HomeMy WebLinkAbout20210920PAC to Bayer 117-142 SIS Report_Rev1.pdf
Large Generator Interconnection
System Impact Study Report
Completed for
PacifiCorp Energy Supply Management
Pryor Mountain Wind
Proposed Point of Interconnection
Frannie-Yellowtail 230 kV transmission line
August 16, 2019
System Impact Study Report
TABLE OF CONTENTS
1.0 DESCRIPTION OF THE GENERATING FACILITY .................................................................... 1
2.0 SCOPE OF THE STUDY ................................................................................................................. 1
3.0 TYPE OF INTERCONNECTION SERVICE .................................................................................. 2
4.0 DESCRIPTION OF PROPOSED INTERCONNECTION ............................................................... 2
5.0 STUDY ASSUMPTIONS ................................................................................................................. 3
6.0 ENERGY RESOURCE (ER) INTERCONNECTION SERVICE .................................................... 4
6.1.1 Requirements 4
6.1.2 Cost Estimate (ER) 11
7.0 APPENDICES ................................................................................................................................ 13
7.1 Appendix 1: Higher Priority Requests ............................................................................................ 14
7.2 Appendix 2: Contingent Facilities .................................................................................................. 15
7.3 Appendix 3: Property Requests ....................................................................................................... 16
7.4 Appendix 4: Study Results .............................................................................................................. 18
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1.0 DESCRIPTION OF THE GENERATING FACILITY
PacifiCorp ESM (“Interconnection Customer”) proposed interconnecting 240 MWs of new
generation to PacifiCorp’s (“Transmission Provider”) Frannie–Yellowtail 230 kV transmission
line approximately 14 miles north of the Frannie substation located in Park County, Montana. The
Pryor Mountain Wind project (“Project”) will consist of 55 Vesta V110-2.0MK10B, 24 Vestas
V110-2.2MK10C, 29 Vestas V110-2.2MK10D, and 4 GE2.3-116 wind turbine generators for a
total output of 240 MWs. The requested commercial operation date is approximately December
1, 2020.
Interconnection Customer will NOT operate this generator as a Qualified Facility as defined by
the Public Utility Regulatory Policies Act of 1978 (PURPA).
2.0 SCOPE OF THE STUDY
This restudy is being performed for the following reasons:
1. The Interconnection Customer requested to move the physical location of the Point of
Interconnection substation which the Transmission Provider determined was not a Material
Modification.
2. The Interconnection Customer requested to switch the jurisdiction of the Interconnection
Request from a state jurisdictional qualifying facility project to a FERC jurisdictional
project which the Transmission Provider determined was not a Material Modfication.
The interconnection system impact study shall evaluate the impact of the proposed interconnection
on the reliability of the transmission system. The interconnection system impact study will
consider Base Case as well as all generating facilities (and with respect to (iii) below, an identified
network upgrades associated with such higher queued interconnection) that, on the date the
interconnection system impact study is commenced:
(i) are directly interconnected to the transmission system;
(ii) are interconnected to Affected Systems and may have an impact on the interconnection
request;
(iii) have a pending higher queued interconnection request to interconnect to the transmission
system; and
(iv) have no Queue Position but have executed an LGIA or requested that an unexecuted
LGIA be filed with FERC.
The interconnection system impact study will consist of a short circuit analysis, a stability analysis,
and a power flow analysis. The interconnection system impact study will state the assumptions
upon which it is based; state the results of the analyses; and provide the requirements or potential
impediments to providing the requested interconnection service, including preliminary indication
of the cost and length of time that would be necessary to correct any problems identified in those
analyses and implement the interconnection. The interconnection system impact study will provide
a list of facilities that are required as a result of the Interconnection Request and a non-binding
good faith estimate of the cost responsibility and a non-binding good faith estimated time to
construct.
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3.0 TYPE OF INTERCONNECTION SERVICE
The Interconnection Customer has selected Energy Resource (ER) Interconnection Service.
4.0 DESCRIPTION OF PROPOSED INTERCONNECTION
The Interconnection Customer’s proposed Generating Facility is to be interconnected to the
Frannie-Yellowtail 230 kV transmission line via a new Point of Interconnection substation to be
located approximately 14 miles from the Frannie substation. Figure 1 below is a one-line
diagram that illustrates the interconnection of the proposed Generating Facility to the
Transmission Provider’s system.
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Yellowtail
Substation
Q0542 POI
Substation
230 kV
Frannie
Substation
Garland
Substation
Point of Interconnection
Change of
ownership
14.26 Miles
41.14 Miles
M
Oregon Basin
Substation
34.5 kV
Q0542
Collector
Substation
12 – 2.0 MW WTG M2.0 MW 690 V
2.1 MVA Z=8.7%
@1.9 MVA
690 V
2.2 MW
2.3 MVA Z=8.7%
@ 2.06 MVA1 – 2.2 MW WTG
11 – 2.0 MW WTGTotal
35-1
35-2
12 – 2.0 MW WTG 35-3
12 – 2.0 MW WTG
35-4
3 – 2.2 MW WTG
8 – 2.0 MW WTG
35-5
M
9 – 2.2 MW WTG
2 – 2.0 MW WTG
35-6
690 V
690 V
2.3 MW
2,421 kVA
2.3 MVA
Z=5.75 %7 – 2.2 MW WTG
4 – 2.3 MW WTGTotal
35-7
2.2 MW
11 – 2.2 MW WTG
35-8
11 – 2.2 MW WTG 35-9
11 – 2.2 MW WTG
35-10
2.3 MVA Z=8.7%
@ 2.06 MVA
90/120/150 MVA
Z=9%
90/120/150 MVA
Z=9%230-1
230-2
Figure 1: Simplified System One Line Diagram
5.0 STUDY ASSUMPTIONS
All active higher priority transmission service and/or generator interconnection requests
will be considered in this study and are listed in Appendix 1. 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:
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o Transmission Service Queue: to the extent practical, all network upgrades that are
required to accommodate active transmission service requests will be modeled in
this study.
o Generation Interconnection Queue: Interconnection Facilities associated with
higher queue interconnection requests will be modeled in this study.
The Interconnection Customer’s request for energy or network resource interconnection
service in and of itself does not 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 Resource
Interconnection Service may be significantly different. Therefore, the Interconnection
Customer 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, which are required to provide Network Resource
Interconnection Service will be evaluated on the basis of 100 percent deliverability (i.e.,
no displacement of other resources in the same area).
This study assumes the Project will be integrated into the Transmission Provider’s system
at agreed upon and/or proposed Point of Interconnection.
The Interconnection Customer will 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 will be 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 http://www.pacificorp.com/tran.html
6.0 ENERGY RESOURCE (ER) INTERCONNECTION SERVICE
Energy Resource Interconnection Service allows the Interconnection Customer to connect its
Generating Facility to the Transmission Provider’s Transmission System and to be eligible to
deliver electric output using firm or non-firm transmission capacity on an as available basis.
6.1.1 Requirements
6.1.1.1 Generating Facility Modifications
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
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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 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.
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
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by the generation facility in subsequent interaction/coordination studies will be required pre- and
post-commercial operation in order ensure system reliability.
To facilitate collection and validation of accurate modeling data to meet NERC modeling
standards, PacifiCorp, 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 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 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 verifying in writing that the inverters have been programmed
to meet ALL PRC-024 requirements vs. the manufacturers IEEE distribution settings.
Figure 2 – Voltage Ride-Through Curve
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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.
6.1.1.2 Transmission System Modifications
Construct a new 230 kV three breaker ring substation to serve as the Point of Interconnection.
A remedial action scheme (RAS) will be required that trips the Q0542 Project for loss of the
Q0542 POI–Yellowtail 230 kV transmission line under certain heavy load, heavy generation
conditions.
6.1.1.3 Transmission/Distribution Line Modifications
Construct a 400 ft- 230 kV Loop-in on both the north and south ends of the Q0542 POI near
structure 3/135 and 4/135 on the Thermopolis- Yellowtail 230 kV Transmission Line.
Install 14.06 miles of 3/8” OPGW between Frannie Sub and the POI sub (replacing one of the
two existing 3/8” Steel Shield wires). Correct approx. 10 Class B – structural defect conditions.
Additionally, replace one x-brace in this section.
Replace one shield wire with 3/8” OPGW (replacing one of the two existing 3/8” shield wires)
between Q0542 and Yellowtail Sub on the Thermopolis-Yellowtail 230 kV Transmission Line.
The distance is 41.34 miles.
Correct approx. 30 Class B – structural defect conditions. Additionally, replace 7 x-braces in
this section.
6.1.1.4 Existing Circuit Breaker Upgrades – Short Circuit
The increase in the fault duty on the system as a result of the addition of the generation facility
with the 57 – 2.0 MW wind turbine generators connected to 57 - 34.5 kV – 690 V 2.1 MVA
transformers with Z= 8.7 % @1.9 MVA, 50 – 2.2 MW wind turbine generators connected to 57
– 2.3 MVA 34.5 kV – 690 V 2.3 MVA transformers with Z=8.7% @2.06 MVA, and 4 – 2.3 MW
wind turbine generators connected to 4 – 2.3 MVA 34.5 kV – 690 V transformers with Z=5.75 %
and then the combination fed through 2 – 90/120/150 MVA 230 – 34.5 kV transformers with 9%
impedance will not push the fault duty above the interrupting rate of any of the existing fault
interrupting equipment.
6.1.1.5 Protection Requirements
The installation of protective relays for line fault detection will be required at the Transmission
Provider’s new 230 kV Point of Interconnection (POI) Substation for the protection of the line to
the Interconnection Customer’s Collector substation and the lines to Yellowtail and Oregon
Basin substations. The lines to Yellowtail and Oregon Basin substation will use permissive over
reaching transfer trip line relaying logic. The line relay systems will require communication
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circuits between the substations. The line relays currently in Yellowtail and Oregon Basin
substations will be compatible with the relays to be installed at the POI substation so only relay
setting changes will be required at those substations for this project.
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
Generation Interconnection Customer’s collector substation will be protected with a bus
differential relay systems. The bus differential relays will be located in the POI substation. The
Generation Interconnection Customer will need to provide the output from two sets of current
transformers from the transformer 230 kV breaker. These currents will be fed into the bus
differential relays. If a fault is detected both the 230 kV breakers in the POI substation and the
230 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 open the
Interconnection Customer’s 230 kV transformer breaker at the collector substation.
To meet the requirements for the RAS listed in section 6.1.1.2 line loss logic units will be
installed in Yellowtail and the Q0542 POI substations. Redundant communication paths will be
required between the two substations. If both breakers for the Yellowtail – Q0542 POI 230 kV
line are opened at either terminal of the line the line loss logic unit at Q0542 POI will trip the
two breakers for the tie line to the Q0542 Collector substation.
6.1.1.6 Data (RTU) Requirements
The installation of a RTU is required at the Transmission Provider’s Point of Interconnection (POI)
substation. Additional data for the operation of the power system will be needed from
Interconnection Customer’s collector substation. These quantities will be wired into the RTU at
the POI substation. In addition to the control and indication of the 230 kV breakers in the POI
substation the following data from the POI substation and the Interconnection Customer’s collector
substation will be monitored:
From the POI substation:
Analogs:
Net generation MW
Net generation MVAr
Energy register values
From the Interconnection Customer’s collector substation:
Analogs:
Generation MW Transformer 1
Generation MVAr Transformer 1
Energy register values Transformer 1
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Generation MW Transformer 2
Generation MVAr Transformer 2
Energy register values Transformer 2
Real power flow 34.5 kV line #1
Reactive power flow 34.5 kV line #1
Real power flow 34.5 kV line #2
Reactive power flow 34.5 kV line #2
Real power flow 34.5 kV line #3
Reactive power flow 34.5 kV line #3
Real power flow 34.5 kV line #4
Reactive power flow 34.5 kV line #4
Real power flow 34.5 kV line #5
Reactive power flow 34.5 kV line #5
Real power flow 34.5 kV line #6
Reactive power flow 34.5 kV line #6
Real power flow 34.5 kV line #7
Reactive power flow 34.5 kV line #7
Real power flow 34.5 kV line #8
Reactive power flow 34.5 kV line #8
Real power flow 34.5 kV line #9
Reactive power flow 34.5 kV line #9
Real power flow 34.5 kV line #10
Reactive power flow 34.5 kV line #10
Average Wind Farm Wind Speed (m/s)
Average Wind Farm Atmospheric Pressure (Bar)
Average Wind Farm Temperature (Celsius)
Status:
230 kV transformer 1 breaker
230 kV transformer 2 breaker
34.5 kV Line #1 breaker
34.5 kV Line #2 breaker
34.5 kV Line #3 breaker
34.5 kV Line #4 breaker
34.5 kV Line #5 breaker
34.5 kV Line #6 breaker
34.5 kV Line #7 breaker
34.5 kV Line #8 breaker
34.5 kV Line #9 breaker
34.5 kV Line #10 breaker
6.1.1.7 Substation Requirements
Frannie Substation
Conduit will be installed to support the installation of fiber into the substation.
Oregon Basin Substation
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The substation fence will be expanded to support the installation of a control house and microwave
tower. The Yellowtail line wave trap and power line carrier equipment will be removed.
Yellowtail Substation
Remove the wave trap and power line carrier equipment. One relay panel will be installed.
Q0542 Point of Interconnection substation
The Point of Interconnection substation will be built as a three breaker ring bus substation. The
following equipment has been identified as being required and may change during detailed design.
3 – 230kV, breaker
6 – 230kV, CCVT
3 – 230kV, combined CT/VT metering unit
8 – 230kV, switch, breaker disconnect
3 – 230kV, switch, line disconnect
1 – 230 kV, switch, meter disconnect
9 – 230kV, lightning arrester
1 – 230 kV, SSVT
1 – control house
Q0542 Customer substation
A CDEGS grounding analysis will be required to verify safe step and touch potentials. Six, 230
kV metering instrument transformers will be installed. The customer shall provide a disconnect
switch on each side of each metering instrument transformer. The customer shall provide a
separate lockable room with unencumbered access for PacifiCorp to install metering and
communication equipment.
6.1.1.8 Communication Requirements
Communication requirements to physically connect the Q0542 project will consist of:
Install fiber on the existing 14.26 miles line between Frannie substation and Point of
Interconnection substation.
Upgrade the existing radio system between McCullough Peak to Frannie substation,
McCullough Peak to Oregon Basin substation and McCullough Peak to Cody service
center with company standard microwave radios. This requires new towers at Frannie,
Oregon Basin and Cody service center.
Install multiplex, routers, communication batteries and chargers at all the locations
requiring upgrades.
Install Fiber nodes at Frannie and the Q0542 Point of Interconnection substation.
Install new RTUs at Point of Interconnection substation and the Q0542 collector substation
with a new data concentrator.
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Remove Power line carrier and use mirrored bits on the 230 kV transmission line from
Oregon Basin substation to the Yellowtail substation with interface of WAPA’s new
microwave system at McCullough Peak to Yellowtail substation.
Communications work will also be required at other locations to include Casper Service
Center, Portland Control Center (PCC), and the Salt Lake Control Center (SCC).
6.1.1.9 Metering Requirements
Interchange Metering
At the Transmission Provider’s Q0542 Point of Interconnection substation the interchange
metering will be designed bidirectional and rated for the total net generation of the project
including metering the retail load (per tariff) delivered to the customer. The Transmission
Provider will specify and order all interconnection revenue metering, including the instrument
transformers, metering panels, junction box and secondary metering wire. The primary metering
transformers shall be combination CT/VT extended range for high accuracy metering with ratio’s
to be determined during the design phase of the project The metering instrument transformers are
long lead items and should be given appropriate time to meet in-service expectations.
The metering design package will include two revenue quality meters, test switch, with DNP real
time digital data terminated at a metering interposition block. One meter will be designated a
primary SCADA meter and a second meter will be used designated as backup with metering DNP
data delivered to the alternate control center. The metering data will include bidirectional KWH
KVARH, revenue quantities including instantaneous PF, MW, MVAR including per phase voltage
and amps data.
An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.
6.1.2 Cost Estimate (ER)
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 are not included.
Direct Assigned
Q0542 POI Substation
Line termination and metering $451,000
Total Direct Assigned $451,000
Network Upgrades
Q0542 POI Substation
Construct 230 kV substation $8,037,000
Frannie-Yellowtail Transmission Line
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Install fiber, loop line in/out of POI substation $3,337,000
Yellowtail Substation
Protection and communications equipment $221,000
Oregon Basin Substation
Substation expansion, protection and communications equipment $1,595,000
Frannie Substation
Communications equipment $404,000
Cody Substation
Communications equipment $237,000
McCullough Peak Communications Site
Communications equipment $164,000
Total Network Upgrades $13,990,000
Total Cost $14,441,000
*Any distribution line modifications identified in this report will require a field visit analysis in
order to obtain a more thorough understanding of the specific requirements. The estimate provided
above for this work could change substantially based on the results of this analysis. Until this field
analysis is performed the Transmission Provider must develop the Project schedule using
conservative assumptions. The Interconnection Customer may request that the Transmission
Provider perform this field analysis, at the Interconnection Customer’s expense, prior to the
execution of an Interconnection Agreement in order to obtain more cost and schedule certainty.
Note: Costs for any excavation, duct installation and easements shall be borne by the
Interconnection Customer and are not included in this estimate. This estimate is as accurate as
possibly given the level of detailed study that has been completed to date and approximates the
costs incurred by Transmission Provider to interconnect this Generating Facility to Transmission
Provider’s electrical distribution or transmission system. A more detailed estimate will be
calculated during the Facilities Study. The Interconnection Customer will be responsible for all
actual costs, regardless of the estimated costs communicated to or approved by the Interconnection
Customer.
6.1.1 Schedule
The Transmission Provider estimates it will require approximately 24 months to design, procure
and construct the facilities described in Network Resource sections of this report following the
execution of an Interconnection Agreement. The schedule will be further developed and optimized
during the Facilities Study.
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Please note, the time required to perform the scope of work identified in this report appears to
result in a timeframe that may support the Interconnection Customer’s requested commercial
operation date of December 1, 2020.
7.0 APPENDICES
Appendix 1: Higher Priority Requests
Appendix 2: Contingent Facilities
Appendix 3: Property Requirements
Appendix 4: Study Results
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7.1 Appendix 1: Higher Priority Requests
All active higher priority Transmission Provider projects, and transmission service and/or
generator interconnection requests will be considered in this 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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7.2 Appendix 2: Contingent Facilities
The following Interconnection Facilities and/or upgrades to the Transmission Provider’s system
are Contingent Facilities for the Interconnection Customer’s Interconnection Request and must
be in service prior to the commencement of generation activities: None
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7.3 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.
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.
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7.4 Appendix 4: Study Results
This is a restudy due to the requested change in wind turbine generators by the Customer. A restudy
of the power flow and transient stability analysis was conducted to determine if the change in the
type of wind turbines as proposed by the Customer would negatively impact the reliability of the
transmission system.
Study results indicate that a remedial action scheme (RAS) will be required that trips the Q0542
Project for loss of the Q0542 POI-Yellowtail 230 kV line under some heavy load and heavy wind
generation conditions. Identification of specific load and wind generation conditions will be
identified during RAS scoping and design.
The following modeling data were used in this analysis:
Collector system – PME-B-D002-1 Rev 0A.pdf, PME-B-D002-2 Rev 0A.pdf, PME-B-
D002-3 Rev 0A.pdf drawings providing cable lengths and sizes. Individual wind turbine
generator (WTG) step-up transformers of 2.6 MVA, 5.75%, 34.5/0.69 kV and two main
station transformers of 90/120/150 MVA, 9.0%, 230/34.5 kV from collector drawings.
WTG data – 55 x Vesta V110-2.0MK10B WTGs, 24 x Vestas V110-2.2MK10C WTGs,
29 x Vestas V110-2.2MK10D WTGs, and 4 x GE2.3-116 WTGs. (Due to model
coordination constraints, the four GE WTGs were modeled as Vestas V110-2.2MK10D
turbines.) These Vestas WTGs have very limited reactive power capability. Maximum
gross capability of the WTGs modeled as 239.4 MW with a reactive power range of +23
to -45 MVAR (power factor range of 0.995 capacitive and 0.982 inductive).
Point of Interconnection (POI) – approximately 14 miles north of Frannie 230 kV
substation on Frannie-Yellowtail 230 kV line.
Power Flow Study Results:
Steady-state conditions – heavy stressed conditions modeled with maximum Q0542
generation, peak area loads and heavy south bound system transfers (625 MW Yellowtail
south). It was necessary to add 30 MVAR of 34.5 kV shunt capacitors added on Pryor Mt.
34.5 kV system to provide a net delivery of 235 MW at 0.998 power factor (235 +j 16
MVA); however, it is noted that is it the Customer’s responsibility to design its Project to
meet all interconnection requirements, including power factor.
N-1 outage conditions – worst case N-1 outage is loss of Q0542 POI -Yellowtail 230 kV
line resulting in extremely high voltage (1.4 pu) conditions on the 230 kV and 34.5 kV
transmission and collector systems. Note – Vestas WTGs have limited reactive power
capability to respond to high voltage conditions.
Dynamic Study Results: (worst case N-1 outage)
N-1 outage, no remedial actions - loss of Q0542 POI -Yellowtail 230 kV line resulting in
extremely high voltage conditions (1.15 pu on 230 kV system) and over-voltage tripping
of all Vestas WTGs approximately 23 cycles (< 0.4 seconds) after fault clearing and loss
of the 230 kV line. System performance does not meet criteria.
N-1 outage, with capacitor trip - loss of Q0542 POI -Yellowtail 230 kV line and high speed
tripping of 40 MVAR Frannie 230 kV capacitor banks resulting in high voltage conditions
and over-voltage tripping of one Vestas WTG equivalent (114 MW) approximately 40
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cycles after fault clearing and loss of the 230 kV line. System performance does not meet
criteria.
N-1 outage, with Project Q0542 trip - loss of Q0542 POI - Yellowtail 230 kV line and
tripping of Q0542 Project approximately 5 cycles after fault clearing and loss of the 230
kV line. System performance is marginally acceptable.