HomeMy WebLinkAbout20180216Vail Exhibit 49.pdfCase No.PAC-E-17-07
Exhibit No.49
Witness:Rick A.Vail
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Second Supplemental Testimony of Rick A.Vail
Q0715 SIS Report and Q0810 SIS Report
February 2018
O
Rocky Mountain Power
V PACIFICORP ExhiCb Pa e1of35
TRANSMISSION
Large Generator Interconnection
System Impact Restudy Report
Completed for
Invenergy Wind DevelopmentLLC
("InterconnectionCustomer")
Q0715
Uinta County
Proposed Point of Interconnection
Canyon Compression-Railroad 138 kV transmission line
(Near Whitney Canyon Inlet,near to Structure #116)
February 8,2018
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Rocky Mountain Power
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TABLE OF CONTENTS
1.0 DESCRIPTION OF THE GENERATING FACILITY.....................................................1
2.0 SCOPE OF THE STUDY........................................................l
3.0 TYPE OF INTERCONNECTION SERVICE ....................................................2
4.0 DESCRIPTIONOFPROPOSEDINTERCONNECTION......................................................2
4.1 OtherOptionsConsidered...................................................2
5.0 STUDYASSUMPTIONS.............................................................3
5.1 EnergyResource(ER)InterconnectionService.......................................................4
5.1.1 Requirements 4
5.1.2 Cost Estimate 10
5.1.3 Schedule 11
5.1.4 Maximum Amount of Power that can be delivered into Network Load,with No Transmission
Modifications (for informational purposes only)ll
5.1.5 Additional Transmission Modifications Required to Deliver 100%of the Power into Network
Load (for informational purposes only)11
6.0 PARTICIPATION BY AFFECTED SYSTEMS.......................................................11
7.0 APPENDICES ...............................................................11
7.l Appendix 1:Higher Priority Requests .......................................................13
7.2 Appendix 2:Property Requirements....................................................14
7.3 Appendix 3:Study Results....................................................16
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Invenergy Wind Development LLC Page i February 8,2018
Uinta County,Q0715
Rocky Mountain Power
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1.0 DESCRIPTIONOF THE GENERATINGFACILITY
InvenergyWind Development LLC ("Interconnection Customer")proposed interconnecting 120
MW of new generation to PacifiCorp's ("Transmission Provider")Canyon Compression-Railroad
138 kV transmission line near Whitney Canyon Inlet (near to structure #116)located in Uinta
County,Wyoming.The Uinta County ("Project")will consist of 60 GE 2.0-116 turbines for a total
output of 120 MW.The requested commercial operation date is October 1,2020.
This restudy is being performed due to a change in the ratings of certain facilities that were used
in the evaluationof this Project in the original system impact study.
Interconnection Customer will NOT operate this generator as a Qualified Facility as defined by
the Public UtilityRegulatory Policies Act of 1978 (PURPA).
The Transmission Provider has assigned the Project "Q0715."
2.0 SCOPE OF THE STUDY
The interconnection system impact restudy 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,
any identified network upgrades associatedwith such higher queued interconnections)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 requestto 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.
This interconnection system impact restudy will consist of a short circuit analysis,a stability
analysis,and a power flow analysis.The 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 study will also 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-bindinggood faith estimated time to construct.
Based on the engineering judgement,the stability results for this project are not expected to change
and hence the restudy of stability analysis was not performed.
O Invenergy Wind Development LLC Page 1 February 8,2018
Uinta County,Q0715
Rocky Mountain Power
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3.0 TYPE OF INTERCONNECTIONSERVICE
The Interconnection Customer has selectedEnergy Resource (ER)interconnection service.
4.0 DESCRIPTIONOF PROPOSED INTERCONNECTION
The InterconnectionCustomer's proposed Generating Facility is to be interconnected through a
new substation southwest of the Whitney Canyon Inlet point in Uinta County on the Canyon
Compression -Railroad 138 kV transmission line.Figure 1 below,is a one-line diagram that
illustrates the interconnection of the proposed Generating Facility to the Transmission Provider's
system.
Whitney
Canyon
>0.3 miles
I CanyonCompression
O
Q0715 POl
Substation
Point ofInterconnection
QO715 34.5k
Substation
Figure 1:Simplified System One Line Diagram
4.1 Other Options Considered
The followingalternative options were considered as potential Points of Interconnection
("POI")for this Project:None.
Invenergy Wind Development LLC Page 2 February 8,2018
Uinta County,Q0715
Rocky Mountain Power
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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 materially
modified or 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 separatequeues:
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 requestswith an in-service date of December 2020 or earlier 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.Onlya Network Customer may
make a request to designate a generating resource as a Network Resource.The provision of
transmission service may require additional studies and the construction of additional
upgrades.
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
O 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 POI.
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.
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 Energy Gateway West,Aeolus-Bridger/Anticline D.2,is assumedto be in-service by year
end 2020.
All system improvements associatedwith relevant prior queued projects are in service before
Q0715.
The Midway -Jordanelle 138 kV line is assumedto be in service (2019).
The Point of Interconnection for this Project is assumed to be approximately0.3 miles from
the Transmission Provider's Whitney Canyon Inlet point.Moving the Point of Interconnection
further away from this point must be approved by the Transmission Provider as the study
results could change.
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
Invenergy Wind Developrnent LLC Page 3 February 8,2018
Uinta County,Q0715
Rocky Mountain Power
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5.1 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.
5.1.1 Requirements
5.1.1.1 Generating Facility Modifications
Transmission Provider will require the facility to operate in voltage control mode with
the ability to deliver power output to the POI within the range of+/-0.95 power factor.
(Please see Standard Large Generator Interconnection Agreement,article 9.6.1 and
9.6.2 in OATT.)Any additionalreactive compensation must be designed such that the
discrete switching of the reactive device,if required,does not cause step voltage
changes greater than ±3%at any load serving bus on the Transmission Provider's
system.
As required by NERC standard VAR-001-la,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,or other designated point as deemed appropriated
by Transmission Provider.The Transmission Provider may also specify a voltage
O and/or reactive power bandwidth as neededto 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.The voltage control
settings of the Generating Facility must be coordinated with the Transmission Provider
prior to energization (or interconnection).
At low output levels,the Q0715 Project needs to ensure that it maintains the power
factor within +/-0.95 at the POI and minimize the reactive power flow towards the
transmission system to prevent high voltages.PacifiCorp has experienced high voltages
in the Wyoming area when the transmission system is lightly loaded with low wind
conditions in the area.With low wind conditions the wind farms tend to supply reactive
power into the transmission system increasing the voltage.
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 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.
Invenergy Wind Development LLC Page 4 February 8,2018
Uinta County,Q0715
Rocky Mountain Power
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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
maintainingthe PMU,the Generating Facility will be responsible for collecting,storing
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 Generator Facility's step-
up transformers measured on the low side of the GSU at a sample rate of at least 30
samples per second and synchronized within +/-2 milliseconds of the Coordinated
UniversalTime (UTC).Initially,the followingdata must be collected:
Three phase voltage and voltage angle (analog)
Three phase current (analog)
Data requirements are subject to change as deemed necessaryto comply with local and
federal regulations.
All wind turbines must meet the Federal Energy Regulatory Committee (FERC)and
WECC low voltage ride-through requirements as specified in the interconnection
agreement.Each of the Interconnection Customer's step-up transformers will need to
be switched with a 138 kV circuit breaker.
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.
The Interconnection Customer is responsible for the protection of the transmission line
between the Generating Facility and the Point of Interconnection substation.In order
to provide this protection 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)and
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.
5.1.1.2 Transmission System Modifications
Construct a new three breaker 138 kV POI ring bus substation southwest of the
Whitney Canyon Inlet (near to structure 116),with associated switches and line
terminations.An additional 138 kV breaker (customer-owned)will be required at
the Point of Change of Ownership (see Figure 1).
Modify the existing Naughton West RAS to integrate the Q0715 Project.If the
average of the flows on West of Naughton &West of Evanston is above 900 MW,
Invenergy Wind Development LLC Page 5 February 8,2018
Uinta County,Q0715
Rocky Mountain Power
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Q0715 will be armed to trip for the N-2 outages of either Ben Lomond -Birch
Creek 230 kV line +Ben Lomond -Naughton or Naughton -Birch Creek 230 kV
line +Ben Lomond -Naughton 230 kV line.
o Capability to trip the Q0715 Project if necessary under N-2 outages described
above.
o Redundant communication from the RAS controller to the Project.
5.1.1.3 Transmission Requirements
Construct 300 ft Loop-In of the Canyon Compression-Railroad 138 kV Line to the
Railroad side of the Q0715 POI sub near structure 116.
Replace one shield wire with OPGW between Canyon Compression and the Q0715
POI substation for a distance of 1.38 miles.
The Interconnection Customer shall construct the tie line from the collector
substations to the tie-line substations.
The Interconnection Customer is required to build tie-line substations adjacent to the
POI substation which will house the tie-line breaker.The Transmission Provider shall
review the design of the tie-line span between the tie-line substation deadend tower
and the POI substation deadend tower.The Interconnection Customer shall coil
conductor,OPGW,shield wire,and line hardware with sufficient quantities to span
between the tie-line substation tower and the POI substation tower.
The Transmission Provider will construct the span between the tie-line substation
tower and the POI substation tower.
If any Transmission Provider lines are crossed by Interconnection Customer tie-line,
the Interconnection Customer line will cross under Transmission Provider's line with
at least NESC plus 3 foot clearance under all sag conditions of both lines.
5.1.1.4 Existing Circuit Breaker Upgrades -Short Circuit
The increase in the fault duty on the system as a result of the addition of the Generating
Facility with 125 -GE 2.0-116 2 MW wind turbine generators fed through 60 -2,222
kVA 34.5 kV -690 V transformers with 5.75%impedance then fed through one 138 -
34.5kV 83/112/140 MVA step-up transformer with 9%impedance will not push the
fault duty above the interrupting rating of any of the Transmission Provider's existing
fault interrupting equipment.There is concern that the equipment of other customers
of the Transmission Provider at Canyon Compression substation may need to be
replaced due to the increase in fault duty at that location.Further analysis will be
performed during detailed design if this Project moves forward.
5.1.1.5 Protection Requirements
The Interconnection Customer's tie line substation (having a sole 138kV circuit breaker
and associated equipment)will be adjacent to the Q0715 POI substation with a common
Invenergy Wind Development LLC Page 6 February 8,2018
Uinta County,Q0715
Rocky Mountain Power
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fence between the two facilities.With this configuration the ground mats of the two
substations will be tied together.The short line segment between the tie line substation
and the Q0715 POI substation will be considered a bus section and will be protected
with redundant bus differential relay systems.The bus differential relays will be located
in the Q0715 POI substation.The Interconnection Customer will need to provide the
output from two sets of current transformers to be fed into the bus differential relays
with a maximum current transformer ratio matching the maximum CT ratio of the
breakers at the Q0715 POI substation.If a fault is detected in the short conductor
connection,both the 138kV breakers in the Q0715 POI substation and the 138kV
breaker in the Interconnection Customer's tie line substation will be tripped.
The detection and clearing of faults on the tie line between the tie line and the collector
substation will be the responsibility of the Interconnection Customer.Facilities must
be installed to detect and isolate the line if it is faulted in five cycles or less.
A relay at the Q0715 POI substation will monitor the voltage magnitude and
frequency.If the magnitude or frequency of the voltage is outside of normal range of
operation a signal will be sent over the communication system to the collector
substation.At the collector substation this signal is to trip open all of the 34.5 kV
feeder breakers to disconnect the wind turbine generators.By tripping the 34.5 kV
breakers instead of the 138kV breakers the station service to the plant is maintained
to facilitate the restoration of the generation.This relay will also have phase and
ground directional overcurrent elements set to operate for faults in the line between
the Q0715 POI substation and the collector substation and serve as a backup to the
main protection installed by the Interconnection Customer as indicated in the
previous paragraph.
The installation of protective relays for line fault detection will be required at the
Transmission Provider's Q0715 138kV POI substation for the protection of the lines to
the Interconnection Customer's collector substation and the line to Railroad substation,
where a two-terminal transmission line current differential will be implemented.The
lines from the Q0715 POI substation to Compression substation will also be protected
with a two-terminal transmission line current differential relay system.The connection
to Whitney Canyon substation will be treated as a load for this line differential.
5.1.1.6 Data (RTU)Requirements
In addition to the need for operational data and control at the Q0715 POI substation,
data for the operation of the power system will be neededfrom the collector substation.
This data will be acquired by installing an Interconnection Customer owned data
concentrator at the collector substation.The data will be transferred to the RTU in POI
substation via Interconnection Customer owned fiber on the tie line from the collector
substation.
Listed below is the data that will be acquired from the collector substation,tie line
substation and Q0715 POI substation.
Invenergy Wind Development LLC Page 7 February 8,2018
Uinta County,Q0715
Rocky Mountain Power
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From the Q0715 POI substation:
Analogs:
Net Generation real power
Net Generator reactive power
Interchange energy register
From tie line substation:
Status:
138kV breaker
From the Q0715 collector substation:
Analoes:
Transformer #1 real power
Transformer #1 reactive power
Real power flow through 34.5 kV line feeder breaker 1
Reactive power flow through 34.5 kV line feeder breaker 1
Real power flow through 34.5 kV line feeder breaker 2
O Reactive power flow through 34.5 kV line feeder breaker 2
Real power flow through 34.5 kV line feeder breaker 3
Reactive power flow through 34.5 kV line feeder breaker 3
Real power flow through 34.5 kV line feeder breaker 4
Reactive power flow through 34.5 kV line feeder breaker 4
Real power flow through 34.5 kV line feeder breaker 5
Reactive power flow through 34.5 kV line feeder breaker 5
A phase 138kV transmission voltage
B phase 138kV transmission voltage
C phase 138kVtransmission voltage
Average Wind speed
Average Plant Atmospheric Pressure (Bar)
Average Plant Temperature (Celsius)
Status:
138 kV breaker Tl
34.5 kV collector circuit breaker 1
34.5 kV collector circuit breaker 2
34.5 kV collector circuit breaker 3
34.5 kV collector circuit breaker 4
34.5 kV collector circuit breaker 5
5.1.1.7 Substation Requirements
00715 POI Substation
Invenergy Wind Development LLC Page 8 February 8,2018
Uinta County,Q0715
Rocky Mountain Power
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The Project will require a new 138 kV three breaker ring bus POI substation.The
substation will be approximately 170'x 300'(fence dimensions)based on the
Interconnection Customer provided facility requirements.The POI substation will be
located adjacent to the Interconnection Customer's tie line substation with a common
fence between the facilities.The ground grids for the substations will be tied together
and conduit will be installed between the substation to facilitate installation of
protection,control,and indicationcables.The followingis a list of the major equipment
required for this project:
3 -138 kV Power Circuit Breakers
6 -138 kV CCVTs
3 -138 kV CT/VT Metering Units
11 -138 kV Switches
9 -138 kV Lightning Arresters
1 -138 kV SSVT
1 -Control House
5.1.1.8 Communication Requirements
Installation of fiber is required on the existing line from Canyon Compression
substation to the new Q0715 POI substation.The Interconnection Customer will need
to install OPGW fiber on the line from Q0715 collector substation to the tie line
substation where it will then connect to the Transmission Provider's communication
equipment.Fiber nodes,multiplex and fiber terminationpanels are required at all three
locations.At the Q0715 POI substation a 48 volt communication battery and charger
is required for protection circuits.At Canyon Compression substation the
communications are connected to the backbone via existing fiber and microwave.
Substation network is to be installed at all three locations for metering and status.
With the Naughton RAS requirements for redundant communications,a leased Tl
circuit is to be installed at the POI substation with the other endterminated at Naughton
substation.
5.1.1.9 Metering Requirements
Interchange Metering
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,junctionbox
and secondary metering wire.The primary metering transformers shall be combination
138 kV,500/5,RF =2,CT/VT extended range for high accuracy metering.
The metering design package will include two revenue quality meters,test switch,with
DNP real-time digital dataterminated at a metering interpositionblock.One meter will
be designated a primary SCADA meter and a second meter will be used designated as
Invenergy Wind Development LLC Page 9 February 8,2018
Uinta County,Q0715
Rocky Mountain Power
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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.
Station Service/Construction Power
Prior to construction,Interconnection Customer must arrange construction power with
the Transmission Provider.The metering shall conform to the Six State Electric Service
Requirements manual as the site is within the Transmission Provider's service territory.
For permanent station service load,bidirectionalmetering is required.Please note,prior
to back feed Interconnection Customer must arrange distribution voltage retail meter
service for electricity consumed by the Project and arrange backup station service for
power that will be drawn from the transmission or distribution line when the Project is
not generating.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.
5.1.2 Cost Estimate
O The followingestimate representsonly 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
Q0715 Tie Line Substation -Coordinate Relaying and Communications $364,000
Q0715 Naughton substation -Modify RAS $105,000
Q0715 POI Substation -Metering,Protection &Control and $1,414,000
Line Termination
Total Direct Assignment $1,883,000
Network Upgrades
Q0715 POI substation -Add 138 kV three-breaker ring bus $6,187,000
Railroad substation -Add line relays $62,000
Canyon Compression substation -Add line relays $93,000
Canyon Compression-Railroad Loop In/Out $515,000
Total Network Upgrade $6.,857.,000
O Invenergy Wind Development LLC Page 10 February 8,2018
Uinta County,Q0715
Rocky Mountain Power
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Total Cost $8.740.000
*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 Generator 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.
5.1.3 Schedule
The Transmission Provider estimates it will require approximately24 months to design,
procure and construct the facilities described in the Energy Resource sections of 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 appears
to result in a timeframe that does support the Interconnection Customer's requested
commercial operation date of October 1,2020.
5.1.4 Maximum Amount of Power that can be delivered into Network Load,with
No Transmission Modifications (for informational purposes only)
Zero (0)MW can be delivered on a firm basis to the Transmission Provider's network loads
without system improvements.
5.1.5 Additional Transmission Modifications Required to Deliver 100%of the
Power into Network Load (for informational purposes only)
In order to deliver 100%of the power into Network Load all improvements identified in
this report must be in service.
6.0 PARTICIPATIONBY AFFECTEDSYSTEMS
Transmission Provider has identified the followingaffected systems:None
7.0 APPENDICES
Appendix 1:Higher Priority Requests
Invenergy Wind Development LLC Page 11 February 8,2018
Uinta County,Q0715
Rocky Mountain Power
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Appendix 2:Property Requirements
Appendix 3:Study Results
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O Invenergy Wind Development LLC Page 12 February 8,2018
Uinta County,Q0715
Rocky Mountain Power
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7.1 Appendix 1:Higher Priority Requests
All active higher priority 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 Requestsconsidered:
Q0720*(TSR -Q2060)*This project has been designated a network resource.
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O Invenergy Wind Development LLC Page 13 February 8,2018
Uinta County,Q0715
Rocky Mountain Power
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7.2 Appendix 2:PropertyRequirements
PropertyRequirements 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 planningto 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.
O 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 operationallyacceptable
to Transmission Provider.The real property shall be a permitted or permittable 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 defmed 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
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System Impact Study Report
mitigation activities or monitoring activities;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.
O
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7.3 Appendix3:Study Results
A Western Electricity Coordinating Council (WECC)approved 2021-22 Heavy winter case was
used to perform the power flow studies using PSS/E version 33.7.Power flow studies were
performed on both peak and off-peak load cases.The off-peak load case was chosen to demonstrate
the stress on the higher kV transmission system under light load conditions.
The local 345 kV,230 kV,138 kV and 115 kV transmission system outages were considered
during the study.Some of the local area contingencies considered for this study are listed below.
(1)N-1:Outage of the Q0715 -Railroad 138 kV line
(2)N-1:Outage of Q0715 -Canyon Compression 138 kV line
(3)N-1:Outage of Canyon Compression -Muddy Creek 138 kV line
(4)N-l:Outage of the Long Hollow -Painter 138 kV line
(5)N-l:Outage of the Painter -Railroad 138 kV line
(6)N-1:Outage of the Railroad 230/138 kV auto transformer
(7)N-1:Outage of the Birch Creek -Ben Lomond 230 kV line
(8)N-l:Outage of the Ben Lomond -Naughton 230 kV line
(9)N-1:Outage of the Naughton -Birch Creek 230 kV line
(10)N-2:Outage of the Ben Lomond -Birch Creek 230 kV line &Ben Lomond -Naughton
230 kV line
O (11)N-2:Outage of the Ben Lomond -Syracuse 345 kV line &Populus -Terminal 345 kV
line
(12)N-2:Outage of the Ben Lomond -Terminal 345 kV #2 line &Ben Lomond -Syracuse
345 kV line
N-0 Results:No N-0 thermal or voltage issues were observed in the studies.
N-1 Results:No N-1 thermal or voltage issues were observed in the studies.
N-2 Results:The followingN-2 issue was observed in the studies.
The Evanston West path consists of three 230 kV lines:
Naughton-Treasureton
Naughton-Ben Lomond
Naughton-Birch Creek -Ben Lomond
For the N-2 outage of the Ben Lomond -Birch Creek 230 kV line and Ben Lomond -Naughton
230 kV line,and dependent on flow levels on the Evanston West path,an overload on the
remaining Naughton -Treasureton 230 kV line can occur.There is an existing remedial action
scheme (RAS),Naughton RAS,to drop generation for this N-2.The Q0715 Project must be
incorporated into the Naughton RAS as it will affect area flows.
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PACIFICORP ExhibLNo49PaA E9of35
Large Generator Interconnection
System Impact Study Report
Completed for
Invenergy Wind Development,LLC
("InterconnectionCustomer")
Q0810
Uinta II
Proposed Point of Interconnection
Q0715 Point of Interconnection Substation (on Canyon Compression -
Railroad 138 kV line)
February 8,2018
O
Rocky Mountain Power
PAciFI CORP ExhibitaNo49Pa 2EO
O System Impact Study Report
TABLE OF CONTENTS
1.0 DESCRIPTION OF THE GENERATING FACILITY ......................................................l
2.0 SCOPE OF THE STUDY...........................................................l
3.0 TYPE OF INTERCONNECTION SERVICE ....................................................1
4.0 DESCRIPTION OF PROPOSED INTERCONNECTION.....................................................l
5.0 STUDYASSUMPTIONS......................................................................................3
6.0 ENERGYRESOURCE(ER)INTERCONNECTIONSERVICE....................................................4
6.1.1 Requirements 4
6.1.2 Cost Estimate 9
6.1.3 Schedule 10
6.l.4 Maximum Amount of Power that can be delivered into Network Load,with No Transmission
Modifications (for informational purposes only)10
6.1.5 Additional Transmission Modifications Required to Deliver 100%of the Power into Network
Load (for informational purposes only)10
7.0 NETWORKRESOURCE(NR)INTERCONNECTIONSERVICE..............................................10
7.1.1 Requirements 10
7.1.2 Cost Estimate 10
7.1.3 Schedule 10
8.0 PARTICIPATIONBYAFFECTEDSYSTEMS.....................................................11
9.0 APPENDICES.......................................................................................11
9.1 Appendix 1:Higher Priority (Prior Queued)Requests ...................................................12
9.2 Appendix 2:Property Requirements.....................................................13
9.3 Appendix 3:Study Results......................................................15
O
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System Impact Study Report
1.0 DESCRIPTIONOF THE GENERATINGFACILITY
Invenergy Wind Development,LLC ("InterconnectionCustomer")proposed interconnecting 101
MW of new generation to PacifiCorp's ("Transmission Provider")Canyon Compression -
Railroad 138 kV line located in Uinta County,Wyoming.The Uinta project ("Project")will consist
of 44 GE 2.3 inverters for a total output of 101 MW.The requested commercial operation date is
July 1,2019.
Interconnection Customer will NOT operate this generator as a Qualified Facility as defined by
the Public UtilityRegulatory Policies Act of 1978 (PURPA).
The Transmission Provider has assigned the Project "Q0810."
2.0 SCOPE OF THE STUDY
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,any identified
network upgrades associated with such prior queued interconnections)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
O request;
(iii)have a pending prior 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.
This interconnection system impact study will consist of a short circuit analysis,a stability
analysis,and a power flow analysis.The 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 study will also 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-bindinggood faith estimated time to construct.
3.0 TYPE OF INTERCONNECTIONSERVICE
The Interconnection Customer has selected Network Resource (NR)Interconnection Service,but
has also elected to have the interconnection studied as an Energy Resource (ER).The
Interconnection Customer will select NR or ER prior to the facilities study.
4.0 DESCRIPTIONOF PROPOSED INTERCONNECTION
The Interconnection Customer's proposed Generating Facility is to be interconnected through the
Interconnection Customer Interconnection Facilities to be constructed for the Q0715 project.
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Figure 1 below,is a one-line diagram that illustrates the interconnection of the proposed
Generating Facility to the Transmission Provider's system.
Whitney
Canyon Inlet
i Canyon Compression
0.3 miles
Q0715 POI
Substation
Point of
/Interconnection
\Q0810
/Project Sub
34.5 kV
138 kV 68/90/112 MVA -eO138-34.5 kV
Z =9 %
Tie-Line Substation
(Customer-owned)
34.5 kV6Miles
Change of 84/112/140 MVA
138-34.5 kVOwnershipZ=9 %
Q0715
Project Sub &
Railroad
Figure 1:SimplifiedSystem One Line Diagram -Point ofInterconnection
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5.0 STUDYASSUMPTIONS
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
materially modified or 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 will be modeled in
this study.
o Generation Interconnection Queue:Interconnection Facilities associated with prior
queued 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.The
provision of transmission service may require additional studies and the construction of
additional upgrades.
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 underbuildrequired 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.
The Q0715 project must be complete before or simultaneously with this Project.
The Jordanelle -Midway 138 kV line is assumed to be in service (2019).
The Energy Gateway West,Aeolus-Bridger/Anticline sub-segment D.2,is assumed to be
in-service by year end 2020.
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
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6.0 ENERGY RESOURCE (ER)INTERCONNECTIONSERVICE
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
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
O reactive power to the system)immediately followingthe 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 followinga 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 Grid Operator 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-la,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,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 isOInvenergyWindDevelopmentPage4February8,2018
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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/coordinationstudies 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 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 Generator
Facility's step-up transformers measured on the low side of the GSU at a sample rate of at least 30
samples per second and synchronized within +/-2 milliseconds of the Coordinated UniversalTime
(UTC).Initially,the followingdata must be collected:
Three phase voltage and voltage angle (analog)
Three phase current (analog)
O Data requirements are subject to change as deemed necessary to comply with local and federal
regulations.
All generators must meet the Federal Energy Regulatory Committee (FERC)and WECC low
voltage ride-through requirements as specified in the interconnection agreement.
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
Q0810 is responsible to eliminate the credible N-2 outage of the Transmission Provider's Ben
Lomond-Birch Creek and Ben Lomond-Naughton 230 kV transmission lines,which share
common structures for approximatelyeight miles as they exit Ben Lomond substation.This will
require construction of a new approximatelyseven-mile 230 kV line (2-795 ACSR)in a separate
right of way,in order for both 230 kV circuits to be on separate structures.
6.1.1.3 Transmission/DistributionLine Modifications
Construct a 230 kV single circuit transmission line beginning approximatelyone mile outside of
Ben Lomond substation to structure 525 for the Ben Lomond-Naughton #1 line.
This line segment will replace the current Ben Lomond-Naughton #1 circuit which resides on the
north side of the 7 mile long lattice tower double circuit with the Ben Lomond-Birch Creek 230
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kV transmission line.This new line will require the procurement of additionalrights-of-ways
which the Interconnection Customer will be responsible to obtain on behalfof the Transmission
Provider.The corridor near Ben Lomond substation where the new transmission line must be
constructed is congested.The Transmission Provider anticipates that the procurement of the
necessary rights-of-way could be difficult and may add significant cost and potential delays to
the Project.
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 Generating Facility
with 44 -GE 2.3 MW wind turbine generators fed through 44 -2.5 MVA 34.5 kV -690 V
transformers with 5.75%impedance then fed through one 138 -34.5kV 68/90/112 MVA step-up
transformer with 9%impedance will not push the fault duty above the interrupting rating of any
of the Transmission Provider's existing fault interruptingequipment.
6.1.1.5 Protection Requirements
The Interconnection Customer's line relays at the collector substation will need to respond to the
combination of the 138 kV fault current being contributed from both the Q0715 and the Q0810
generation projects for faults on the 138 kV tie line and trip both 138 kV breakers for the two
projects.
As this Project will be interconnected through the same facilities planned to be constructed for
the Q0715 project it will be included in the bus differential relay system that will trip the 138 kV
breaker in the tie line substation to be installed as part of the Q0715 project.
The relay to be installed at the Q0715 POI substation as part of the Q0715 project will monitor
the voltage magnitude and frequency of the Q0810 Project.If the magnitude or frequency of the
voltage is outside of normal range of operation a signal will be sent to trip the tie line 138 kV
breakers.
New line relay settings will be developed for the Naughton -Ben Lomond and Birch Creek -
Ben Lomond 230 kV lines due to the rebuilding of the seven mile section of those lines.
6.1.1.6 Data (RTU)Requirements
Data for the operation of the power system will be needed from the Interconnection Customer's
collector substation.Listed is the data that will be acquired from the collector substations.
From the Q0715 collector substation:
Analoes:
Net Generation MW
Net Generator MVAR
Interchange metering kWH
From the Q0810 collector substation:
Analogs:
Net Generation MW
Net Generator MVAR
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O System Impact Study Report
Interchange metering kWH
34.5 kV Real power F1
34.5 kV Reactive power Fl
34.5 kV Real power F2
34.5 kV Reactive power F2
34.5 kV Real power F3
34.5 kV Reactive power F3
34.5 kV Real power F4
34.5 kV Reactive power F4
34.5 kV Real power F5
34.5 kV Reactive power F5
Average Wind Speed
AveragePlant Atmospheric Pressure (Bar)
Average Plant Temperature (Celsius)
Status:
138 kV line breaker
34.5 kV breaker F1
34.5 kV breaker F2
34.5 kV breaker F3
34.5 kV breaker F4
34.5 kV breaker F5
6.1.1.7 Substation Requirements
Q810 Collector Station
The following major equipment has been identified as being required and may change during
detailed design:
3 -138 kV CT/VT combination metering units
1 -Control house
The Interconnection Customer will providea separategraded,grounded and fenced area along the
perimeter of the Interconnection Customer's Generating Facility for the Transmission Provider to
install a control house for metering equipment.This area will share a fence and ground grid with
the Generating Facility and have separate,unencumbered access for the Transmission Provider.
DC power for the control house will be supplied by the Transmission Provider.AC station service
for the control house will be provided by the Interconnection Customer.
9715 Collector Station
The following major equipment has been identified as being required and may change during
detailed design:
3 -138 kV CT/VT combination metering units
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6.1.1.8 Communication Requirements
The Transmission Provider will need to make minor modifications at its primary and secondary
control centers to account for the additional generation of this phase in addition to the Q0715
project.
6.1.1.9 Metering Requirements
Interchange Metering -00715 POI substation:
The Q0715 generation metering to be located at the Q0715 POI substation will be reassigned as
an interconnection customer intertie with the Transmission provider for the combined Q0715 and
Q0810 generation projects
90715 and 90810 collector substations:
The generation and backfeed metering for both Q0715 and Q0810 projects will be located at the
Interconnection Customers'respective collector substations.The generation metering will be
located at the 138 kV high side of the Interconnection Customer's transformers and will be loss
adjusted to the Transmission Provider's Q0715 POI substation.
The Transmission Provider will specify and order all interconnection revenue metering
equipment,including the 138 kV instrument transformers,metering panels,junctionboxes,and
secondary metering wire.The current transformers shall be extended range for high accuracy
metering with current ratio of 500/5 (0.15%extended range accuracy).The voltage transformers
will have a voltage ratio of 700/1 (0.3%accuracy).
The metering design package will include four revenue quality meters and supporting hardware.
The meters will output DNP real-time digital data terminated at a metering interpositionblock.
The metering design package will include all SCADA metering data terminated at a metering
interposition block.The metering data will include bidirectional KWH and KVARH revenue
quantities.The metering data will also include PF,MW,MVAR,MVA,per phase voltages,and
per phase amps.The interconnection customer may request data outputs from the meters,but the
request must be made prior to final design.
An Ethernet phone line is required for retail sales and generation accounting via the MV-90
meter data management system.
Station Service/Construction Power
Prior to construction,Interconnection Customer must arrange construction power with the
Transmission Provider.The metering shall conform to the Six State Electric Service
Requirements manual as the site 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 and arrange back-up station service for
power that will be drawn from the transmission or distribution line when the Project is not
generating.
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Interconnection Customer must call the PCCC Solution Center at 1-800-625-6078 to arrange this
service.Approval for back feed is contingent upon obtaining station service
6.1.2 Cost Estimate
The followingestimate representsonly 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
Q0810 Collector Substation $413,000
Metering and Control House
Q0715 Collector Substation $413,000
Metering and Control House
Q0715 Point of Interconnection Substation $30,000
Relay and Communication Modifications
Transmission Provider Control Centers $13,000
Communication Modifications
Total Direct Assigned $869,000
O Network Upgrades
Ben Lomond-Naughton#1 Transmission Line $25,785,000
Removefrom existingdouble circuit and construct new 7 mile line
Grand Total $26,654,000
*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 Generator 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.
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6.1.3 Schedule
The Transmission Provider estimates it will require approximately24-30 months to permit,design,
procure and construct the facilities described in the Energy Resource sections of this report
followingthe execution of an Interconnection Agreement.The schedule will be further developed
and optimized duringthe Facilities Study.
Please note,the time required to perform the scope of work identified in this report appears to
result in a timeframe that does not support the Interconnection Customer's requested Commercial
Operation date of July 1,2019.
6.1.4 Maximum Amount of Power that can be delivered into Network Load,with No
Transmission Modifications (for informational purposes only)
One hundred one (101)MW can be delivered on a firm basis to the Transmission Provider's
network loads assuming all requirements outlined in this report are complete and all
requirements of Q0786 are complete.
6.1.5 Additional Transmission Modifications Required to Deliver 100%of the Power into
Network Load (for informational purposes only)
See section 6.1.1.2.
7.0 NETWORK RESOURCE (NR)INTERCONNECTIONSERVICE
Network Resource Interconnection Service allows the Interconnection Customer to integrate itsOGeneratingFacilitywiththeTransmissionProvider's Transmission System in a manner
comparable to that in which the Transmission Provider integrates its generating facilities to serve
native load customers.The transmission system is studied under a variety of severely stressed
conditions in order to determine the transmission modifications which are necessary in order to
deliver the aggregate generation in the area of the Point of Interconnection to the Transmission
Provider's aggregate load.Network Resource Interconnection Service in and of itself does not
convey transmission service.
7.1.1 Requirements
7.1.1.1 Generating Facility Modifications
See Section 6.1.1.1
7.1.1.2 Transmission System Modifications
See Section 6.1.1.2
7.1.2 Cost Estimate
No additional costs are anticipated other than those listed in section 6.1.2.
7.1.3 Schedule
See section 6.1.3.
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8.0 PARTICIPATIONBY AFFECTEDSYSTEMS
Transmission Provider has identified the followingaffected systems:None.
9.0 APPENDICES
Appendix 1:Higher Priority (Prior Queued)Requests
Appendix 2:Property Requirements
Appendix 3:Study Results
O
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9.1 Appendix 1:HigherPriority (Prior Queued)Requests
All active higher priority transmission service and/or generator interconnection requests will be
considered in this study and are identified below.If any of these requests are materially modified
or 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:
Q0715 (120 MW)
Q0720 (80 MW)-QF
Q0786 (100 MW)-ER/NR
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9.2 Appendix2:Property Requirements
PropertyRequirements 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
O 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 operationallyacceptable
to Transmission Provider.The real property shall be a permitted or permittable 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 defmed 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.AOInvenergyWindDevelopmentPage13February8,2018
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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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9.3 Appendix 3:Study Results
Power Flow Study Results
A Western Electricity CoordinatingCouncil (WECC)approved 2021-22 Heavy winter and 2022
Heavy summer cases were used to perform the power flow studies using PSS/E version 33.7.
Power flow studies were performed on both peak and off-peak load cases.The off-peak load case
was chosen to demonstrate the stress on the higher kV transmission system under light load
conditions.The Rock Springs/Firehole West path was stressed to 640 MW.The local 230 kV and
138 kV transmission system outages were considered during the study.
N-0 Results:No N-0 thermal or voltage issues were observed in the studies.
N-1 Results:Assuming the 2.35 miles of the Railroad -Croydon 138 kV line is rebuilt and the
jumpers at Canyon Creek and Carter Creek are upgraded by the prior Q0786 project,no additional
issues were observed.
N-2 Results:
The credible N-2 of the Ben Lomond -Birch Creek and Ben Lomond -Naughton 230 kV lines
can overload the Naughton -Treasureton 230 kV line and/or the Railroad -Croydon -Coalville
-Silver Creek -Synderville-Cottonwood 138 kV lines.The Ben Lomond -Birch Creek and
Ben Lomond -Naughton 230 kV circuits share common structures for approximatelyeight miles.
O The project cannot be integrated into the Naughton Remedial Action Scheme (RAS)as it exceeds
the maximum amount of generation tripping (600-700 MW)to be dropped as a part of RAS.
Therefore,elimination of the specific 230 kV N-2 is required.As there is a double circuit 138 line
that runs parallel to the 230 kV double circuit in the area,one of the 230 kV circuits can be
swapped with one of the 138 kV circuits,reducing the impact of this outage.Approximately seven
miles of structures on the 138 kV segment would need to be replaced to accommodate the weight
of the 230 kV circuit.
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