69 kV regulator 28/35.5 -31.5 113% -16.6 59% -27.0 97%
Fishhole-Bly 69 kV line 29/38 -23.9 93% -8.8 33% -19.0 56%
*Seasonal facility rating (summer/winter)
The existing generation and higher priority generation Interconnection Requests can exceed the local load on Line 9, causing significant reverse power flow toward the 115 kV system at Fishhole substation. The existing and higher priority generation exceeds the capacity of the Fishhole 115-
69 kV transformer and is curtailed in this system configuration. Addition of the TCS-30
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generation in contingency transmission configuration no. 3, is shown in the power flow simulation to increase the overload of the Fishhole 115-69 kV transformer by 32% and cause a new overload
of the Fishhole 69 kV voltage regulator. Voltage Deviation Analysis
Existing load at Dairy substation would cause voltage collapse at moderate to heavy loading when operating in contingency transmission configuration no. 3. Voltage stability at light load is
adequate but minimal. Contingency transmission configuration no. 3 is typically used for short periods of time to perform scheduled maintenance on Line 9 west of Dairy substation.

Generation from TCS-30 could not be accepted while the Transmission Provider’s system is
operating in contingency transmission configuration no. 3.

6. CONTINGENCY TRANSMISSION CONFIGURATION NO. 4

This is a future transmission system configuration following completion of Transmission Provider’s planned capital project to construct a new 69 kV transmission line between Malin substation and Bonanza substation. The future 69 kV transmission line will become the primary
source to Bonanza, Casebeer and Dairy substations and it will provide a new contingency source
to several substations in the area including the proposed TCS-30 POI, eliminating the use of contingency configurations no. 1, 2 and 3 for an outage of the Klamath Falls-Hornet, Hornet-Lakeview Junction and Lakeview Junction-Dairy sections of Line 9.
Power Flow Analysis

The following table compares loading on the 69 kV system between TCS-30 POI and Malin
substation during maximum solar generation in the area with the TCS-30 generation in service.

Table 16: Power flow results with TCS-30 in future contingency configuration no. 4
Monitored Facility Rating*
Malin 230-69 kV XFMR 125/150 -35.4 28% -12.3 10% -23.2 13%
Malin-Bonanza 69 kV line (future) 102/150 -25.7 26% -12.7 13% -21.6 15%
Bonanza-Casebeer 69 kV line 102/150 -27.2 27% -17.4 17% -23.7 16%
Casebeer-Bonanza Tap 69 kV line 102/150 -24.7 25% -19.3 19% -25.3 17%
Bonanza Tap-Dairy 69 kV line 60/90 -24.9 42% -19.4 33% -25.5 29%
Dairy- TCS-30 POI 69 kV line 60/90 -10.0 17% -10.0 17% -10.0 11%
*Seasonal facility rating (summer/winter)
The power flow results show that the thermal rating of the 69 kV path between TCS-30 POI and Malin is adequate to carry generation from TCS-30.
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The existing generation and higher priority generation Interconnection Requests can exceed the
local load on this 69 kV system, which can cause reverse power flow on the future Malin-Casebeer 69 kV line and on the 230-69 kV transformer at Malin substation prior to the proposed interconnection of TCS-30. The addition of the TCS-30 generation is shown to increase the reverse power flow on these transmission facilities. Reverse power flow at Malin substation is within the facility ratings.
As part of the planned 69 kV line project, protective relaying systems will need to be installed to accommodate reverse power flow on the future Malin-Casebeer 69 kV line and on the Malin 230-69 kV transformer due to the existing generation, higher priority Interconnection Requests and
the proposed addition of TCS-30.
Voltage Deviation Analysis
The following table compares the post-transient voltage deviation on the Dairy substation 12 kV
bus for a trip of the TCS-30 generation in contingency transmission configuration no. 4 during
maximum solar generation and without solar generation on this system. Table 17: Voltage deviation for TCS-30 generation trip in future contingency configuration no. 4
Season/Load Level Scenario Monitored Bus
Post-Transient
Solar Solar
Summer Peak Load Trip of TCS-30 69-13.2 kV XFMR Dairy 12 kV -1.2% -1.9%
Summer Peak Load Trip of TCS-30 generator Dairy 12 kV -2.6% -3.5%
Winter Peak Load Trip of TCS-30 69-13.2 kV XFMR Dairy 12 kV -2.3% -2.9%
Winter Peak Load Trip of TCS-30 generator Dairy 12 kV -3.7% -4.4%
DML Trip of TCS-30 69-13.2 kV XFMR Dairy 12 kV -2.7% -
DML Trip of TCS-30 generator Dairy 12 kV -4.0% -

Voltages and post-transient voltage steps are projected in power flow simulation to remain within permissible limits during trip of the TCS-30 generation in contingency transmission configuration no. 4 under various load and generation conditions.
Reactive Margin Analysis
The following table compares the reactive margin on the Dairy substation 69 kV bus in contingency transmission configuration no. 4 prior to and with the TCS-30 generation during summer peak load with maximum solar generation in the area.

Table 18: Reactive margin during contingency configuration no. 4
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Contingency Event Monitored Bus
Voltage Stability Magnitude of Reactive Margin
System normal configuration Dairy 69 kV -45.3 -47.6
Loss of Malin 500-230 kV XFMR Dairy 69 kV -42.7 -44.9
The TCS-30 Interconnection Request does not negatively impact the reactive margin on the
Transmission Provider’s system. Generation can be accepted from TCS-30 in future contingency configuration no. 4.
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13.2 Appendix 2: Higher Priority Requests
All active higher priority Transmission Provider projects, and transmission service and/or
generator interconnection requests will be considered in this cluster area study and are identified below. If any of these requests are withdrawn, the Transmission Provider reserves the right to restudy this request, as the results and conclusions contained within this study could significantly change.
Transmission/Generation Interconnection Queue Requests considered:
GI
Queue
Size
(MW)
687 415.8
721 55
741 40
757 20
806 20
825 10
826 10
827 10
828 13
829 10
830 10
849 100
905 50
906 80
907 80

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13.3 Appendix 3: Property Requirements
Property Requirements for Point of Interconnection Substation
Requirements for rights of way easements Rights of way easements will be acquired by the Interconnection Customer in the Transmission Provider’s name for the construction, reconstruction, operation, maintenance, repair, replacement and removal of Transmission Provider’s Interconnection Facilities that will be owned and operated by PacifiCorp. Interconnection Customer will acquire all necessary permits for the
Project and will obtain rights of way easements for the Project on Transmission Provider’s easement form. Real Property Requirements for Point of Interconnection Substation
Real property for a POI substation will be acquired by an Interconnection Customer to
accommodate the Interconnection Customer’s Project. The real property must be acceptable to Transmission Provider. Interconnection Customer will acquire fee ownership for interconnection substation unless Transmission Provider determines that other than fee ownership is acceptable; however, the form and instrument of such rights will be at Transmission Provider’s sole
discretion. Any land rights that Interconnection Customer is planning to retain as part of a fee
property conveyance will be identified in advance to Transmission Provider and are subject to the Transmission Provider’s approval. The Interconnection Customer must obtain all permits required by all relevant jurisdictions for
the planned use including but not limited to conditional use permits, Certificates of Public
Convenience and Necessity, California Environmental Quality Act, as well as all construction permits for the Project. If eligible, Interconnection Customer will not be reimbursed through network upgrades for more
than the market value of the property.
As a minimum, real property must be environmentally, physically, and operationally acceptable to Transmission Provider. The real property shall be a permitted or able to be permitted use in all zoning districts. The Interconnection Customer shall provide Transmission Provider with a title
report and shall transfer property without any material defects of title or other encumbrances that
are not acceptable to Transmission Provider. Property lines shall be surveyed and show all encumbrances, encroachments, and roads. Examples of potentially unacceptable environmental, physical, or operational conditions could
include but are not limited to:
1. Environmental: known contamination of site; evidence of environmental contamination by any dangerous, hazardous or toxic materials as defined by any governmental agency; violation of building, health, safety, environmental, fire,
land use, zoning or other such regulation; violation of ordinances or statutes of
any governmental entities having jurisdiction over the property; underground or above ground storage tanks in area; known remediation sites on property; ongoing mitigation activities or monitoring activities; asbestos; lead-based paint, etc. A
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phase I environmental study is required for land being acquired in fee by the Transmission Provider unless waived by Transmission Provider.
2. Physical: inadequate site drainage; proximity to flood zone; erosion issues; wetland overlays; threatened and endangered species; archeological or culturally sensitive areas; inadequate sub-surface elements, etc. Transmission Provider may require Interconnection Customer to procure various studies and surveys as
determined necessary by Transmission Provider. Operational: inadequate access for Transmission Provider’s equipment and vehicles; existing structures on land that require removal prior to building of substation; ongoing maintenance for
landscaping or extensive landscape requirements; ongoing homeowner's or other requirements or
restrictions (e.g., Covenants, Codes and Restrictions, deed restrictions, etc.) on property which are not acceptable to the Transmission Provider.