20180307PAC to Staff UT Q542SIS.pdf

PAciFICORP
Large Generator Interconnection
System Impact Study Report
Completed for
LGIQ#Q0542
Proposed Interconnection
To the Existing
230 kV Frannie -Yellowtail
Transmission Line
August 19,2014
PACIFICORP
System Impact Study Report
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 DESCRIPTION OF PROPOSED INTERCONNECTION................................................2
4.1 Other Options Considered (NERC Requirement)................................................2
5.0 STUDY ASSUMPTIONS..................................................................2
5.1 Energy Resource (ER)Interconnection Service.................................................5
5.1.1 Study Results 5
5.1.2 Requirements 10
5.1.1 Cost Estimate 18
5.1.2 Schedule 19
5.1.3 Maximum Amount of Power that can be deliveredinto NetworkLoad,with No Transmission
Modifications(for informationalpurposes only).19
5.1.4 Additional Transmission ModificationsRequired to Deliver 100%of the Power into Network
Load (for informationalpurposes only)20
5.2 NetworkResource (NR)Interconnection Service...............................................21
5.2.1 Study Results 21
5.2.2 NetworkResource Requirements 23
5.2.3 NetworkResource Cost Estimate 27
5.2.4 Schedule 28
6.0 PARTICIPATION BY AFFECTED SYSTEMS...............................................28
7.0 APPENDIX 1:PROPERTY REQUIREMENTS................................................29
8.0 APPENDIX 2:COMBINED QUEUE...............................................31
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1.0 DESCRIPTION OF THE GENERATING FACILITY
("Interconnection Customer")proposed interconnecting 240 MWs of new generation to
PacifiCorp's ("Transmission Provider")Frannie -Yellowtail 230 kV transmission line
approximately 2.75 miles north of the Frannie substation located in Park County,Montana.The
project ("Project")will consist of 120 Gamesa 2.0 Gll4 wind turbine generators for a total
output of 240 MWs.The requested commercial operation date is approximately December 1,
2015.
Interconnection Customer will NOT operate this generator as a Qualified Facility as defined by
the Public Utility Regulatory Policies Act of 1978 (PURPA).
The Transmission Provider has assigned the project "Q0542."
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,
an identified network upgrades associated with such higher queued interconnection)that,on the
date the interconnection system impact study is commenced:
(i)are directlyinterconnected 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,
includingpreliminaryindication 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 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 DESCRIPTION OF PROPOSED INTERCONNECTION
To interconnect the Q0542 Project to the 230 kV Frannie -Yellowtail transmission line will
require the construction of a new 230 kV three breaker ring bus switching substation including
control house and the installation of metering,protection and control and communications
equipment.Transmission system upgrades will also be required at Frannie substation,Yellowtail
substation,Cedar Mountain substation,Oregon Basin substation,McCulloughPeak microwave
station,Cody Service Center,Casper Service Center,Portland Control Center and Salt Lake
Control Center.
4.1 Other Options Considered (NERC Requirement)
The Interconnection Customer could have chosen to interconnect directly to the Frannie
substation but,chose to have the Q0542 Project tap the existing 230 kV Frannie -Yellowtail
transmission line approximately 2.75 miles North of the Frannie substation.
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
withdrawn,the Transmission Provider reserves the right to re-evaluate this request,and
the results and conclusions could significantlychange.
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 and are expected to
be in-service on or after the Interconnection Customer's requested in-service date
for the Project will be modeled in this study.
o Generation Interconnection Queue:when relevant,interconnection facilities
associated with higher queue interconnection requests will be modeled in this
study.However,no generation will be simulated from any higher queued project
unless a commitment has been made to obtain transmission service.
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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
can make a request to designate a generating resource as a network resource.Since the
queue of higher priority transmission services requests may be different when and if a
Network Customer's requests network resource designation for this generation 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 generation 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).However,a network customer can
elect to designate more generating resources in an area than can be accommodated by
existing or planned transmission capacity.The network customer would then be required
to dispatch the resources so as to limit total generation so as not to exceed the network
customer's transmission rights.
This study assumes the project will be integrated into the Transmission Provider's system
to the existing Frannie -Yellowtail 230kV line at or near a point approximately 2.75
miles north of Frannie substation located in Park County,Wyoming.
This study assumes that the Railroad -Silver Creek 138kV line planned for December
2015 is in-service.
This study assumes that Q0542 is in-service in summer 2016.The 2016 heavy and light
load conditions are applied to this study.
PacifiCorp standards require post contingency voltage limits of 0.9 per unit and 1.1 per
unit.
The Interconnection Customer will construct and own any facilities required between
the Point of Change of Ownership and the project.
Generatortripping may be required for certain outages.
All facilities will meet or exceed the minimum WECC,NERC,and the Transmission
Provider's performance and design standards.
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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
regularlyfor transmission system updates at http://www.pacificorp.com/tran.html
If wind turbines are connected electricallynear series capacitors,then specialized studies
to consider SSR (Sub-Synchronous Resonance)and Sub-Synchronous Control
Interactions (SSCI)may be required.If N-1 or N-2 contingencies result in a radial path
of the turbines into the series capacitors,then studies are essential -for other non-radial
configurations,the studies are necessary at the discretion of the Transmission
Provider.Such studies must demonstrate that the wind turbine controls do not contribute
negative damping to the system,and that the mechanical modes of resonance in the
turbine do not interact with system series capacitors.If such interactions occur,it is the
responsibility of the wind developer to provide remedies,and to provide adequate
protection to ensure the sub-synchronous interactions are detected and the wind turbines
tripped.
The Latham/Platte 230kV line upgrades from a DUTT relaying scheme to a POTT
relaying scheme using mirrored bits,associated with the TOT4 project,have been
completed.
The 230kV bus configuration modifications at Latham substation associated with the
TOT4A project have been completed.
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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.
Consistent with the Transmission Provider's Open Access Transmission Tariff,the facility will
be studied such that deliverability will be determined to the Transmission Provider's aggregate
network loads assuming some portion of existing network resources are displaced by the output
of the Interconnection Customer's large generating facility.Energy resource interconnection
service in and of itself does not convey transmission service.
5.1.1 Study Results
The PSS/E version 33.5 program was used to evaluate the steady state performance of the system
for contingencies described in Table 1.The 2014 Heavy Summer WECC case was modified for
the study.The study area was limited to the Big Horn area in Wyoming since the Point of
Interconnection (POI)is located on the Frannie -Yellowtail 230 kV line.
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BIG HORN AREA
TRANSMISSION SYSTEM
2012-2016
SE
AREA PLANNING ENGINEERING
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The case was tuned to meet the maximum path flow on the Yellowtail South path.The
Yellowtail South path is jointly owned between PacifiCorp (PAC)and Western Area Power
Administration (WAPA).The path limit is 625 MW,with ownership split 400 MW for
PacifiCorp (230 kV lines)and 225 MW for WAPA (115 kV lines).The Yellowtail South path
consists of the followinglines:
Yellowtail (PAC)-Frannie 230 kV (owned by PAC)*
Yellowtail (PAC)-Sheridan 230 kV (owned by PAC)
Yellowtail (WAPA)-Lovell 115 kV #1 line (owned by WAPA)
Yellowtail (WAPA)-Lovell 115 kV #2 line (owned by WAPA)
*Post Q0542,the metering point for the Yellowtail -Frannie 230 kV line would move from
Yellowtail to the new Q0542 Point of Interconnection so that the power flow from this Project is
captured in the path flow.
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Table 1
N-1 Outages
PAC owned facilities
#Contingency
1 Yellowtail (PAC)-Point of Interconnection 230kV line
2 Point of Interconnection -Frannie -Garland -Oregon Basin 230kV line
3 Oregon Basin -Grass Creek -Thermopolis (PAC)230kV line
4 Thermopolis (PAC)-Riverton 230kV line
5 Riverton -Casper230kV line
6 Yellowtail (PAC)-Sheridan230kV line
7 Sheridan-Buffalo 230kV line
8 Buffalo -Kaycee -Midwest -Claim Jumper 230kV line
9 Buffalo -Carr Draw 230kV line
10 Carr Draw -Casper 230kV line
11 Yellowtail (PAC)-Rim Rock 161kV line
12 Thermopolis (PAC)-Kirby Creek -Hilltop 115kV line
13 Thermopolis (PAC)-Thermopolis (WAPA)ll5kV #1 line
14 Thermopolis (PAC)-Thermopolis (WAPA)ll5kV #2 line
15 Riverton 230/ll5kV transformer
16 Thermopolis 230/161kV transformer
17 Thermopolis 230/ll5kV #2 transformer
WAPA owned facilities
#Contingency
1 Yellowtail (PAC)-Yellowtail (WAPA)230kV line
2 Yellowtail (WAPA)-Crossover 230kV line
2 Thermopolis (PAC)-Bad Water 230kV line
3 Bad Water -Buffalo Head -Spence 230kV line
4 Spence -Casper 230kV line
5 Lovell -Nahne Jensen -Basin -Worland -Hilltop &Thermopolis (WAPA)115kV line
6 Lovell -Big George -Meeteesee -Carter Mountain -Thermopolis (WAPA)115kV line
7 Yellowtail 60MW hydro generator#1
8 Yellowtail 60MW hydro generator#2
9 Yellowtail 60MW hydro generator#3
10 Yellowtail 60MW hydro generator#4
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NorthWestern Energy owned facilities
#Contingency
1 Yellowtail (PAC)-Billings 230kV line
Tri-State owned facilities
#Contingency
1 Thermopolis 230/ll5kV #1 transformer
Customer owned facilities
#Contingency
1 Point of Interconnection -Collection Site 230kV line
2 New 240MW wind generator
Table 1:List of Contingencies
Prior to adding Q0542,no thermal overload and voltage issues are observed under N-0
conditions.After adding Q0542,no thermal overload and voltage issues are observed under N-0
conditions.
There are known system conditions followingcontingencies that exist prior to the addition of the
Q0542 project which are provided here for documentation purposes.The following
contingencies cause the overload on Worland Tap -Basin -Nahne Jensen 115kV WAPA line:
N-1 outage of the Yellowtail (PAC)-Yellowtail (WAPA)230kV line,or
N-1 outage of Yellowtail -Frannie -Garland -Oregon Basin 230kV line.
To mitigate this issue,tripping the section of Worland Tap -Basin 115kV line or Basin -Nahne
Jensen 115kV line is required.WAPA indicates that within five years there are plans to
reconductor the Worland Tap -Basin -Nahne Jensen 115kV line with 477ACSS (Aluminum
Conductor Steel Supported)which has a limit of 800 amps (159 MVA).The tripping scheme will
no longer be required if this new reconductor project is completed.
The followingcontingency causes low voltage issues in WAPA 115kV system:
N-1 outage of the Yellowtail (PAC)-Yellowtail (WAPA)230kV line
Tripping the Meeteesee Tap -Big George l15kV WAPA line alleviates this low voltage issue.
No new voltage violations or thermal overloads are identified in the study for N-1 contingencies
with Q0542 in-service other than the existing issues identified.However,coordination with
WAPA is still required to operate the new generation facility properly under certain N-1
conditions described above or for other outage conditions that may occur from time to time.
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5.1.2 Requirements
5.1.2.1 GeneratingFacility Modifications
The Generation and Interconnection facilities owned by the Interconnection Customer are
required to operate under automatic voltage control with the voltage sensed electrically at the
Point of Interconnection.The generating and interconnecting facility should have sufficient
reactive capacity to enable the delivery of 100 percent of the plant output to the Point of
Interconnection at unity power factor measured at 1.0 per unit voltage under steady state
conditions.
Generators capable of operating under voltage control with a voltage droop are required to do so.
Studies will be required to coordinate the voltage droop setting with other facilities in the area.
As required by NERC standard VAR-001-la,the Transmission Provider will provide a voltage
schedule for the Point of Interconnection.When voltage droop controls are not available,the
generation and interconnection facilities should be operated so as to maintain the voltage at the
Point of Interconnection between 1.01 pu to 1.04 pu.At the Transmission Provider's discretion,
these values might be adjusted depending on the operating conditions.Within this voltage range,
the generating and interconnecting facilities should operate so as to minimize the reactive
interchange between the generation/interconnection facilities and the Transmission Provider's
system (operation fixed at unity power factor at the Point of Interconnection).If the voltage is
outside the upper or lower range,the voltage control scheme should operate so as to utilize the
reactive capabilities of the generating and interconnecting facilities to maintain the voltage to a
value within the control band.The voltage control settings of the generation and interconnection
facilities must be coordinated with the Transmission Provider prior to energization (or
interconnection).The reactive compensation must be designed such that the reactive switching(if required by the Interconnection Customer)does not cause step voltage changes greater than
+/-3%on the Transmission Provider's system.
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 prior to
interconnection.The list of approved generator models is continuallyupdated and is available
on the http://www.WECC.bizwebsite.
The Transmission Provider was unable to obtain a working generator model from the
Interconnection Customer.
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5.1.2.2 Transmission Modifications
The Point of Interconnection substation is to be looped in to the Frannie -Yellowtail 230kV
Transmission line approximately 2.75 miles north of the Frannie substation located in Park
County,Wyoming.This new switching substation will split the line into two new sections:
Q0542-Yellowtailon the northern end and Frannie -Q0542 on the southern end.
The Q0542 Point of Interconnection substation will be located one span away from the existing
transmission line between structures 8/123 and 1/124.A loop in of the Point of Interconnection
substation off the transmission line toward Frannie will require removing H-frame structures
8/123 and 1/124 and replacing them with two new 3-pole TI451 structures and 2 new 3-pole
TI452 structures.All structures will be guyed wood poles.
Frannie Yellowtail .
~2.75 mi.,i
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Collector Circuits
34.5 kV
Q0542
Substation i -
230-34.5 kV
156/208/260 MVA
8.0%Z @ 156 MVA
9.51 Miles
Change of
ownership
-Q0542 POI
Substation
Point of
Interconnection
230 kV
2 75 Miles
Frannie
Substation
Garland
Substation
Oregon Basin
Substation
Figure 1:System One Line Diagram
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5.1.2.3 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 120 -2.35 MVA generators fed through 1 -156/208/260 MVA step up transformer
with 8%impedance will not push the fault duty above the interruptingrate of any of the existing
fault interruptingequipment.
5.1.2.4 Protection Requirements
As indicated in the one line diagram shown in Figure 1,the proposed Point of Interconnection
2.75 miles north of Frannie substation in the Yellowtail -Oregon Basin 230 kV line will require
the construction of a new Point of Interconnection substation with three 230 kV breakers.There
will be a 9.51 mile line from the Point of Interconnection substation to the Generation
Interconnection Customer's collector substation.The line between Yellowtail and Oregon Basin
substations is protection with line relays using power line carrier for communication.Since in
this part of the Transmission Provider's service territory the communication options are limited
we will plan to continue to use the power line carrier for the line relay communication media
between the Point of Interconnection substation and Yellowtail substation,and between the Point
of Interconnection substation and Oregon Basin substation.In each case we will continue to use
one set of frequency shift transmitters and receivers using direct underreaching transfer trip line
logic schemes.The line relays at Yellowtail and Oregon Basin have been replaced in recent
years and with the development of new settings these relays will function with the relays that are
planned for the Point of Interconnection substation.For the line between the Point of
Interconnection substation and the collector substation a line current differential system will be
used.The Transmission Provider will design and built a panel containing the line relays that will
be compatible with the units being installed at the Point of Interconnection substation.The two
line relay set will communication over an optical fiber cable that will need to be installed in
conjunctionwith the 9.51 mile 230 kV tie line.
At the Point of Interconnection substation a relay will be installed that will monitor the voltage
magnitude and frequency.If the voltage,magnitude or frequency,is outside of the normal
operation range this relay will send a trip signal to cause the Interconnection Customer's 34.5 kV
line breakers at the collector substation to open.
5.1.2.5 Data (RTU)Requirements
The installation of a RTU is required at the Transmission Provider's Point of Interconnection
substation.Additional data for the operation of the power system will be needed from
Interconnection Customer's collector substation.RTU units will be installed at both locations to
acquire the operational data and send the data back to the Transmission Provider's operational
center.In addition to the control and indication of the 230 kV breakers in the Point of
Interconnection substation the followingdata from the Point of Interconnection substation and
the Interconnection Customer's collector substation will be monitored:
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From the Point of Interconnection substation:
Analogs:
Net generation MW
Net generation MVAr
Energy register values
230 kV A phase voltage
230 kV B phase voltage
230 kV C phase voltage
From the Interconnection Customer's collector substation:
Analogs:
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
Real power flow 34.5 kV line #11
Reactive power flow 34.5 kV line #11
Real power flow 34.5 kV line #12
Reactive power flow 34.5 kV line #12
Reactive power flow 34.5 kV from reactive device
Total Wind Farm Generation (MW)
Average Wind Farm Wind Speed (m/s)
Average Wind Farm Atmospheric Pressure (Bar)
Average Wind Farm Temperature (Celsius)
Wind Direction
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Status:
230 kV transformer breaker
34.5 kV transformer 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
34.5 kV Line #11 breaker
34.5 kV Line #12 breaker
34.5 kV Reactive Device breaker
5.1.2.6 Substation Requirements
Oregon Basin substation
No major substation modifications are required at Oregon Basin substation.
Yellowtail substation
No major substation modifications are required at Yellowtail substation.
Q0542 Point of Interconnection substation
The Point of Interconnection substation will be built as a three breaker ring bus with all
necessary equipment such as:circuit breakers,CCVT's,lightning arresters,an SSVT,and group
operated switches.Bus,bus support structures,and dead end towers will be installed as well as
conduit,cable trench,and yard lights.The substation will be fenced and a ground grid installed.
A control house will be installed to enclose all of the relay and communication equipment.
Q0542 Customer substation
Relay panels and a separate battery system will need to be installed in the Customer substation.
This equipment will need to be installed in a separate lockable room within the Customer's
control house,or a separate control building will need to be installed.With either option,only
Transmission Provider personnel will have access to that area.Since PacifiCorp personnel will
require access into the Customer substation,a Current Distribution,Electromagnetic Fields,
Grounding and Soil Structure Analysis CDEGS analysis will be required to verify the grounding
design safe step and touch potentials.
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5.1.2.7 Communication Requirements
Communication requirements to physicallyconnect the Q0542 project will consist of:
Install fiber on the existing 2.75 miles line between Frannie substation and Point of
Interconnection substation.
The Interconnection Customer will be required to install fiber on the new 9.51 mile line
between the Point of Interconnection substation and the Q0542 collector substation.
Upgrade the MAS radio between Frannie substation and McCullough Peak microwave
station.
Install a new microwave tower at Frannie substation.
Upgrade the Fractional Tl radios from McCulloughPeak to Cedar Mountain microwave
stations and Cody Service Center with larger Microwave.
Install leased Tl line at Cody Service Center and interface with the microwave.
Install multiplex,communication batteries and chargers at all the locations requiring
upgrades.
Install Fiber DMX nodes at Frannie,the Q0542 Point of Interconnection substation and
the Q0542 collector substations.
Install new RTUs at Point of Interconnection substation and the Q0542 collector
substation.
Install substation network at all sites.
Power line carrier will be required on the 230 kV transmission line from Point of
Interconnection substation to the Yellowtail substation and on the 230 kV transmission
line from the Point of Interconnection substation to the Oregon Basin substation.
Mirrored bit relaying will be used on the Q0542 Point of Interconnection to Q0542
collector substation line.
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).
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5.1.2.8 Metering Requirements
InterchangeMetering
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 includinginstantaneous PF,MW,MVAR includingper phase
voltage and amps data.
An Ethernet connection is required for retail sales and generation accounting via the MV-90
translation system.
The Transmission Provider recommends the Interconnection Customer install meter by-pass
switches to reduce operational disruption.If the Interconnection Customer elects not to install
metering bypass switches,the Interconnection Customer's generator will need to be taken off
line for metering testing,repair and service.
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5.1.1 Cost Estimate
Q0542 Collector substation -Engineering,procurement and installation $300,000
of protection and control and communications equipment.
Q0542 Point of Interconnection substation -Engineering,procurement $425,000
and construction of a substation take-off structure and associated
installation of the Interconnection Customer's last span of conductor.
Q0542 Point of Interconnection substation -Engineering,procurement $250,000
and installation of metering and communications equipment.
Q0542 Point of Interconnection substation to Frannie substation -$390,000
Engineering,procurement and installation of approximately 2.75 miles of
fiber optic cable.
Sub-total Direct AssignmentCosts $1,365,000
Interconnection -Network Upgrade Costs
Q0542 Point of Interconnection substation -Engineering,procurement $9,000,000
and construction of the 230 kV three breaker ring bus point of
interconnection switching substation.
230 kV Frannie -Yellowtail transmission line -Engineering,$330,000
procurement and construction to loop in/out the 230 kV Frannie -
Yellowtail transmission line.
Frannie substation -Engineering,procurement and installation of $305,000
communication upgrades includingMAS radio and microwave upgrades.
McCullough Peak microwave station -Engineering,procurement and $365,000
installation of communication and protection and control upgrades
includingupgrading the MAS and Fractional Tl radio equipment.
Cedar Mountain substation -Engineering,procurement and installation $305,000
of communication upgrades includingupgrading the Fractional Tl radio
equipment.
Cody Service Center -Engineering,procurement and installation of $320,000
communication upgrades including upgrading the Fractional Tl radio
equipment,installinga Tl line and updating the microwave interface.
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Yellowtail substation -Engineering,procurement and installation of $90,000
protection and control upgrades.
Oregon Basin substation -Engineering,procurement and installation of $95,000
protection and control upgrades.
Casper Service Center,Portland Control Center and Salt Lake Control $45,000
Center -Engineering,procurement and installation of communication
upgrades.
Sub-total Network Upgrade Costs $10,855,000
Total Cost -ER Interconnection Service -Interconnection Only $12,220,000
5.1.2 Schedule
At this time,it is estimated that the upgrades required to place this project in service could be
completed within 24 months of a signed interconnection agreement.Further details regarding
the schedule will be available through the Facilities Study when a more detailed estimate has
been prepared.The two items will be necessary before any construction starts:
1.Obtain the necessary permits and rights of way to construct the facilities necessary to
interconnect the Q0542 project (Interconnection Customer's responsibility)
2.Execute a Large Generation Interconnection Agreement.
Please note the time required to execute the scope of work coupled with the anticipated date the
Interconnection Agreement will be signed,results in a timeframe that does not support the
Interconnection Customer's requested in-service date of December 1,2015.
5.1.3 Maximum Amount of Power that can be delivered into Network Load,with No
Transmission Modifications (for informational purposes only).
Zero megawatts can be delivered to network load with no transmission modifications.
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5.1.4 Additional Transmission Modifications Required to Deliver 100%of the Power into
Network Load (for informational purposes only)
In order to deliver 100%of the Project output to network load,all of the improvements identified
in the Energy Resource Section of this report would be required,as well as the following
improvements (see Figures 2 and 3):
A new 150-mile 230 kV line from Shirley Basin substation to the Bitter Creek substation
with connections to the Standpipe and Latham substations.The line termination at Point
of Rocks to Bridger will be removed as the line will be extended and terminate at the
Bitter Creek substation,creating the Bridger -Bitter Creek line which is part of the 150
mile line mentioned above.
The line from Bridger to Point of Rocks will be removed and extended to terminate at
Bitter Creek
Addition of a new bay at Shirley Basin substation with one 230kV circuit breaker to add
the new line termination.The substation will still operate as a ring bus.
A new cross bay at Standpipe substation with three new 230 kV circuit breakers and two
new line terminations
Expansion of the Latham substation with new cross bays,two new 230 kV circuit
breakers and two new line terminations
A new four-breaker ring bus substation,adjacent to the existing Bitter Creek substation
and construction of four line terminations.
Accelerate the reconfiguration of the Bridger substation (see Figure 3)
A new 50-mile 230 kV line from White Horse to Jonah Gas new substations
A new 230 kV three-breakersubstation at White Horse
A new 230 kV three-breakersubstation at Jonah Gas
Two (2)new 230 kV phase shifting transformers at Craven Creek substation
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5.2 Network Resource (NR)Interconnection Service
Network Resource interconnection service allows the Interconnection Customer to integrate its
large generating facility with the Transmission Provider'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.If any,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,and assumes that some portion of existing network
resources are displaced by the output of the Interconnection Customer's large generating facility.
Network resource interconnection service in and of itself does not convey transmission service.
5.2.1 Study Results
Wyoming has more generation than load,and as such,surplus energy must be exported to
network loads in other states.Projects are planned to construct additional transmission lines (the
Energy Gateway projects)from Wyoming to points in Idaho,Oregon,Utah,and the Desert
Southwest to accommodate additional exports from Wyoming;however these projects will not
be in-service in time for the proposed interconnection.An overview of these plans can be found
at the Northern Tier Transmission Group website (http://www.nttg.biz/site/)or at the Informal
Message section of Transmission Provider's OASIS website
(http://www.oasis.pacificorp.com/OASIS/PPW/).
In order to deliver 100 percent of the Project output to network loads prior to the completion of
the Aeolus to Populus segment of Energy Gateway,additional system improvements are required
for the Q0542 project.There are several transmission constraints in Wyoming that need to be
alleviated in order to accommodate the 240 MW Q0542 output (see Figure 2):
(1)TOT 4A.TOT 4A is defined as the sum of the flows on the following230kV lines:
Riverton -Wyopo,Spence -Mustang and Miners -Platte.This path is fully committed
at this time.
(2)Rock Springs /Firehole West.This path is defined as the sum of the flows on the Rock
Springs -Raven 230 kV and the Firehole -Mansface 230 kV lines.This path is fully
committed at this time.
To accommodate the Project output,a new approximately 150-mile long 230 kV line from
Shirley Basin to Bitter Creek substation,will be necessary in order to increase the constrained
TOT 4A transmission path.Additional studies will be required to determine the new TOT 4A
path rating after the addition of the new line and it will have to go through the WECC Three
Phase Facility Rating process.
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Additionally,a new approximately 50-mile long 230 kV line from a new substation (White
Horse)on the Atlantic City -Rock Springs 230 kV line,to a new substation near Jonah Gas is
required.A 230 kV phase shifting transformer at Craven Creek is required for flowabilityas the
Monument West path is also phase shifted.
A portion (128 MW)of the 240 MW project output could be scheduled on the Bridger West
system.The Bridger West (three 345 kV lines)path capacity is 2400 MW and current obligations
total 2208 MW.The remaining 192 MW of capacity is shared between Idaho Power,64 MW
(one-third)and PacifiCorp,128 MW (two-thirds).The remainder will be scheduled on the
improved Rock Springs/Firehole West path (White Horse -Jonah).
The new proposed projects are in Figures 2 and 3.
I Riverton
I
Pinedale
I
Wyopo
Paradise ColumbiaGenevaSteel SpenceI
Atlantic
I Chimney Butte CityIdaho TOT4AJonah850MW
el Field White BairoilToThreeMileKnolllChappLabargeHorseToPopulusCreekMustang
Great 115 kVTreasureton_
._.._.Divide
Bridger WestKeerer/ge Exxon 2400 Miners
Naughto Blacks e Jim Brid Platte Standpi
Lim Fork go 'Rock Echo ,BasinMonmn
Blue rings Springs
.-Bar LathamBenreekISouthimFireholefntBitterLomondMonumentWesronÔapstaceRocksCreek
475 MW Little MtnIRailroadRockprings-Wyoming
Evain2s80onMWestL._._._._._._._.Eirebo 640._._._._._._._._._._._._._._._._._._.
Flam ng Gorge --------ForeignUtah--------ownedColorado<230 kV230kV
345kV
Proposed
230kV
Figure 2:Central &Southwest WyomingTransmission System
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5.2.2 Network Resource Requirements
5.2.2.1 GeneratingFacility Modifications
See Section 5.1.2.1.
5.2.2.2 Network Resource Transmission Modifications
Transmission modifications required include the following(refer to Figures 2 and 3):
Construct a new 150-mile 230 kV transmission line from Shirley Basin to the Bitter
Creek substation.
Construct a new 50-mile 230 kV transmission line from White Horse to the Jonah Gas
substation.
ProposedBridger Changes 230 kV line
xfmr #1 &3
----Future 230kV
Remove
o DJ
xfmr #2 o yO
o
230 kV DifficultyMustang
230 k 230 kV
Bitter Rock
Creek Spangs ShirleyBasinOy/Dunlap
Bridger Freezeou /
Bitter 6 miles 45 miles
Creek /
POR
13 le
U to 44
5 miles Ecl Lathaan 34 4 mil
n es S ipe
to
Difficultv
New Bitter Creek230 kV Substation
Pro
O Du ap
to Latham to Shirley Basin ()To Jim Bridger
To POR
o Bar X
Spr 10
O
To Monell Freezeout Standpipe
To Standpipe
ProposedLatham Expansion
Figure 3 -New 230 kV Line from Shirley Basin to Bitter Creek substation and Other
Improvements
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5.2.2.3 Network Resource Protection and Control Requirements
To support the Transmission line upgrades required for the NR part of the project the following
protective relaying will be required along with communication links to support the line relaying:
Shirley Basin -Standpipe
Standpipe -Latham
Latham -Platte
Latham #1 Bitter Creek
Latham #2 Basin -Bitter Creek
Bitter Creek -Point of Rocks
Bitter Creek-Jim Bridger
White Horse -Jonah Gas
Rock Springs -White Horse
White Horse -Atlantic City
All of the transmission lines will be built with optical fiber cable in the shield wire position.
This communication media will be used by the line relay in most locations.For each of the
transmission lines,permissive overreaching transfer trip scheme will be used except for the short
line between the Bitter Creek and the Bridger substations which will use line current differential
and the White Horse to Atlantic City transmission line which will continue to use power line
carner.
Relaying will be needed for the new phase shifting transformers in the Craven Creek substation.
5.2.2.4 Network Resource Substation Re uirements
Shirley Basin substation
At Shirley Basin substation a new bay will be added with one 230 kV circuit breaker to add the
new line termination.The substation will still operate as a ring bus.Other major equipment
installed include:CCVT's,group operated switches,and lightningarresters.
Standpipe substation
Standpipe substation will need to be expanded to the south/west which includes additional fence,
ground grid,and grading.A new bay will be installed with three 230 kV circuit breakers to
terminate the two new line positions in the breaker and a half configuration.Other major
equipment include:CCVT's group operated switches,and lightningarresters.
Latham substation
At Latham substation two new 230 kV circuit breakers will be installed to terminate the two new
line positions.Other major equipment include:CCVT's,group operated switches,and lightning
arresters.
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Echo Springs substation
Relaying on the existing 230kV line from Latham to Point of Rocks will be mirrored bits.Two
wave traps will be removed.
Bitter Creek substation
Bitter Creek substation will be completely expanded.A new substation will be constructed
directly adjacent to the existing substation.The new substation will be a four breaker ring bus
with four 230kV,3000A breakers and four line terminations.Other major equipment include:
CCVT's,group operated switches,lightning arresters,and a new control building.It is assumed
a distribution line can be built to provide station service.The fence will enclose both old and
new yards and the new ground grid will be tied with the existing ground grid.The 230kV
Monell line will remain in its existing position.
Point of Rocks substation
The existing 230kV position to Jim Bridger substation will be removed.Two 230 kV switches
will be removed.
Jim Brideer substation
As part of the Jim Bridger reconfiguration,two 230kV bays will be installed with five 230kV,
3000A circuit breakers.Other major equipment required include:group operated switches,
CCVT's,and lightning arresters.Additional AC and DC load centers will be required.One
230kV breaker and one 230kV switch will be removed.The 230kV line terminations will be
moved within the substation.
Jonah Field substation
A new substation will be constructed near the Jonah Gas facility.This substation will be a three
breaker ring bus with three 230kV circuit breakers.Other major equipment required include:
CCVT's,group operated switches,a control building,and lightning arresters.It is assumed a
distribution line is in close proximity and can be expanded to serve the station service of the
substation.Fencing,grading,ground grid,conduit,cable trench,and yard lighting will be
required.
White Horse substation
A new substation will be constructed in between Atlantic City substation and Rock Springs
substation.This substation will be a three breaker ring bus with three 230kV circuit breakers.
Other major equipment required include:CCVT's (one with a line tuner and carrier accessories),
a wavetrap,an SSVT,group operated switches,a control building,and lightning arresters.
Fencing,grading,ground grid,conduit,cable trench,and yard lighting will be required.
Atlantic City substation
No major substation modifications are required at Atlantic City substation.
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Rock Springs substation
One 230kV wavetrap will be removed (old Atlantic City line).
Craven Creek substation
Two 230kV phase shifting transformers will be installed (one for redundancy).Three 230kV
circuit breakers will be installed.Other major equipment include:lightning arresters and group
operated switches;three CCVT's will be relocated within the substation.The installation of the
transformers will require expanding the substation which includes fencing,grading,and new
ground grid.
5.2.2.5 Network Resource Communication Requirements
Communication Requirements to deliver the Q0542 Projects generation to the Transmission
Provider's Network Load include:
Install OPGW fiber optic cable on the new 150 mile line from Shirley Basin to Bitter
Creek and on to Jim Bridger substation.
Fiber nodes and multiplexwill need to be installed at Platte,Latham,Echo,Bar X,Bitter
Creek and Point of Rocks.
Mirrored bits line protection will be over the OPGW fiber installed on the new lines.
Install a new RTU at Bitter Creek substation
Install 48 volt battery and chargers at Echo,BarX,and Bitter Creek substations.
Install OPGW fiber optic cable on the new line from Jonah Field to the new White Horse
substation.
Install a new RTU at the White Horse substation
Install fiber node and multiplexat the White Horse 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).
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5.2.3 Network Resource Cost Estimate
Interconnection -ER Only $12,220,000
NR Interconnection
Shirley Basin substation -Bitter Creek substation -Engineering,$88,500,000
procurement and construction of a new 150 mile 230 kV transmission
line.
White Horse substation -Jonah Gas substation -Engineering,$26,500,000
procurement and construction of a new 150 mile 230 kV transmission
line.
Shirley Basin substation -Engineering,procurement and construction of $3,300,000
a new bay and 230 kV circuit breaker includingCCVT's,group operated
switches,and lightning arresters.
Standpipe substation -Engineering,procurement and construction to $6,700,000
expand substation,add a bay and three 230 kV circuit breakers including
CCVT's group operated switches,and lightning arresters.
Latham substation -Engineering,procurement and construction to add $2,750,000
two new 230 kV circuit breakers including CCVT's,group operated
switches,and lightning arresters.
Echo Springs substation -Engineering,procurement and installation of $2,650,000
mirrored bits relaying and removal of two wave traps.
Bitter Creek substation -Engineering,procurement and construction of a $17,700,000
new four breaker ring bus substation including CCVT's,group operated
switches,lightning arresters,and a new control building.
Point of Rocks substation -Engineering and removal of the 230 kV line $285,000
position to the Jim Bridger substation and the removal of two switches.
Jim Bridger substation -Engineering,procurement and construction of $8,850,000
two new bays and five new 230 kV circuit breakers,new AC and DC
load centers and the installation of group operated switches,CCVT's,
and lightning arresters.
Jonah Field substation -Engineering,procurement and construction of a 15,500,000
230 kV three breaker ring bus including CCVT's,group operated
switches,a control building,and lightningarresters.
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White Horse substation -Engineering,procurement and construction of a 12,600,000
new 230 kV three breaker ring bus substation including CCVT's (one
with a line tuner and carrier accessories),a wavetrap,an SSVT,group
operated switches,a control building,and lightning arresters.
Atlantic City substation -Engineering and labor to upgrade the $80,000
protection and control equipment at the Atlantic City substation.
Rock Springs substation -Engineering and labor to remove one 230 kV $43,000
wavetrap.
Craven Creek substation -Engineering,procurement and construction to $44,400,000
expand the substation and install two 230 kV phase shifting transformers
and three 230 kV circuit breakers including group operated switches,a
control building,lightningarresters and relocation of three CCVT's.
Total Cost -NR Interconnection Service -Interconnection Only $242,078,000
5.2.4 Schedule
The Transmission Provider estimates it will require approximately 7 to 10 years to design and
build both the Energy Resource and Network Resource facilities described in this report after the
completion of both items below.
l .Obtain the necessary permits and rights of way to construct the facilities necessary to
interconnect the Q0542 project (Interconnection Customer's responsibility)
2.Execute a Large Generation Interconnection Agreement.
Please note the time required to execute the scope of work coupled with the anticipated date the
Interconnection Agreement will be signed,results in a timeframe that does not support the
Interconnection Customer's requested in-service date of December 1,2015.
6.0 PARTICIPATION BY AFFECTED SYSTEMS
Transmission Provider has identified the followingaffected systems:Western Area Power
Administration.A copy of all reports will be shared the each affected system.
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7.0 APPENDIX 1:PROPERTYREQUIREMENTS
Property Requirementsfor Point of Interconnection Substation
The followingapplies to property acquired by an Interconnection Customer on which a Point of
Interconnection substation will be built to accommodate the Interconnection Customer's project.
The property will ultimatelybe assigned to PacifiCorp,the Transmission Provider.
Property must be environmentally,physically and operationally acceptable to the
Transmission Provider without any material defects of title (or as deemed acceptable to
the Transmission Provider)and without unacceptable encumbrances.The property shall
be a permitted or permittable use in all zoning districts.Property lines shall be surveyed
and show all encumbrances,roads (private or public);easements (prescriptive or express)
etc.
Examples of potentiallyunacceptable environmental,physical,or operational conditions:
.Environmentallyunacceptable conditions could include but are not limited to
known contamination of site;evidence of environmental contamination by any
dangerous,hazardous or toxic materials as defined by any governmental agency;
property is in violation of building,health,safety,environmental,fire,land use,
zoning or other such regulation,ordinances,or statues of any governmental
entities having jurisdiction over the property;underground or above ground
storage tanks;known remediation sites on property;ongoing mitigation activities
or monitoring activities;asbestos;lead-based paint,etc.At a minimum,a phase I
environmental study is required for company land being acquired in fee.
Evidence will be required 60 days prior to the start of construction.
.Physicallyunacceptable conditions could include but are not limited to inadequate
drainage;in flood zone;erosion issues;wetland overlays;threatened and
endangered species;archeological or culturally sensitive areas;inadequate sub-
surface elements,etc.Geotechnical studies are required by the Transmission
Provider.
Operationally unacceptable conditions could include but are not limited to
inadequate access for company equipment;existing structures on land that require
removal prior to building of substation;ongoing maintenance for landscaping or
extensive landscape requirements;ongoing homeowner's or CC&R's that are not
acceptable to the Transmission Provider.
Property should be acquired by fee ownership.If fee acquisition is not possible,then the
term shall be perpetual and the use exclusive and provide the Transmission Provider with
all property rights it deems necessary (perpetual easement).All contracts are subject to
the Transmission Provider's approval prior to execution.
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The Interconnection Customer is required to identify any and all land rights to the subject
property,which are to be retained by the Interconnection Customer prior to conveying
property.All retained land rights are subject to the Transmission Provider's approval.
If the Interconnection Customer is building facilities to be owned by the Transmission
Provider,then the Interconnection Customer must obtain all permits required by all
relevant jurisdictions for the use including but not limited to conditional use permits,
Certificates of Public Convenience and Necessity,California Environmental QualityAct,
etc.,as well as all construction permits for the project
Interconnection Customer will not reimburse through network upgrades for more than the
market value of the property.
Property must be assignable to company and without litigation,suit,liens,condemnation
actions,foreclosures actions,etc.
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8.0 APPENDIX 2:COMBINED QUEUE
Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
SF Phosphates
2 01/19/01 East N/A Substation,230 02/01/02 11
kV
West Valley
3 01/23/01 East N/A Substation,138 09/01/01 200
kV
Foote Creek
7 03/07/01 East N/A Substation,08/01/01 50
34.5 kV
Monument
8 03/08/01 East N/A Switching 10/01/04 110
Station,230 kV
Rowley
9 04/01/01 East N/A Substation,138 06/15/01 80
kV
Gatsby
11 07/20/01 East N/A Substation,138 09/01/02 120
kV
Longhollow
12 08/27/01 East N/A Switching 12/26/03 146
Station,138 kV
Northwest
18 10/21/02 East N/A Substation,46 10/06/04 25
kV
20 04/30/03 East GEN Mona 345kV 03/22/06 280
21 04/30/03 East GEN Mona 345kV 03/22/06 245
29a 09/18/03 East GEN Goshen 161kV 02/12/06 64.5
29b 09/18/03 East GEN Goshen 161kV 10/20/10 129
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Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
Timp -Tri-City 535-S4406/03/04 East ER 07/29/07Line,138kV 567-W
Terminal Sub
52 03/28/05 East GEN Distribution 07/20/06 3.2
Circuit,12.47kV
North of 250-S5908/24/05 East NR Antelope Mine 06/01/11 285-WSub,230kV
Blundell 11-S6612/05/05 East NR Geothermal 10/19/07 15-WSub
Spanish Fork -
73 03/27/06 East GEN Santaquin,07/31/08 18.9
46Kv
PACE31033926804/12/06 East NT PACE 04/15/06 141(Resource)
Mona
78 04/25/06 East NR Substation,04/25/06 59
345Kv
Uinta Long9006/22/06 East ER 05/15/08 60Hollow,138kV
Tooele
93 09/19/06 East GEN Substation,47-03/01/08 1
kV
NR Uinta Long9610/09/06 East 07/02/08 79.5w/ER Hollow,138kV
Timp-Tri-City 79-S10711/14/06 East NR 08/18/08line,138kV 49-W
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Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
2700 East
111 12/08/06 East NA 11600 South,08/09/07 0.511
Sandy,UT
Miners-NR11701/18/07 East Difficulty Line,12/09/08 99w/ER 230kV
Miners-NR11801/18/07 East Difficulty Line,12/09/08 19.5w/ER 230kV
NR Foote Creek119a01/29/07 East 09/30/09 127.5w/ER Sub.230kV
Existing point of
120 02/08/07 East NA service in 10/04/07 0.65
Laramie,WY
126 03/05/07 East NR Near Glenrock 01/02/09 237Mine230kV
Oquirrh-Lark12903/30/07 East N/A '04/01/09 4.846-kV
138 05/22/07 East N/A Green River 12
circuit,12.5kV 05/22/09 0.575
University
139 05/25/07 East N/A Substation,10/09/09 7.6
46kV
PacifiCorp's
24.9-kV Circuit,
150 07/13/07 East N/A QRY15,out of 6/18/2009 1
Quarry
Substation
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Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
Dave Johnston-NR15308/08/07 East Yellowcake 10/28/10 200.5w/ER Line,230-kV
Goshen-Ucon15408/10/07 East N/A 04/30/12 19.8Line,69-kV
14.4-kV Circuit
161 09/04/07 East N/A out of Pinedale 1/22/2009 0.05
Substation
3474 N.3rd16510/12/07 East N/A 3/11/2008 0.03Street
PacifiCorp's 69-
kV,Sand Hills
171 11/08/07 East N/A Line between 12/25/2009 19.5
Casper &Platte
Junction
Craven CreekNE17512/07/07 East to Chappel 11/30/12 150w/ER Creek 230 kV
PAC's 230 kVNR19101/25/08 East Jim Bridger -08/01/14 500w/ER Aeolus
PacifiCorp's
199 02/20/08 East NR proposed 230-12/01/14 200kVAeolus
Substation
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Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
PacifiCorp's
200 02/20/08 East NR proposed 230-12/01/14 100kVAeolus
Substation
PacifiCorp's
201 02/20/08 East NR proposed 230-12/31/15 100kVAeolus
Substation
Shirley-Basin
Substation on
203 02/26/08 East ERR the PacifiCorp's 09/30/10 111
230-kV Miners-
Difficulty Line
Bernice #22
circuit out of21304/22/08 West N/A 8/4/2009 0.3Bernice
Substation
Pinedale Circuit21404/24/08 East N/A 02/18/09 1.96#23
Latigo
Substation
NR between22005/12/08 East 11/20/09 100.5w/ER Casper and
Windstar 230-
kV line
316-PACE94749309205/23/08 East NT PACE 6/1/2012 S(Resource)562-W
PacifiCorp'sNR224a05/27/08 East 345 kV Mona 05/15/15 320w/ER substation
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Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
PacifiCorp'sNR224b05/27/08 East 345 kV Mona 05/15/15 230w/ER substation
Customer's
252 11/25/08 East N/A existing 46-kV 3/1/2009 0.23
system
1600 West B
Avenue,Utah
253 11/26/08 East N/A Industrial 2/20/2009 0.05
Depot,Tooele,
Utah
3.2 miles NE of
NR PacifiCorp's 05/20/12 151.825512/23/08 West w/ER Goshen
Substation
256 01/14/09 West NA HPS 12 Circuit 04/15/09 1.696
PacifiCorp's
345-kV Jim 18.3-NR267-A 04/13/09 East Bridger Power 6/12/10 Sw/ER Plant,Point of 22-W
Rocks,WY
PacifiCorp's
345-kV Jim 18.3-NR267-B 04/13/09 East Bridger Power 5/5/13 Sw/ER Plant,Point of 22-W
Rocks,WY
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System Impact Study Report
Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
PacifiCorp's
345-kV Jim 18.3-NR267-C 04/13/09 East Bridger Power 5/22/11 Sw/ER Plant,Point of 22-W
Rocks,WY
PacifiCorp's
345-kV Jim 18.3-NR267-D 04/13/09 East Bridger Power 5/27/12 Sw/ER Plant,Point of 22-W
Rocks,WY
PacifiCorp's
270-A 04/30/09 East ER Huntington 11/21/10 16.2PowerPlant,
Huntington,UT
PacifiCorp's
270-B 04/30/09 East ER Huntington 4/30/15 16.2PowerPlant,
Huntington,UT
PacifiCorp's
Hunter Power271-A 04/30/09 East ER 4/13/10 17.0Plant,
Castledale,UT
PacifiCorp's
Hunter Power271-B 04/30/09 East ER 4/30/15 17.0Plant,
Castledale,UT
PacifiCorp's
Hunter Power271-C 04/30/09 East ER 4/30/16 8.7Plant,
Castledale,UT
Page 37 August 19,2014
Q0542
PACIFICORP
System Impact Study Report
Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
PacifCorp's
proposed new
NR substation on27205/14/09 East 9/30/10 12.0w/ER the 230-kV
Miners-
Difficulty Line
1145 563529 06/26/09 East NT PACEW PACEW 4/1/10 25.0
PacifiCorp's
138/46-kV28208/07/09 East N/A 9/25/09 0.0360Lampo
Substation
17 miles south
290-A 09/22/09 East NRIER SE of Rock 6/30/12 100.8
Springs,WY
17 miles south
290-B 09/22/09 East NRIER SE of Rock 12/31/12 100.8
Springs,WY
17 miles south
290-C 09/22/09 East NRIER SE of Rock 6/30/13 50.4
Springs,WY
PacifiCorp's
291 09/25/09 East NRIER Emery to 12/31/11 100.0SpanishFork
345 kV line
53-S116758102510/05/09 East NT PACE PACE (Load)3/1/11 94-W
32-S116958360810/14/09 East NT GSHN GSHN (Load)1/1/13 64-W
Page 38 August 19,2014
Q0542
PACIFICORP
System Impact Study Report
Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
1170 583614 10/14/09 East NT PACE PACE (Load)9/1/10 21
PacifiCorp's
proposed new
substation 707-S30110/27/09 East NRIER adjacent to the 6/1/14 670-WLakeSide
Power Gen
Facility
PacifiCorp's
Amassa
306-A 11/13/09 East NRIER Substation,1/31/11 48.3
(DJ-Difficulty
230-kV)
PacifiCorp's
34.5-kV31012/21/09 East N/A 10/31/10 20.0Parowan
Substation
Three Peaks
311 12/22/09 East N/A Substation 10/31/10 20.0
Substation
PacifiCorp's
138 kV switch
132 located 3/4 25-S31312/22/09 East NR 12/31/12mileNofthe 65-W
generation
facility site
PacifiCorp's
34.5-kV West31412/31/09 East NR 12/31/10 20.0Cedar
Substation
1190 603498 02/15/10 East NT PACE PACE (Load)7/1/10 12.0
Page 39 August 19,2014
Q0542
PACIFICORP
System Impact Study Report
Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
PacifiCorp's
230-kV323-A 03/03/10 East NRIER 5/31/11 21.6Sunbeam
Substation
PacifiCorp's
230-kV323-B 03/03/10 East NRIER 11/30/11 21.6Sunbeam
Substation
Parowan -
Rocky
324 03/08/10 East N/A Mountain 8/10/12 40.0
Power
Substation
1202 614127 04/09/10 East NT WYOEAST WYODAK (Load)11/17/10 35.0
PacifiCorp's
24.9-kV circuit,
332 04/29/10 East N/A SML21,out of 6/1/11 2.8
South Milford
Substation
1209 617716 05/03/10 East NT GSHN GSHN (Load)1/1/13 39.0
1210 618363 05/03/10 East PTP PACE MDWP 6/1/11 3.0
WYOCENTRAL121461894005/14/10 East NT WYOCENTRAL 10/1/10 10.0(Load)
PacifiCorp's
24.9 kV circuit,
333 05/17/10 East N/A SML21,out of 10/1/11 2.8
South Milford
Substation
1215 620282 05/19/10 East NT PACE PACE (Load)6/30/11 17.0
1216 621679 05/27/10 East NT PACE PACE (Load)7/1/10 15.0
Page 40 August 19,2014
Q0542
PACIFICORP
System Impact Study Report
Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
PacifiCorp's
Amassa
335 06/01/10 East NRIER Substation,3/1/12 49.5
(DJ-Difficulty
230-kV)
PacifiCorp's
Goshen34106/10/10 East NR/ER 11/1/12 120.0Substationat
161 kV
1223 625986 06/17/10 East NT WYOEAST WYOEAST (Load)1/1/11 2.0
1224 626003 06/17/10 East NT PACE PACE (Load)10/1/10 2.0
1225 626275 06/17/10 East NT WYOEAST WYOEAST (Load)12/10/10 9
1229 626453 06/23/10 East NT PACE PACE (Load)7/1/11 150.0
1230 626791 06/23/10 East NT PACE PACE (Load)2/24/11 30.0
1231 626864 06/23/10 East NT PACE PACE (Load)11/1/10 6.0
1236 630525 07/15/10 East NT WYOEAST WYOEAST (Load)6/1/11 15.0
1237 634125 08/03/10 East NT PACE PACE (Load)10/1/10 8.0
PacifiCorp's
24.9-kV Circuit,
348 08/09/10 East N/A QRY15,out of 4/30/11 0.22
Quarry
Substation
1238 635532 08/09/10 East NT WYOEAST WYOEAST (Load)7/31/13 67.0
1241 637972 08/20/10 East NT PACE PACE (Load)7/1/13 21.0
1248 645170 09/22/10 East PTP PACE MDWP 1/1/12 3.0
1251 645781 09/29/10 East NT PACE PACE (Load)10/1/11 4.0
1252 645790 09/29/10 East NT PACE PACE (Load)12/1/10 8.0
PACE125664800810/08/10 East NT PACE 5/1/14 660.0(Resource)
1258 648377 10/12/10 East NT PACE PACE (Load)5/1/13 13.0
1263 656398 11/09/10 East NT DJ WYOEAST (Load)12/1/10 1.0
Page 41 August 19,2014
Q0542
PACIFICORP
System Impact Study Report
Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
PacifiCorp's
24.9-kV
Southfork
363 12/13/10 East N/A Circuit,4H27,TBD 0.1
out of South
Cody
Substation
PacifiCorp's
34.5-kV N
Rawlins36512/20/10 East N/A .5/1/2011 0.11Curcult,9H440,
out of Platte
Substation
PacifiCorp's
proposed
Sigurd-Red 169-S36712/27/10 East N/A 1/1/2014Butte345-kV 172-W
transmission
line
375 03/04/11 East NR/ER SDibatioyn 10/1/2014 351
1305 686836 03/18/11 East NT PACE PACE (Load)4/1/2011 6.00
Pinto38403/30/11 East NR/ER Substation 12/31/2012 60
1312 692513 04/04/11 East NT PACE PACE (Load)7.00
1317 702580 05/11/11 East NT PACE PACE (Load)04/01/12 70
1326 709355 06/07/11 East PTP PACE PACE 1/1/2015 20
Circuit OQU18,
Oquirrh #18
396 08/04/11 East N/A feeder,out of 12/1/2011 0.585
Oquirrh
substation
Page 42 August 19,2014
Q0542
Y PACIFICORP
System Impact Study Report
Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
1361 741886 10/12/11 East NT WYOCENTRAL 1/1/2012WYOCENTRAL(Load)37
403 10/25/11 East NR/ER Su
start
on 7/1/2014 525
1376 752491 11/29/11 East NT PACE PACE (Load)1/1/2013 5
Rock Springs-
407 01/17/12 East NR/ER Naughton Line,12/31/2012 79.8
230kV
Windstar-
409 01/26/12 East NR/ER Aeolus line,9/30/2014 320
230kV
1405 769663 02/27/12 East NT PACE PACE (Load)5/1/2012 89
1407 770827 03/07/12 East NT WYON WYON (Load)5/1/2012 4
24.9-kV circuit,
415 03/12/12 East N/A SML21,out of 12/1/2012 10
South Milford
Carbide
420 03/26/12 East NR/ER substation,10/1/2014 200
69kV
1412 775561 03/28/12 East NT GSHN GSHN (Load)10/1/2013 3
1497 785040 05/23/12 East NT WYOEAST PACE 11/01/13 25
425 06/01/12 East N/A Chappel Creek
substation 7/30/2016 156.2
Moab-Pinto42606/26/12 East NR/ER 8/31/2014 80Line,Pole #365
1520 804038 08/15/12 East NT PACE PACE 8/15/2012 2
1521 804043 08/15/12 East NT WYOCENTRAL WYOCENTRAL 10/15/2012 1
1523 805002 08/23/12 East NT PACE PACE 12/1/2012 46
1524 805181 08/23/12 East NT WYOCENTRAL WYOCENTRAL 11/1/2012 5
Page 43 August 19,2014
Q0542
PACIFICORP
System Impact Study Report
S.tartDate
POR (TSR)/(TSR)ICompletedCustOASISControlTypeofLocationofQUEUERequestPOD(TSR)Requested MVVAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
Customer's
432 08/27/12 East N/A existing 138kV 5/1/2013 6.3
substation
1530 806472 08/30/12 East NT TRONA TRONA 11/1/2012 8
1531 806486 08/30/12 East NT TFU3NA TFU3NA 1/1/2015 29
1532 806494 08/30/12 East NT PAX3E PAJ3E 1/1/2012 2
1533 806544 08/30/12 East NT PAX3E PAJ3E 1/1/2012 4
1534 806561 08/30/12 East NT PAX3E PAJ3E 1/1/2013 6
1535 806585 08/30/12 East NT PAX3E PAX3E 12/1/2012 8
1536 807115 08/31/12 East NT PAX3E PAJ3E (Load)9/1/2013 5
809252;09/14/12 East NT BCLE ANDK(Load)8/1/2016 501540809367
809254;09/14/12 East NT BCLE /UNDK(Load)8/1/2016 1001541809362
809337;09/14/12 East NT BCLE ANDK(Load)1/1/2013 201542809374
809340;09/14/12 East NT BCLE ANDK(Load)1/1/2015 241543809375
809347;09/14/12 East NT BCLE /UNDK(Load)2/1/2015 31544809376
809353;09/14/12 East NT BCLE ANDK(Load)1/1/2016 31545809378
809355;09/14/12 East NT BCLE ANDK(Load)9/1/2016 31546809380
809357;09/14/12 East NT BCLE /UNDK(Load)1/1/2017 111547809382
809397 ;09/14/12 East NT BCLE ANDK(Load)1/1/2013 301548809398
CircuitP'RS13,
437 09/17/12 East N/A Preston#13,4/17/2014 0.5outofPreston
substation
Page44 August19,2014
Q0542
PACIFICORP
System Impact Study Report
Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
Customer's
electric system
438 09/18/12 East N/A from Tooele 4/1/2013 1.75
Depot
substation
Customer's
electric system
439 09/18/12 East N/A from Tooele 4/1/2013 1.56
Depot
substation
RIGBY-
REXBURG44210/11/12 East N/A TAP TO 9/30/2014 5.6
WEBSTER
1578 77610461 12/06/12 East NT Sunbeam BRDY 3/1/2013 45
450 12/21/12 East N/A Pavant 3/15/2014 50substation
Circuit CLM11,
451 01/02/13 East N/A Coleman #11,
out of Coleman 12/13/2013 3
substation
1591 77717778 01/02/13 East PTP PACE 4C 1/1/2014 66
1592 77717792 01/02/13 East PTP PACE 4C 1/1/2014 100
Circuit CLF11,
CLIFTON #11
DAYTON &453 01/07/13 East N/A BANIDA,out of 12/31/2013 1.6
Clifton
substation
Page 45 August 19,2014
Q0542
PACIFICORP
System Impact Study Report
Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
Circuit WCD28,
West Cedar
454 01/10/13 East N/A #28,out of 6/30/2014 3
West Cedar
substation
Circuit WCD28,
West Cedar
455 01/10/13 East N/A #28,out of 6/30/2014 3
West Cedar
substation
Circuit BKl12,
Brooklawn #12,
456 01/10/13 East N/A out of 6/30/2014 2.1
Brooklawn
substation
Circuit BKl11,
Brooklawn #11,
457 01/10/13 East N/A out of 6/30/2014 2.1
Brooklawn
substation
1599 77699698 01/16/13 East NT GSHN GSHN 11/1/2013 1
Circuit SML12,
South Milford
459 01/18/13 East N/A #12,out of 6/30/2014 3
South Milford
substation
Pavant-Gonder
460 01/18/13 East NR/ER Transmission 12/31/2014 160
Line
1603 77786388 01/23/13 East NT PACE MDGT 01/01/15 24
Page 46 August 19,2014
Q0542
PACIFICORP
System Impact Study Report
Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
1605 77762035 01/25/13 East NT NEWPOINT NEWPOINT 01/01/16 84
1607 77762000 01/30/13 East NT NEWPOINT NEWPOINT 01/01/16 164
Circuit ENO12,
Enoch#12,out46302/11/13 East N/A 6/30/2014 3ofEnoch
substation
Circuit WCD28,
West Cedar#
464 02/11/13 East N/A 28,out of West 6/30/2014 3
Cedar
substation
465 02/11/13 East NR/ER su
sbaat
on 12/31/2015 50.4
Circuit WCD28,
West Cedar
471 02/28/13 East N/A #28,out of 6/30/2014 3
West Cedar
substation
Circuit WCD28,
West Cedar
472 02/28/13 East N/A #28,out of 6/30/2014 3
West Cedar
substation
Circuit WCD28,
West Cedar
473 02/28/13 East N/A #28,out of 6/30/2014 3
West Cedar
substation
Page 47 August 19,2014
Q0542
PACIFICORP
System Impact Study Report
Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
Circuit ENV12,
Enterprise #12,
475 03/08/13 East N/A out of 12/31/2013 3Enterprise
Valley
substation
Circuit PRV25,
Parowan
Valley#25,out48803/19/13 East N/A 12/31/2013 3ofParowan
Valley
substation
Circuit ENO12,
Enoch#12,out48903/19/13 East N/A of Enoch 12/31/2013 3
substation
Circuit BKl12,
Brooklawn #12,
491 03/19/13 East N/A out of 12/31/2013 3
Brooklawn
substation
Circuit SML12,
South Milford
492 03/19/13 East N/A #12,out of 12/31/2013 3
South Milford
substation
Page 48 August 19,2014
Q0542
PACIFICORP
System Impact Study Report
Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
Circuit SML11,
South Milford
493 03/19/13 East N/A #11,out of 12/31/2013 3
South Milford
substation
1722 78169628 04/30/13 East PTP TRONA REDB 5/1/2014 30
1723 78170277 04/30/13 East PTP TRONA MPAC 5/1/2014 30
Circuit RKW11,
Porter Rockwell
500 06/12/13 East N/A #11,out of 9/1/2013 2.589
Porter Rockwell
substation
1747 78351080 06/18/13 East NT PINTO PACE 11/30/2015 80
Circuit MLF12,
502 06/27/13 East N/A Milfor 2rd 10/15/2015 2.97
substation
Circuit SML21,
South Milford
503 06/27/13 East N/A #21,out of 10/15/2015 2.97
South Milford
substation
Page 49 August 19,2014
Q0542
PACIFICORP
System Impact Study Report
Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
Circuit SML12,
South Milford
504 06/27/13 East N/A #12,out of 10/15/2015 2.97
South Milford
substation
Milford
substation 72-
47kv
512 08/22/13 East N/A distribution 3/1/2015 3
circuit,pole
number 173-28-
10#,059303
138kV bus at
West Cedar
substation (or)513 09/10/13 East NR/ER 138kV bus at 12/31/2015 80
Three Peaks
substation
Tap to the 138
kV Enterprise
Valley -West51409/13/13 East NR/ER Cedar 12/1/2015 80
transmission
line
Sigurd to Red
Butte No.2
515 09/13/13 East NRIER 345kV 12/1/2015 80
transmission
line
Page 50 August 19,2014
Q0542
PACIFICORP
System Impact Study Report
Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
Sigurd to Red
Butte No.2
516 09/13/13 East NR/ER 345kV 6/30/2015 3
transmission
line
1766 78752066 09/26/13 East NT DJ WYOE 10/1/2014 50
1767 78752068 09/26/13 East NT DJ WYOE 10/1/2014 50
1768 78752070 09/26/13 East NT DJ WYOE 10/1/2014 50
1769 78752071 09/26/13 East NT DJ WYOE 10/1/2014 109
1770 78752072 09/26/13 East NT DJ WYOE 10/1/2014 109
1771 78752081 09/26/13 East NT Fourcorners DJ 10/1/2014 85
Tap to 34.5 kV
MDD24
(Middleton 24)518 10/01/13 East N/A 6/30/2015 2.97circuitfeeding
Dixie Deer
substation
Tap to 34.5 kV
MDD24
(Middleton 24)519 10/01/13 East N/A 6/30/2015 3circuitfeeding
Dixie Deer
substation
Tap to 34.5 kV
MDD24
(Middleton 24)520 10/01/13 East N/A 6/30/2015 2.97circuitfeeding
Dixie Deer
substation
Tap to 12.5 kV
521 10/01/13 East N/A DXD12 (Dixie 11/1/2015 3
Deer 12)circuit
Page 51 August 19,2014
Q0542
Y PACIFICORP
System Impact Study Report
Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
Santaquin-
Nebo #2,tap to
523 10/08/13 East N/A Burgin (one of 11/1/2015 6
two 46kV lines
in the area)
Terminal -524 10/08/13 East N/A 11/1/2015 6Tooele46kV
Parowan52510/09/13 East NR/ER 11/30/2016 40substation
TAR11,
Tamarisk 11 (to
526 10/16/13 East N/A the immediate 12/31/2014 3
north of
substation)
HUC13,
527 10/16/13 East N/A Huntington 13 12/31/2014 3(South of town,
on Route10)
HUC1252810/16/13 East N/A .
'12/31/2014 3Huntington12
1778 78834184 10/18/13 East NT PACE PACE 12/1/2013 10
529 10/22/13 East N/A WCD 28 6/30/2015 3
530 10/22/13 East N/A WCD 28 6/30/2015 3
531 10/22/13 East N/A WCD 28 6/30/2015 3
1780 78849614 10/22/13 East NT WYOC WYOC 1/1/2014 21
1781 78865513 10/25/13 East NT WYOE WYOE 1/1/2014 20
532 11/07/13 East NR/ER Pavant 7/1/2016 50substation
1787 78984295 11/26/13 East NT WYOE WYOE 7/30/2014 7.5
Page 52 August 19,2014
Q0542
PACIFICORP
System Impact Study Report
Start Date
POR (TSR)/(TSR)ICompletedCust.OASIS Control Type of Location ofQUEUERequest POD (TSR)Requested MWAREF.Area Request InterconnectionReceived Commercial(GI)Operation
(GI)
138k/linetap
539 12/13/13 East NRIER on PacifiCorp's 3/31/2016 130.4WeccoRadial
line
Pinto
substation at
138 kV through54112/23/13 East NRIER facilities 12/31/2015 138
constructed for
Q0384
1794 79099043 12/23/13 East NT PACE PACE 3/31/2014 1
1796 79132251 01/03/14 East NT PACE PACE 1/1/2014 25
1797 79164408 01/09/14 East NT PACE PACE 2/1/2014 200
230 kV Frannie
-Yellowtail line
542 01/23/14 East NR/ER approximately 3 12/1/2015 240milesNorthof
the Frannie
substation
Page 53 August 19,2014
Q0542
PAciFICORP
Transient Stability Analysis Report
Completed for
LGIQ#Q0542
Proposed Interconnection
To the Existing
230 kV Frannie -Yellowtail
Transmission Line
August 22,2014
PAciFICORP
Table of Contents
Executive Summary ....................................................................................................................2
1.Description of Project..............................................................................................................3
2.Study Assumptions..................................................................................................4
3.Transient Analysis .........................................................................................................6
4.Conclusions..............................................................................................................................7
1
PAciFICORP
Executive Summary
("Interconnection Customer")proposed interconnecting 240 MW of new generation to
PacifiCorp's ("Transmission Provider")Frannie -Yellowtail transmission line approximately
2.75 miles north of the Frannie Substation located in Carbon County,Montana.The project
("Project")will consist of 120 Gamesa 2.0 Gll4 wind turbines generators for a total output of
240 MWs.The requested commercial operation date is approximately December 1,2015.
Interconnection Customer will [NOT]operate this generator as a Qualified Facility as defined by
the Public Utility Regulatory Policies Act of 1978 (PURPA).
The Transmission Provider has assigned the project "Q0542."
The Transmission Provider was not able to complete the transient stability analysis portion of the
System Impact Study due to technical issues with the model provided by the Interconnection
Customer.Until a working model is provided by the Customer and the Transmission Provider is
able to verify and analyze the dynamic behavior and the voltage ride through capabilities of the
turbines used by the Interconnection Customer,the study will remain incomplete and the results
will be deemed unacceptable.
The Project is required to operate in the voltage control mode maintaining the voltage at the POI
based on voltage schedule provided by the Transmission Provider.
2
PAciFICORP
1.Description of Project
The Interconnection Customer has proposed interconnecting a wind farm in Carbon County,
Montana,to PacifiCorp existing Frannie -Yellowtail 230 kV line approximately 2.75 miles
north of Frannie Substation.A preliminaryelectrical single line diagram depicting the Project's
interconnection at the point of interconnection (POI)substation is shown in Figure 1.
It is proposed to interconnect 120 Gamesa 2.0 Gll4 wind turbines generators.Power from each
turbine will be stepped up to 34.5 kV from 0.69 kV.A 34.5 kV collection system will bring the
combined power output to the collector substation where the power will be further increased to
230 kV through a 230/34.5 kV transformer.
New 230 kV Point of Interconnection for Q 542
230 kV line to
Yellowtail
230 kV line to
230 kV line toFrannie
Figure 1.Preliminary Single Line Diagram
3
PAciFICORP
2.Study Assumptions
The PSS/E version 33.5 program was used to evaluate system stability.In addition,the
followingassumptions were used in performing this study.
Study Period:The 2014 Heavy Summer WECC transmission power flow and dynamics data
updated was used for this analysis.
Study Area:The study area was limited to the Project and the surrounding 230 kV and 115kV
transmission system in Wyoming.
The existing commitments on the TOT4A/4B Paths were modeled in the study.Also generators
that are senior in the LGI queue and have TSR requests were modeled in the study.
Other Assumptions:
Transient stability simulations are performed out to 10 seconds in order to assess system
damping.
The Gamesa 2.0 MW Gl14 wind turbine is required to have voltage ride-through
protection capability;therefore,the wind turbine is designed to stay connected to the grid
in the case of severe faults.As shown in Figure 2 the wind turbines are required to have
the voltage ride through capabilities described in NERC standard PRC-024.
The Customer must ensure that the Gamesa 2.0 Gll4 wind turbines have voltage ride
through capability that conforms to the voltage ride-through time duration curve shown in
Figure 2 of this report.
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Voltage Ride-Through
Time Duration Curve 1.30
.1.25
m =1.20mm.1.15
1.0Š1.00
No Trip Zone
I 0.850.80 C
0.75 Ë0.70 =
0.60 o0.55 o.0.50 -
0.45 O0.40 CD0.35 g0.30 -
0.25 O
0.20 >0.150.10 O0.05 0.0.00
0 0.5 1 1.5 2 2.5 3 3.5 4
Time (sec)
---High Voltage Duration -Low Voltage Duratlon
Figure 2.Voltage Ride-through Capability
During normal voltage conditions,the voltage control scheme should operate to minimize
the reactive exchange between the Interconnection Customer's Project and Transmission
Provider system or as directed by the system operator.As per NERC standard VAR-001-
la,the Transmission Provider will provide a voltage schedule at the Point of
Interconnection.
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 prior to interconnection.The list of approved generator models is continually
updated and is available on the http://www.WECC.bizwebsite.
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3.Transient Analysis
The Project facility is required to ride through all 3-phase faults with normal clearing or single
line-to-ground faults with delayed clearing for any event that doesn't disconnect the facility.
The PSS/E version 33 program was used to evaluate the transient stability performance of the
wind turbines and system for different contingencies.The 2014 Heavy Summer WECC case
(14hslap.sav)was used for this analysis.Due to technical issues with the Gamesa user-written
dynamic model provided by the Interconnection Customer,the Transmission Provider was not
able to perform any transient stability analysis.The Transmission Provider has discussed the
model issues with the wind turbine manufacturer several times;however these discussions have
not resulted in the resolution of the technical issues seen by the Transmission Provider.
The Transmission Provider before running any contingency in transient stability simulations,
performs a steady state (no-contingency)run after implementing the dynamic model of the
Project.This ensures that the model provided by the Customer is working accurately and the
transmission system initializes without any technical issues.Ideally,as this is a no contingency
run,this should result in straight lines if the MW and MVAr output of the Project or any other
generator on the transmission system is plotted.This is called the "flat run"meaning a simulation
of the steady state system for 10-20 seconds would produce flat lines.When the Transmission
Provider ran the flat run after interconnecting the Project,the MW and MVAr output for the
Project was not a straight line as shown in Figure 3.
Figure 3:No-contingency run after interconnecting Q0542
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These issues were resolved based on changes suggested by the manufacturer.After the flat run
issues were resolved,the Transmission Provider encountered several issues with the voltage
controller model of the turbine that resulted in tripping of the Gamesa wind turbine units due to
high voltage shortly following fault clearing.While this is believed to be a model issue,the
voltage ride through capability could not be confirmed.
Due to these unresolved model issues,the Transmission Provider was not able to complete a full
transient stability analysis including the voltage ride-through capability for the Project and
determine whether interconnecting the Project to the Yellowtail -Frannie line is feasible without
any reliability issues.Hence,the Transmission Provider will not be able to interconnect the
Project until a working model is provided.
4.Conclusions
The followingconclusions have been reached through this analysis:
Transmission Provider was unable to perform transient stability analysis for the Project due to
technical issues with the dynamic model provided by the Customer.The Transmission Provider
has worked with the wind turbine manufacturer to resolve the model issue but has not arrived at
a successful resolution as of this writing.The Transmission Provider was not able to perform
detailed transient stability analysis to determine the voltage ride through capabilities of the
Project and also was not able to analyze the reliability impacts of the Project interconnecting to
Yellowtail -Frannie 230 kV line.Hence,the Transmission Provider cannot allow the Project to
interconnect at the POI until a working model is provided and detailed transient stability analysis
is performed.
Simulation results are based on data provided by the Interconnection Customer as well as other
model data available at the time of the study.The results can be used to help determine whether
or not the Project facilities will meet the performance criteria including ride-through
requirements which are identified in the Interconnection Agreement,and,in some cases,may
indicate that additional equipment is required in order to meet these requirements.However,
ultimately it is the Interconnection Customer's responsibility to meet these requirements during
actual operation on a daily basis and failure to do so can result in loss of interconnection
privileges.Therefore,the results of these simulations should be regarded as informational rather
than definitive,and do not relieve the Interconnection Customer of any performance
responsibilities.
Finally,if the assumptions utilized in this study significantly change,PacifiCorp reserves the
right to perform a re-study.Significant changes include,but are not limited to,development of
new models which may impact performance as well as changes to the base case assumptions for
planned future but as yet uncommitted transmission line and generation facilities.
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