Section 1
Summary of Stability Base cases for TPL 001-4
Studies
This document accompanies the base cases that have been posted to the ISO New England (ISO-NE)
website under Planning Advisory Committee (PAC) materials1 on August 11, 2015 in order to coordinate
with the PAC. The base cases will be utilized by ISO-NE to conduct studies needed to meet the NERC TPL001-4 standard.
Any text adjacent to the blue square brackets ([R1]) in the sections below refers to a specific
requirement in the NERC TPL 001-4 standard. If a subsection has such a designation then the
information within that subsection pertains to the stated requirement in the standard.
The study base cases will cover the following:
1. Five year out peak load case (2021) to assess the near-term stability impact to meet
requirement [R2.4.1]
2. Five year out off-peak load case (2021) to assess the near-term stability impact to meet
requirement [R2.4.2]
1.1.1 Study Assumptions
To assess the stability performance of the New England system, two stability base cases have been
developed. For the purposes of peak load stability analyses, the year five projection of the 90/10
summer peak demand level was used. For the purposes of off-peak load (light load) stability analyses, a
12,500 MW fixed light load was used.
1.1.2 Source of Stability Models [R1]
To represent the New England system topology, the Model on Demand (MOD) system was used. This
included all ratings and topology in the MOD system as of May 22, 2015. For the external system outside
New England, cases from the 2011 Multiregional Modeling Working Group (MMWG) case library were
used. After creating 2021 peak and off-peak load cases from MOD, the cases were merged with an
appropriate external case from ISO-NE’s 2014 August stability case library, to create final cases. Note
that the New England system topology is identical for both steady state and stability cases. The stability
model data from ISO-NE’s 2014 August stability library cases for 2018 Summer Peak and Light Load was
used as the starting point for the stability case development. The stability model data for the new
projects and changes to any existing facilities since August 2014 were incorporated.
1
http://www.iso-ne.com/committees/planning/planning-advisory
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1.1.3 Existing Facilities [R1.1.1]
Included in the base cases were all facilities that were in-service as of May 22, 2015 that were in the ISONE MOD system. Additionally, any updates to the model made between May 22, 2015 and June 30, 2015
were included. For existing facilities the ISO-NE MOD system relies on the NX-9 application to update
the topology information. The NX-9 application includes the transmission data that is collected in
accordance with ISO-NE Operating Procedure OP-162.
The voltage and reactive schedules for transmission devices like autotransformers and dynamic reactive
devices are based on voltage schedules that are published in the latest version (12/09/2014) of the ISONE Operating Procedure OP-12 Voltage and Reactive Control Appendix B3.
The following existing HVDC transmission facilities have models included for transient stability analysis:
1. Phase II
2. Cross Sound Cable
3. Highgate
Additionally, the following existing dynamic reactive devices have models included for transient stability
analysis:
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Chester SVC
Barnstable SVC
Essex STATCOM
Glenbrook STATCOM
Saco Valley Synchronous Condensers
Jay Synchronous Condenser
Granite Synchronous Condensers
Kibby Dynamic VAR device (DVAR)
Groton Dynamic VAR device (DVAR)
Granite Dynamic VAR device (DVAR)
As noted before, the stability model data from ISO-NE’s 2014 August stability library cases for 2018
Summer Peak and Light Load was used as the starting point for the stability case development. The
model data for the existing generators was based on the 2014 August stability cases with the exception
of units in Table 1 that had updates made to their models.
Table 1
Stability Model Updates to the Existing Generators
Generation Facilities
Bridgeport Energy Increase in CT
2
3
Description of Stability Model
Update
Updated model added
http://www.iso-ne.com/static-assets/documents/rules_proceds/operating/isone/op16/op16_rto_final.pdf
http://www.iso-ne.com/static-assets/documents/rules_proceds/operating/isone/op12/op12b_rto_final.pdf
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Generation Facilities
Skelton Station Modernization in ME
Bethlehem unit in NH
Cataract East unit in ME
Hemphill 1 unit in NH
DG Whitefield unit in NH
Northfield Mountain #2, #3, #4 Upgrades in MA
Pt. Lepreau unit in NB
ReEnergy Livermore Falls unit in ME
Westbrook Uprate in ME
Bull Hill Wind in ME
Kibby Wind in ME
Rollins Wind in ME
Stetson Wind in ME
Spruce Mountain Wind in ME
South Meadow Unit #5 Automatic Voltage Regulator (AVR)
replacement in CT
Description of Stability Model
Update
Updated model added
New model added (previously
no stability model was
available)
New model added (previously
no stability model was
available)
New model added (previously
no stability model was
available)
New model added (previously
no stability model was
available)
Updated model added
Updated model added
Updated model added
Updated model added
Updated model added
Updated model added
Updated model added
Updated model added
Updated model added
Updated model added
1.1.4 Long-Term Outages [R1.1.2]
To determine long-term outages with duration greater than six months in the system conditions being
tested in 2021, the June 2, 2015 Long-Term Outage Report was reviewed. There are no known long-term
outages of transmission or generation facilities with duration over six months for the particular study
periods, and hence no long-term outages were modeled in the base cases. This report is located in the
Operations Reports section of the ISO-NE website:
http://www.iso-ne.com/isoexpress/web/reports/operations/-/tree/long-trm-out-rpt
1.1.5 Transmission Topology Changes [R1.1.3]
The May 18, 2015 Regional System Plan (RSP) Project List4 was used to select transmission projects
included in the study base cases. All reliability upgrades (Table 1a and 1b) that were Proposed, Planned
and Under Construction were included in the study base cases.
4
http://www.iso-ne.com/static-assets/documents/2015/06/final_rsp15_project_list_may_2015.xls
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Two future reliability upgrades that were on the May 18, 2015 RSP Project List were excluded – RSP
1269 and RSP 1280. These projects are discussed in section 1.1.12.
In addition to the transmission topology changes, models for transient stability analysis were added for
the following dynamic reactive devices:
1. Ascutney Dynamic Voltage Support Device in VT (RSP 1615)
2. Coopers Mills STATCOM in ME (RSP 1643)
3. Stony Hill Synchronous Condenser (RSP 1578)
The following dynamic reactive devices that will be retired as a part of Southwest Connecticut (SWCT)
Transmission Upgrades were removed from the stability cases:
1. Stony Hill dynamic devices in CT
2. Bates Rock dynamic device in CT
A few other future dynamic reactive devices were added with the addition of certain approved queue
generators. These are included in the section on generation assumptions.
A data request for Local System Plan (LSP) projects that affect the BES was sent by the ISO on April 7,
2015 to Transmission Planners. This request was regarding projects that are not included in the RSP
Project List. Each Transmission Planner used their discretion for which LSP projects should be included. A
list of LSP projects that were provided by the Transmission Planners is included in Table 2. The list does
not include LSP projects that have an associated project on the May 18, 2015 RSP Project List:
Table 2
LSP Projects Included in Study
Transmission
Planner
VELCO
State
In-service Date
Project
VT
5/2016
Rutland-Florence 46 kV
Interconnection
VELCO
VT
5/2015
White River Substation
WMECO
MA
9/2015
UMASS-Amherst new
substation (Tillson Farm)
Solutions
Close normally open switches
Marble St 237 and West
Rutland 446. Reconductor 46
kV from West Rutland Tap Marble St - Proctor Tap to
Florence.
Add new 46/12.47 kV
substation called White River
Jct, transfer load from two
existing substations (Norwich
and White River), add new 46
kV capacitor bank (White River
Jct), and reconductor 46 kV
circuits (Taftsville - Quechee White River Jct - Norwich Tap)
UMASS-Amherst will be
constructing/owning/operating
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Transmission
Planner
State
In-service Date
Project
Solutions
a new 115/13.8 kV substation
with two 55 MVA transformers
and a circuit switcher at
Amherst
The transmission upgrades associated with the ISO-NE Interconnection Queue projects that had a
Proposed Plan Application (PPA) approval as of April 1, 2015 were included in the base cases. These
include dynamic devices associated with the following projects:
1. QP 273 – Addition of a dynamic device (Synchronous condenser) interconnecting to the Keene
Road 115 kV substation in ME
2. QP 333 – Addition of a dynamic device (SVC) at the Detroit 115 kV substation in ME
The basecases also include a detailed model for the 34.5 kV system in the Central Maine Power(CMP)
service area, based on data submitted by CMP.
1.1.6 Forecasted Load [R1.1.4]
The 2015 CELT report was used to obtain the forecast loads for the peak load study case. A 90/10
summer peak load was used for the peak case and a fixed load level of 12,500 MW was used for the offpeak case. Table 3 summarizes the load levels used in each case.
Table 3
Forecasted Load Levels
Year
2021 Peak
2021 Off-Peak
Load Level (MW)
32,676
12,500
1.1.7 Load Power Factor Assumptions [R1.1.4]
Load power factors consistent with the local Transmission Owner’s planning practices were applied
uniformly at each substation. Demand resource power factors were set to match the power factor of the
load at that bus in the model. A list of overall power factors by company territory can be found in the
detailed load report in Appendix A: Load Forecast.
1.1.8 Firm Transmission Service and Interchange [R1.1.5]
No firm transmission service or interchange was modeled in the study cases because ISO-NE does not
have advance firm transmission service arrangements. Please see “ISO-NE OATT Business Practices
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Section 1—OATT Transmission Services Summary5” for details on the transmission services provided by
ISO-NE.
1.1.9 Generation Assumptions [R1.1.6]
All existing generators that are included in the ISO-NE MOD system were included in the base cases. All
future generators in the ISO Interconnection Queue that had a PPA approval as of April 1, 2015 were
included in the base cases. One generator, QP 330, that had a PPA approval as of April 1, 2015 has since
withdrawn, and this unit has been placed out of service in the base cases and will not be assumed online
for any of the dispatches.
In addition, generators that do not have a PPA approval but have an obligation through the Forward
Capacity Market (FCM) were also included in the case. The following generators do not have PPA
approval but are included in the base cases since they cleared in the FCM:
1. QP 440 – Gas Turbine Expansion in New Haven county in CT
2. QP 444 – Gas Turbines in Norfolk county in MA
For the off-peak stability basecases, the maximum capability of all the units was modeled at its Network
Resource Capability (“NRC”) – winter rating. NRC Winter is the maximum amount of energy that a
generator has interconnection rights to provide in winter. It is measured as the net output at the Point
of Interconnection and represents the generator’s maximum output at or above 0 degrees Fahrenheit.
For the peak load stability basecases, the maximum capability of the units was determined by the status
of the unit in the FCM. Any unit that cleared in the FCM was modeled at its Summer Qualified Capacity
rating and a unit not in the FCM was modeled at its Capacity Network Resource Capability (CNRC) rating
(Maximum rating at 90 degrees or greater).
The reactive dispatch for the peak load case of the existing generators is based on the peak load voltage
schedules that are published in the latest version (12/09/2014) of the ISO-NE Operating Procedure OP12 Voltage and Reactive Control Appendix B6. The System Impact Study (SIS) data was used for any
future generator.
The reactive dispatch for the off-peak load case of the existing generators is based on the light load
voltage schedules that are published in the latest version (12/09/2014) of the ISO-NE Operating
Procedure OP-12 Voltage and Reactive Control Appendix B7. The SIS data was used for any future
generator.
5
http://www.iso-ne.com/static-assets/documents/trans/services/types_apps/rto_bus_prac_sec_1.doc
http://www.iso-ne.com/static-assets/documents/rules_proceds/operating/isone/op12/op12b_rto_final.pdf
7
http://www.iso-ne.com/static-assets/documents/rules_proceds/operating/isone/op12/op12b_rto_final.pdf
6
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Photovoltaic (PV) generation is modeled in the peak load base case. A description of the PV generation
modeling is included in section 1.1.11.
No PV generation is modeled in the off-peak load case since the load is assumed to be fixed at 12,500
MW of New England load.
The stability model data from ISO-NE’s 2014 August stability library cases for 2018 Summer Peak and
Light Load was used as the starting point for the stability case development. The stability model data for
the new projects and changes to the existing facilities since August 2014 were incorporated into the
original stability data. Table 4 shows some of these major updates to future generation projects or
future updates to existing generators:
Table 4
Stability Model Updates to Future Generation Projects or Future Stability Model Updates to
Existing Generators
Generation/Transmission Facilities
Gas Turbine Expansion in New Haven county in CT (QP 440)
Gas Turbines in Norfolk county in MA (QP 444)
Combined Cycle Expansion in Fairfield county in CT (QP 412)
Blue Sky West Wind in ME (QP 333)
Pisgah Mountain Wind in ME (QP 349)
Passadumkeag Wind in ME (QP 357)
Potter Repowering in MA (QP 438)
Wyman Hydro Uprate in ME (QP 366)
Northfield Mountain #1Upgrade in MA (QP 196)
Jericho Wind expansion in NH (QP 415-437)
Canton Wind Increase in ME (QP300-406)
Saddleback Wind Increase in ME (QP 287-407)
Description of Stability Model
Update
New model added
New model added
New model added
New model added
New model added
New model added
New model added
Updated model added
Updated model added
Updated model added
Updated model added
Updated model added
The below section shows some of the major stability models that were removed from ISO-NE’s 2014
August stability library cases for 2018 Summer Peak and Light Load. Table 5 shows the models that were
removed due to the fact that some of the future projects were cancelled from the RSP Project List or
withdrawn from the ISO-NE Interconnection Queue List. Table 6 shows the models that were removed
due to the upcoming retirements before the study year of 2021.
Table 5
Stability Model Updates for Withdrawn/Cancelled Projects
Generation/Transmission Facilities
Description of Stability Model
Update
Model removed (Withdrawn
Project)
Deerfield Wind in VT (QP 276)
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Generation/Transmission Facilities
Description of Stability Model
Update
Model removed (Withdrawn
Project)
Model removed (Withdrawn
Project)
Model removed (Cancelled
Project per March 2015 RSP
Project List)
Bowers Wind in ME (QP 327)
Fair Haven Biomass in VT (QP 330)
Northern Pass HVDC in NH (QP 348)
Table 6
Stability Model Updates for Upcoming Retirements
Generation/Transmission Facilities
PPL Great Works - Red Shield in ME
Brayton Point Units (#1, #2, #3, #4) in MA
Brayton Point Exciter Model Replacement (QP 347) in MA
Mount Tom Unit in MA
Norwalk Harbor Units #1, #2, #10 in CT
Medway Diesel unit in ME
Wallingford Refuse unit in CT
PPL Veazie unit in ME
Bar Harbor Diesel unit in ME
Brayton Point Diesel units in MA
Claremont unit in VT
Description of Stability Model
Update
Model removed (Effective
Retirement Date of 6/1/2018)
Models removed (Effective
Retirement Date of 6/1/2017)
Models removed (Effective
Retirement Date of 6/1/2017)
Model removed (Effective
Retirement Date of 6/1/2018)
Model removed (Effective
Retirement Date of 6/1/2017)
Model removed (Effective
retirement date of 6/1/2017)
Model removed (Effective
retirement date of 6/1/2018)
Model removed (Effective
retirement date of 6/1/2017)
Model removed (Effective
retirement date of 6/1/2017)
Model removed (Effective
retirement date of 6/1/2017)
Model removed (Effective
retirement date of 6/1/2018)
Power system software tool PSS/E’s “GNET” function is typically used during stability simulations to
convert the generators to negative loads if they do not have a dynamic model available or have
insufficient dynamic model data. There were certain generators GNETed (i.e. converted to negative
loads during simulations) in ISO-NE’s 2014 August stability library cases for 2018 Summer Peak and Light
Load. Note that the units that were GNETed are smaller than 20 MVA for the unit and 75 MVA for the
plant satisfying the NERC requirement.
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As a part of this NERC TPL stability case building, the following two future generators were added to the
list of GNETed generators:
1. Block Island Wind Farm in RI (QP 405): This is a 30 MW future offshore wind farm that will be
interconnected in the town of New Shoreham in Block Island, RI. Due to insufficient stability
data, this unit was GNETed in the stability cases. No significant impact is expected to the
stability analyses for the transmission system as this unit will be interconnected to the subtransmission network.
2. Harrington Street PV Project in MA (QP 377): This is a 6 MW Photovoltaic Interconnection
project in East Brookfield, MA. Due to insufficient stability data, this unit was GNETed in the
stability cases. No significant impact is expected to the stability analyses for the transmission
system due to its smaller size.
Some important comments while using the stability cases are provided in Appendix D: General
Comments on Stability Cases.
1.1.10 Demand Resource Assumptions [R1.1.6]
Demand resources (DR) were only modeled for the peak load case since the off-peak load case at 12,500
MW includes the impact of all DR. Demand resources that are modeled in the study can be divided into
three categories:
1. Passive DR that cleared in the Forward Capacity Market through FCA 9 (June 1, 2018 – May 31,
2019)
2. Active DR that cleared in the Forward Capacity Market through FCA 9 (June 1, 2018 – May 31,
2019)
3. 2015 CELT Energy Efficiency (EE) forecast for the period beyond May 31, 2019.
The following table shows the performance assumption for each category of DR that is included in the
peak load base case. Real-Time Emergency Generation (RTEG) was not modeled in these analyses. RTEG
that cleared in the FCM was not included in the reliability analyses because long term planning analyses
should not be performed such that the system must be in an emergency state as required for the
implementation of OP-4, Action 6. Performance Assumption (PA) factors are based on the expected
performance of DR after receipt of instructions to dispatch. For Passive DR and forecasted EE the PA
factor is assumed to be 100% since the DR programs are already installed and automatically reduce load.
For Active DR, the PA factor is assumed to be 75%. This is based on historical response rates.
Table 7
New England Demand Resource Performance Assumptions
Load Level
Summer Peak (90/10)
Passive DR
100%
Active DR
75%
Forecasted EE
100%
RTEGs
0%
The details of the demand resources modeled is included in Appendix B: Demand Resources. A summary
of the DR modeled across New England is provided in the tables below. Note that FCA9 DR refers to the
sum of the qualified capacities of existing DR in FCA9 and the newly cleared DR in FCA9.
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Table 8
Passive DR Modeled in the Peak Load Case
Study Year
Passive DR
New England
FCA 9 Passive DR (DRV)
5.5% Distribution Losses
Passive DR Modeled in Case
2021 Peak
2135
116
2252
Table 9
EE Forecast Modeled in the Peak Load Case
Study Year
EE Forecast
New England
EE Forecast for years 2019 - Study Year (DRV)
5.5% Distribution Losses
EE Forecast Modeled in Case
2021 Peak
644
35
680
Table 10
Active DR Modeled in the Peak Load Case
Study Year
Active DR
New England
FCA9 Active DR (DRV) in New England
5.5% Distribution Losses
Unavailable Active DR (25%)
Active DR Modeled in Case
2021 Peak
484
+ 27
-128
383
1.1.11 Market Solution Consideration [R1.1.6]
In addition to the resources that cleared the FCM, the PV generation forecast was used to model PV
generation in the summer peak load case. Similar to DR, the PV generation forecast was only modeled
for the summer peak load case. The 2015 CELT PV generation forecast includes the PV generation that
has been installed as of the end of 2014 and provides a forecast by state of the total PV (by AC
Nameplate8) that is expected to be in-service by the end of each forecast year for the next 10 years. As
an example the 2015 PV forecast provides the PV that is in-service as of the end of 2014 as well as
provides an annual forecast for the PV that will be in-service for end of 2015, end of 2016 and so on until
the end of 2024.
8
AC nameplate is the nameplate output of a PV facility as measured on the AC side of the inverter.
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An availability factor of 26% was applied to the values from the PV generation forecast. The details of
the PV generation modeling are included in Appendix C: PV generation modeling. Table 11 summarizes
the PV generation modeled for the peak load case.
Table 11
PV generation Modeled in the Peak Load Case
PV generation Modeled as Negative Loads
New England
A - PV generation (nameplate) in New England
B - 5.5% Reduction in Distribution Losses
C - Unavailable PV generation (A+B)*(1-26%)
PV generation Modeled in Case as Negative Loads (A+B)-C
Study Year
2021 Peak
1694
93
1322
465
1.1.12 Explanation of Future Changes Not Included
Two transmission projects listed on the May 18, 2015 RSP Project List were not included in the study
cases:


RSP 1269: The project to add a new 345 kV breaker and two 25 MVAR capacitor banks at the
Amherst substation in New Hampshire was not included because the Transmission Owner has
raised concerns regarding the feasibility of implementing the Amherst 345 kV capacitor banks
proposed in the previous New Hampshire/Vermont Solutions Study.
RSP 1280: The project to add a new 115 kV line section 244 and upgrading line section 80
between Coopers Mill and Highland Substations was not included because the Transmission
Owner indicated that the project may not move forward.
1.1.13 Load Levels Studied [R2.1.1, R2.1.2 and R2.2]
This section summarizes the net load level studied for each base case. The tables below exclude the
Station Service loads which vary based on dispatch assumptions.
Table 12: Net Load Modeled for 2021 peak load (Excludes Transmission Losses)
Category
90/10 CELT Forecast
Non-CELT Manufacturing load in New England
Available FCA-9 Passive DR (modeled as negative load)
Available FCA-9 Active DR (modeled as negative load)
Available 2015 CELT EE Forecast for year 2021 (modeled as negative load)
Available 2015 CELT PV Forecast for year 2021 (modeled as negative load)
Net load modeled in New England (Excludes Station Service Load)
Load (MW)
32,676
364
-2,252
-383
-680
-465
29,260
Table 13: Net Load Modeled for 2021 off-peak load (Excludes Transmission Losses)
Category
90/10 CELT Forecast
Load (MW)
11,857
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Non-CELT Manufacturing load in New England
Available FCA-9 Passive DR (modeled as negative load)
Available FCA-9 Active DR (modeled as negative load)
Available 2015 CELT EE Forecast for year 2021 (modeled as negative load)
Available 2015 CELT PV Forecast for year 2021 (modeled as negative load)
Net load modeled in New England (Excludes Station Service Load)
364
0
0
0
0
12,219
1.1.14 Dynamic Load Model[R2.4.1]
A dynamic load model was added to the peak load stability case to model the dynamic behavior of Loads
that could impact the study area, including the consideration of the behavior of induction motor Loads.
The breakdown of the load components for use with the WECC dynamic load model for New England is
based on a report that was prepared by DNV-GL for Lawrence Berkeley National Laboratory. The report
was titled “End Use Data Development for Power System Load Model in New England – Methodology
and Results9”. As a part of this report the New England load was characterized by:
1. Summer peak and Spring Light Load hour
2. Seven geographic areas - Maine, New Hampshire, Vermont, Connecticut, Rhode Island, Eastern
Massachusetts and Western Massachusetts
3. Customer sector – Residential, Commercial and Industrial
4. Electrical end use categories specific to each customer sector
5. Load components of the Western Electric Coordinating Council (WECC)
The following bar chart summarizes the distribution of New England summer peak load in the seven
regions into the 7 components of the WECC load model.
9
http://eetd.lbl.gov/sites/all/files/data-development-for-ne-end-use-load-modeling.pdf
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At the time of commencing this analysis the ISO has not completed the benchmarking of the WECC
dynamic load model for stability studies. Since the requirement R2.4.1 requires a dynamic load model
that includes the behavior of induction motors, an equivalent dynamic model that would represent
induction motors is being used for this analysis for the interim period before the WECC load model has
been benchmarked and verified. The PSS/E standard complex load model (CLOD model) was used to
perform this interim representation.
The CLOD model has the following components: Large motor, small motor, discharge lighting,
transformer saturation, constant MVA loads and remaining loads.
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Figure 1: CLOD Model Parameters
The WECC load model has the following parameters
Figure 2: WECC Load Model parameters
Since a direct translation of model parameters from the WECC load model to the CLOD model was not
available, the ISO has made some assumption on how the parameters in the WECC load model are
converted to the CLOD model. The following section describes the assumption made and the basis for
each assumption.
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The following sections describes the different motor models in the WECC composite load model and the
source is the WECC MVWG Load Model Report ver.1.010




Motor A (MA) is representative of the across-the-line connected three-phase compressor motors
used in air-conditioners and refrigerators. The driven load is constant torque.
Motor B (MB) is representative of the across-the-line connected fan motors. The driven load is
speed-dependent, proportional to speed squared.
Motor C (MC) is representative of pump motors. The model data is similar to Motor B, except for
lower inertia.
Motor D (1-phase) is a representation of single-phase residential air-conditioners
The assumption is made that Motor A and Motor C represent small three-phase motors and Motor B
represents large three-phase motors in the CLOD model. The following table shows a comparison of the
parameters of Motor A, Motor B, and Motor C based on the WECC MVWG Load Model Report. The
details can be found in the report, but in summary:



MA and IA correspond to Motor A,
MB and IB correspond to Motor B, and
MC and IC correspond to Motor C.
Based on the close inertia constants of Motor A and Motor C which is significantly lower than the inertia
constant for Motor B, Motor A and C are categorized as small motors and Motor B is classified as a large
motor.
10
https://www.wecc.biz/Reliability/WECC%20MVWG%20Load%20Model%20Report%20ver%201%200.pdf
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Note that since single phase motors are not explicitly modeled in the CLOD model, these single phase
units are also modeled as small three-phase motors. In summary, the following conversion is used for
the motor loads:


Percentage of Large Motors = Percentage of Motor B
Percentage of Small Motors = Percentage of Motor A + Percentage of Motor C + Percentage of
Motor D
The next component in the WECC load model is the “Electronics load” component. The following is an
excerpt from the WECC MVWG load model report for the behavior of electronic loads:

Power Electronic loads - BPA tested Variable Frequency Drives, PCs and TVs in its laboratory.
Power electronic loads behave as a constant power with respect to voltage and frequency. Power
electronic loads operate close to unity power factor at the fundamental frequency. Electronic
loads trip for low voltage condition at higher levels, usually 55% to 70%.
The closest equivalent component to this performance in the CLOD model is that of the constant MVA
load. It is a more conservative model than the behavior described above.
The static component in the WECC load model consists of two different types of static loads – Constant
current loads and constant impedance loads. The following excerpt from the WECC MVWG load model
report describes what these loads consist of:


A constant current component is representative of fluorescent lighting with electronic ballast,
which is the majority of commercial lighting today. Ballast lights stay on until very low voltages,
10% to 15%.
A constant impedance component is representative of resistive loads such as incandescent
lighting, resistive water heating, resistive space heating, and resistive cooking.
The discharge lighting model within the CLOD model has the following parameters11:
1. Real part of load as constant current.
2. Imaginary part of load as the voltage raised to the power of 4.5.
3. For voltage between 0.65 and 0.75 per unit, the real and imaginary loads are modeled as
explained in the previous items (1. and 2.) with a linear reduction applied corresponding to the reduced
voltage
4. For voltage below 0.65 per unit, the lighting is assumed to be extinguished (i.e., no load).
If we assume the constant current load under the WECC composite model is modeled as a discharge
lighting component in the CLOD model we would see a difference in the performance between the two
models depending on the system voltages. Since the CLOD discharge lighting model would disconnect at
voltage below 0.65 p.u., and the WECC load would stay connected, for voltages below 0.65 p.u., the
11
PSS®E 32.0.5 – Program Application Guide Volume II
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WECC load model would give a worse response than the CLOD model. However, at voltages between
0.65 p.u. and 0.75 p.u. the real power loads in the CLOD model will be lower than the WECC model and
at voltages above 0.75 p.u. the real power loads would be the same for both models. The reactive power
would be lower for the discharge lighting model in the CLOD model than the WECC model at all voltages
below 1 p.u.
However, given that a large part of New England has good load power factors (>0.99 p.u.) the impact of
this reduced reactive and real power at lower loads is not expected to be significant. Further, the
reduction of electronic loads at low voltages and the potential tripping of motor loads with low voltages
is not modeled with the CLOD model and the additional conservativism in modeling motor loads and
electronic loads is expected to offset the reduced constant current loads modeled in the CLOD model. In
summary, the constant current load component in the WECC composite load model will be modeled as a
discharge lighting load in the CLOD equivalent model.
The only remaining component is the constant impedance component in the WECC composite load
model. This component is modeled as a voltage sensitive load in the CLOD model where the load is set
to vary by square of the voltage.
There is no component in the WECC composite load model to represent transformer saturation. Hence
the transformer saturation component of the CLOD dynamic load model is set to 0.
In summary, the following methodology was used to convert the WECC composite load model
parameters to the CLOD parameters:






Percentage of Large Motors = Percentage of Motor B
Percentage of Small Motors = Percentage of Motor A + Percentage of Motor C + Percentage of
Motor D
Constant MVA = Electronics
Discharge Lighting = Constant Current Load
Transformer Saturation = 0
Remaining Loads = Constant Impedance Loads with a Kp of remaining loads = 2 (for constant
impedance loads)
Two other parameters that are a part of the CLOD model but do not deal with the load components is
the R+jX parameter that could be used to account for feeder impedances. The loads included in the
basecases inherently account for distribution losses and hence no additional modeling of feeder
impedances will be included in these basecases. It should be noted that for a majority of the New
England loads the step-down transformers from transmission to sub-transmission levels (46 kV and
below) is included in the basecases.
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Once we have established the methodology to convert the WECC composite load model parameters to
the CLOD complex load model parameters the next step is to use the WECC composite load components
from the New England end use load model to determine the actual components.
New England loads consist of the following components:
1. CELT load for the six New England states
2. Passive DR, Active DR and EE forecast for the six New England states modeled as negative
loads
3. PV forecast modeled as negative loads
4. Manufacturing loads in ME (Non-CELT)
5. Station Service loads
The first step in the load modeling was to eliminate all the negative loads associated with demand
resources by reducing the load at the different buses by an equivalent amount. The next step was to
reclassify all the New England CELT loads into the 7 regions defined in the New England end-use load
model report. The CELT loads were reclassified into the following owners:
1.
2.
3.
4.
5.
6.
7.
Owner 60 – ME CELT loads net of DR
Owner 61 – NH CELT loads net of DR
Owner 62 – VT CELT loads net of DR
Owner 63 – Eastern MA CELT loads net of DR
Owner 64 – Western MA CELT loads net of DR
Owner 65 – Rhode Island CELT loads net of DR
Owner 66 – Connecticut CELT loads net of DR
The remaining non-negative loads are either Manufacturing loads in ME or station service loads across
New England. To determine the components of the WECC load model that correspond to these loads
the equivalent parameters of all the industrial load in New England was used. The following table
summarizes the estimated Industrial Peak hour load component distribution.
The total New England component distribution was used to assign the remaining manufacturing and
station service loads. These loads were modeled under owner 67.
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The only remaining loads in the case are negative loads corresponding to PV loads and one negative load
associated with equivalent generation in ME. Some limited number of loads in the case with zero real
power output was given owner 69 and no dynamic loads were applied to these loads Since a large
majority of the residual load is inverter based PV, all these loads are modeled using a ZIP load model
with constant current characteristics for real and reactive power. . These reactive loads were modeled
as constant impedance loads.
The final table below shows the different components in the CLOD model for the different areas and
loads in New England:
Owner
ID
Large
Motor
(Motor A +
Motor B)
Maine
New
Hampshire
60
12.09%
42.62%
11.86%
61
11.97%
42.19%
12.78%
Vermont
Massachusetts
- East
Massachusetts
- West/Central
62
11.22%
45.61%
12.15%
63
12.27%
47.58%
11.59%
64
13.19%
48.27%
10.20%
Region
Small
Motor
(Motor C +
Motor D)
Discharge
Lighting
(Constant I)
Transf.
Saturati
on
0%
0%
Constant
MVA
(Electronics)
Other
(Constant
Z)
Kp
15.95%
17.48%
2
15.74%
17.32%
2
15.13%
15.90%
2
15.82%
12.75%
2
14.43%
13.91%
2
14.12%
14.34%
2
17.60%
13.08%
2
20.19%
14.84%
2
0%
0%
0%
0%
Rhode Island
65
13.07%
47.58%
10.89%
Connecticut
New England
Manufacturing
+ SS loads
(Non-CELT)
Negative load
for generation
in ME
Limited
number of
loads with no
real power
component
66
11.77%
45.43%
12.11%
67
8.93%
54.06%
1.99%
0%
PV Gens as
Negative loads
0%
68
Modeled as ZIP loads with constant current characteristics for P and Q
69
Modeled as ZIP loads with constant current characteristics for P and Q
94
Modeled as ZIP loads with constant current characteristics for P and Q
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1.1.15 Low Voltage Ride Through Capability [R4.3.1.2]
Some of the units modeled in the stability basecases have relays that model generator tripping based on
actual low voltage ride through capability. However, the majority of the units do not have protection
systems modeled for this purpose. Figure 3-1 below shows the no-trip zone based on PRC-024-1. Since
PRC-024-1 has an enforcement date of July 1, 2016 the ISO does not have specific low voltage trip set
points for generators. A conservative assumption is made that all generators that do not have low
voltage ride through based tripping modeled, the generator would trip for low voltages below the curve
shown in Figure 3 below. An assumption was made that the protection relays would monitor the voltage
at the high side of the GSU for each unit and trip if the high side of the GSU voltage is below the curve.
The PSS/E generic model for Under/Over voltage generator trip relay (VTGTPA) was used. Four relays
were used for each generator to simulate the four sections of the curve in Figure 3.
Figure 3: PRC-024 Voltage No-Trip Zone
1.1.16 Line Relay Models [R4.3.1.3].
The out-of-step scanning model (OSSCAN) will be used to scan the entire network for out-of-step
conditions. With this model, whenever the apparent impedance as seen from either end of a line is less
than the line impedance, the line is flagged as out of step. The model will only be activated after the last
element cleared by protection is tripped.
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Additionally, the following specific relay models were included based on data provided by the
transmission owners:
1. PV20 Plattsburg - Sandbar Overload Mitigation System (OMS) relay model
2. 345 kV line 326 Special Protection System (SPS) thermal mode relay model
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Section 2
Appendix A: Load Forecast
2021 Summer Peak Load
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2021 Off-Peak Load
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Section 3
Appendix B: Demand Resources
The following three tables indicate how each DR type is modeled in the peak load base case. The DR
modeled in the peak load case by load zone is provided. The DR values that are released as a part of the
FCA results and the 2015 CELT EE forecast have transmission and distribution losses (8%) included. For
modeling in the study base case, only the distribution losses (assumed to be 5.5%) will be added to the
DR since the transmission losses (2.5%) will be computed by the simulation software.
Table 14:
Passive DR Modeled in the Peak Load Case
Passive DR
Study Year
Load Zone
2021 Peak
FCA 9 Passive DR (DRV)
5.5% Distribution Losses
Passive DR Modeled in Case
FCA 9 Passive DR (DRV)
Maine
5.5% Distribution Losses
Passive DR Modeled in Case
FCA 9 Passive DR (DRV)
New
5.5% Distribution Losses
Hampshire
Passive DR Modeled in Case
FCA 9 Passive DR (DRV)
Vermont
5.5% Distribution Losses
Passive DR Modeled in Case
FCA 9 Passive DR (DRV)
Rhode Island
5.5% Distribution Losses
Passive DR Modeled in Case
FCA 9 Passive DR (DRV)
NEMA/BOSTON 5.5% Distribution Losses
Passive DR Modeled in Case
FCA 9 Passive DR (DRV)
SEMA
5.5% Distribution Losses
Passive DR Modeled in Case
FCA 9 Passive DR (DRV)
WCMA
5.5% Distribution Losses
Passive DR Modeled in Case
FCA 9 Passive DR (DRV)
New England
5.5% Distribution Losses
Passive DR Modeled in Case
Connecticut
425
+ 23
449
168
+9
177
95
+5
100
117
+6
123
189
+ 10
199
527
+ 29
556
284
+ 16
300
331
+ 18
349
2135
116
2252
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Table 15:
EE Forecast Modeled in the Peak Load Case
EE Forecast
Load Zone
EE Forecast for years 2019 - Study Year (DRV)
Connecticut
5.5% Distribution Losses
EE Forecast Modeled in Case
EE Forecast for years 2019 - Study Year (DRV)
Maine
5.5% Distribution Losses
EE Forecast Modeled in Case
EE Forecast for years 2019 - Study Year (DRV)
New
5.5% Distribution Losses
Hampshire
EE Forecast Modeled in Case
EE Forecast for years 2019 - Study Year (DRV)
Vermont
5.5% Distribution Losses
EE Forecast Modeled in Case
EE Forecast for years 2019 - Study Year (DRV)
Rhode Island
5.5% Distribution Losses
EE Forecast Modeled in Case
EE Forecast for years 2019 - Study Year (DRV)
NEMA/BOSTON 5.5% Distribution Losses
EE Forecast Modeled in Case
EE Forecast for years 2019 - Study Year (DRV)
SEMA
5.5% Distribution Losses
EE Forecast Modeled in Case
EE Forecast for years 2019 - Study Year (DRV)
WCMA
5.5% Distribution Losses
EE Forecast Modeled in Case
EE Forecast for years 2019 - Study Year (DRV)
New England
5.5% Distribution Losses
EE Forecast Modeled in Case
Study Year
2021 Peak
137
+8
145
41
+2
43
27
+1
28
42
+2
44
56
+3
60
157
+9
166
85
+5
90
99
+5
105
644
35
680
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Table 16:
Active DR Modeled in the Peak Load Case
Active DR
Load Zone
Connecticut
Maine
New Hampshire
Vermont
Rhode Island
NEMA/BOSTON
SEMA
Study Year
2021 Peak
FCA 9 Active DR (DRV) in dispatch zone Eastern Connecticut
FCA 9 Active DR (DRV) in dispatch zone Northern Connecticut
FCA 9 Active DR (DRV) in dispatch zone Norwalk-Stamford
FCA 9 Active DR (DRV) in dispatch zone Western Connecticut
FCA 9 Active DR (DRV) in load zone of Connecticut
5.5% Distribution Losses
Unavailable Active DR (25%)
Active DR Modeled in Case
FCA 9 Active DR (DRV) in dispatch zone Emera Maine
FCA 9 Active DR (DRV) in dispatch zone Maine
FCA 9 Active DR (DRV) in dispatch zone Portland ME
FCA 9 Active DR (DRV) in load zone of Maine
5.5% Distribution Losses
8
28
3
32
72
+4
-19
57
27
97
17
141
+8
Unavailable Active DR (25%)
-37
Active DR Modeled in Case
FCA 9 Active DR (DRV) in dispatch zone New Hampshire
FCA 9 Active DR (DRV) in dispatch zone Seacoast
FCA 9 Active DR (DRV) in load zone of New Hampshire
5.5% Distribution Losses
Unavailable Active DR (25%)
Active DR Modeled in Case
FCA 9 Active DR (DRV) in dispatch zone Northwest Vermont
FCA 9 Active DR (DRV) in dispatch zone Vermont
FCA 9 Active DR (DRV) in load zone of Vermont
5.5% Distribution Losses
Unavailable Active DR (25%)
Active DR Modeled in Case
FCA 9 Active DR (DRV) in dispatch zone Rhode Island
FCA 9 Active DR (DRV) in load zone of Rhode Island
5.5% Distribution Losses
Unavailable Active DR (25%)
Active DR Modeled in Case
FCA 9 Active DR (DRV) in dispatch zone Boston
FCA 9 Active DR (DRV) in dispatch zone North shore
FCA 9 Active DR (DRV) in load zone of NEMA/BOSTON
5.5% Distribution Losses
Unavailable Active DR (25%)
Active DR Modeled in Case
FCA 9 Active DR (DRV) in dispatch zone Lower SEMA
FCA 9 Active DR (DRV) in dispatch zone SEMA
FCA 9 Active DR (DRV) in load zone of SEMA
5.5% Distribution Losses
Unavailable Active DR (25%)
Active DR Modeled in Case
111
13
2
15
+1
-4
12
25
5
30
+2
-8
24
56
56
+3
-15
44
50
18
68
+4
-18
54
7
41
48
+3
-13
38
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Active DR
Load Zone
WCMA
New England
Study Year
2021 Peak
FCA 9 Active DR (DRV) in dispatch zone Central MA
FCA 9 Active DR (DRV) in dispatch zone Springfield
FCA 9 Active DR (DRV) in dispatch zone Western MA
FCA 9 Active DR(DRV) in load zone of WCMA
5.5% Distribution Losses
Unavailable Active DR (25%)
Active DR Modeled in Case
FCA 9 Active DR (DRV) in New England
5.5% Distribution Losses
Unavailable Active DR (25%)
Active DR Modeled in Case
32
8
15
55
+3
-15
44
484
+ 27
-128
383
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Section 4
Appendix C: PV generation Modeling
As part of the 2015 PV forecast the data on PV generation was divided into the following mutually
exclusive categories:




PV as a capacity resource in the Forward Capacity Market (FCM)
Non-FCM Settlement only Resources (SOR) and Generators (per OP-14)
Behind-the-Meter (BTM) PV Embedded in Load (BTMEL)
BTM PV Not Embedded in Load (BTMNEL)
Of the four categories, the BTMNEL is already embedded in the CELT forecast and hence will not be
modeled explicitly in any studies. The remaining three categories need to be considered when
accounting for PV generation in studies.
The PV generation forecast only forecasts the PV values on a state-wide basis. However, within a state
the PV does not grow uniformly, with some areas in the state having larger amounts of PV. To account
for this locational variation of PV, the locational data of existing PV that is in-service as of the end of
2014 was utilized to obtain the percentage of PV that is in each dispatch zone. New England is divided
into 19 dispatch zones and the percentage of PV in each dispatch zone as a percentage of total PV in the
state is available. This percentage is assumed to stay constant for future years to allocate future PV to
the dispatch zones. The percentage of existing solar in each dispatch zone as of the end of each year
that is used as a part of the PV generation forecast is based on Distribution Owner interconnection data
and the materials are located at:
http://www.iso-ne.com/system-planning/system-forecasting/distributed-generation-forecast
Once the PV generation data is organized by dispatch zone, the PV within the dispatch zone falls into
three categories:
•
•
•
Category 1 : Units greater than 5MW:
– Location data available
– Will be modeled as an individual generators
– 13 MW of PV in MA are the only resources that fall into this category
Category 2 : Units greater than 1 MW and less than 5 MW
– Location data available through the PPA notifications
– Needs to be modeled as injections at specific locations – Negative loads similar to DR
Category 3: Units below 1 MW
– No location data available
– Needs to be modeled by spreading the MWs across the dispatch zone – Negative loads
similar to DR and spread across the load zone/dispatch zone like DR is spread
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For PV in categories 2 and 3 the PV will be modeled as negative loads at the buses. The power factor of
the negative load will be set to match the power factor of the load at the bus. If no load is present at the
bus then a unity power factor will be assumed.
Based on a review of historic PV outputs, ISO-NE Transmission Planning has determined a 26%
availability factor is applied to all categories of modeled PV generation in transmission planning studies.
The following table shows the PV generation modeled in the peak load case. Note that since the PV
generation data is nameplate AC, a 5.5% gross up was performed to the PV generation forecast to
account for avoided distribution losses.
Table 17: PV generation Modeled in the Peak Load Case
PV generation Modeled as Negative Loads
Study
Year
Load Zone
2021
Peak
Connecticut
Maine
New
Hampshire
PV generation (nameplate) in dispatch zone Eastern
Connecticut
PV generation (nameplate) in dispatch zone Northern
Connecticut
PV generation (nameplate) in dispatch zone NorwalkStamford
PV generation (nameplate) in dispatch zone Western
Connecticut
A - Total PV generation (nameplate) in load zone of
Connecticut
B - 5.5% Reduction in Distribution Losses
C - Unavailable PV generation (A+B)*(1-26%)
PV generation Modeled in Case as Negative Loads(A+B-C)
PV generation (nameplate) in dispatch zone Emera Maine
PV generation (nameplate) in dispatch zone Maine
PV generation (nameplate) in dispatch zone Portland ME
A - Total PV generation (nameplate) in load zone of Maine
B - 5.5% Reduction in Distribution Losses
C - Unavailable PV generation (A+B)*(1-26%)
PV generation Modeled in Case as Negative Loads(A+B-C)
PV generation (nameplate) in dispatch zone New Hampshire
PV generation (nameplate) in dispatch zone Seacoast
A - Total PV generation (nameplate) in load zone of New
Hampshire
B - 5.5% Reduction in Distribution Losses
C - Unavailable PV generation (A+B)*(1-26%)
PV generation Modeled in Case as Negative Loads(A+B-C)
71
78
29
178
356
20
278
98
2
4
2
8
+0
-6
2
23
3
26
+1
-20
7
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PV generation Modeled as Negative Loads
Study
Year
Load Zone
2021
Peak
PV generation (nameplate) in dispatch zone Northwest
Vermont
PV generation (nameplate) in dispatch zone Vermont
A - Total PV generation (nameplate) in load zone of Vermont
Vermont
B - 5.5% Reduction in Distribution Losses
C - Unavailable PV generation (A+B)*(1-26%)
PV generation Modeled in Case as Negative Loads(A+B-C)
PV generation (nameplate) in dispatch zone Rhode Island
A - Total PV generation (nameplate) in load zone of Rhode
Island
Rhode Island
B - 5.5% Reduction in Distribution Losses
C - Unavailable PV generation (A+B)*(1-26%)
PV generation Modeled in Case as Negative Loads(A+B-C)
PV generation (nameplate) in dispatch zone Boston
PV generation (nameplate) in dispatch zone North shore
A - Total PV generation (nameplate) in load zone of
NEMA/BOSTON NEMA/BOSTON
B - 5.5% Reduction in Distribution Losses
C - Unavailable PV generation (A+B)*(1-26%)
PV generation Modeled in Case as Negative Loads(A+B-C)
PV generation (nameplate) in dispatch zone Lower SEMA
PV generation (nameplate) in dispatch zone SEMA
A - Total PV generation (nameplate) in load zone of SEMA
SEMA
B - 5.5% Reduction in Distribution Losses
C - Unavailable PV generation (A+B)*(1-26%)
PV generation Modeled in Case as Negative Loads(A+B-C)
PV generation (nameplate) in dispatch zone Central MA
PV generation (nameplate) in dispatch zone Springfield
PV generation (nameplate) in dispatch zone Western MA
WCMA
A - Total PV generation (nameplate) in load zone of WCMA
B - 5.5% Reduction in Distribution Losses
C - Unavailable PV generation (A+B)*(1-26%)
PV generation Modeled in Case as Negative Loads(A+B-C)
A - PV generation (nameplate) in New England
B - 5.5% Reduction in Distribution Losses
New England
C - Unavailable PV generation (A+B)*(1-26%)
PV generation Modeled in Case as Negative Loads(A+B-C)
115
62
177
+ 10
-138
48
144
144
+8
-113
40
101
53
154
+8
-120
42
175
202
377
+ 21
-294
103
171
59
221
451
+ 25
-352
124
1694
+ 93
-1322
465
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Section 5
Appendix D: General Comments on Stability Cases

Per the latest approved models, Kingdom Wind (KCW), Bull Hill Wind, and Pisgah Wind use
VESTASWT_7_4_4 models. KCW, however, has a customized version of this model owing to
its configuration. It appears that KCW cannot be dispatched with Bull Hill Wind or Pisgah
Wind online in the same case. Transmission planning is working with the developer to
resolve this issue. In the interim, though, these three plants have been included and
compiled in the case, with Bull Hill Wind and Pisgah Wind turned off. KCW unit can be
dispatched in this stability package.
Some cases may issue the following message during initialization.
“BUS 103140 [BULLHLL_GEN 0.6500] MC 1 USER DEFINED MACHINE MODEL "VWEX1" NOT
ACCESSIBLE”
You may also see the following suspect initial condition.
I DSTATE(I) STATE(I) MODEL STATE BUS# X-- NAME --X BASKV ID
117597 0.10000E+00 -0.19817E-05 VWGOV K+3 103140 BULLHLL_GEN 0.6500 1
Please note that that these messages have no bearing on the simulations.
PSS/E v32.2 has been used to create the stability cases. Please make sure that the bus dimension is
set to 150,000 (BUSES 150000) before running a simulation. Steps for running the simulation:
1. Open PSS/E saved case from the received package.
2. After making any study specific dispatch changes run the ‘convert.idv’ automation file and
save the converted case.
3. Load the converted case and the snapshot provided to run simulation.
Note 1: The files “oel_uel.dll” and “URRTGT_rev32.dll” are user-written library models for certain
units, and are not part of the main dsusr.dll. These files must be present in the same directory as
the “dsusr.dll” file, and must be loaded into PSS/E during stability simulations. One of the
following methods can be used to load these additional dll files:
a. Go to PSS/E Tools – Load Model Library, and load these two libraries separately. The
main dll file “dsusr.dll” will be loaded automatically as long as it is in the same directory
b. Alternatively, you can use the following command BAT_ADDMODELLIBRARY in the PSAS
file to load these dll files separately. Please remember to update the directory locations
where the dll files are located. For example:
BAT_ADDMODELLIBRARY,'C:\xxx\xxx\xxx\xxx\xxx.dll'
Note 2: Initialization errors can occur if the steady state reactive output of the Marcy, Fraser, or
Leeds SVCs in NYISO is too high. Moreover, some minor machine rotor angle deviations were
observed during the ring down test of the stability package when the Coopers Mills STATCOM
output is not near 0 MVAR or when the Detroit SVC output is not above 0 MVAR.
“NYSVC_plus.py” reduces the 3 NYISO and Coopers Mills svc/facts reactive output to zero by
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changing their voltage schedules equal to what is in the open case. This python file sets the
output of the Detroit SVC to 10 MVAR by modifying the voltage schedule. This python file should
be run after making significant dispatch changes, especially of NY and ME machines. Note that
this python file solves the case with the following solution options: transformers regulating,
switched shunts regulating, phase angle regulators regulating, and area interchange enabled. If
different solution options are used then the python file will need to be modified accordingly.
Note 3: The file “V82BCPMX1.DAT,” must be present in the same directory as the DSUSR.dll,
otherwise PSS/E dynamics crashes. This file links to certain Vestas wind farm models.
Note 4: The file “CP_GW90.txt” must be included in same directory as all other data in order for
Georgia Mountain Wind user model to function correctly.
Note 5: With the inclusion of the 326 SPS thermal mode relay model, to use this model when
simulating with faults that include opening Line 326, a small value of shunt MVA (1-j1) is needed
on either the Scobie Pond or Lawrence Road 345-kV buses and the Scobie Pond-Lawrence Road
section of Line 326 needs to stay in-service. This allows a negligible MVA to still be flowing on
Scobie Pond-Lawrence Road section of Line 326, otherwise the model will trip the assigned
branches (generator GSUs), even though the thermal set point may not have been reached.
Opening of the Scobie Pond-Lawrence Road section of Line 326, which is being monitored by the
SPS model, causes the assigned branches to be tripped (and thereby tripping the units associated
with this SPS) after the associated time delay; this is inherent in the PSSE relay model.
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