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NLSO Report
2018 Annual Planning Assessment
Doc # TP-R-011
Date: 2018/03/29
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011
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Executive Summary
A key function of the NLSO Transmission Planning Department is to ensure the coordinated
development of a safe, reliable and economical transmission system for the benefit of users within the
Province of Newfoundland and Labrador.
The transmission planning process requires the use of computer software to perform power system
studies in order to demonstrate that the power system meets Transmission Planning Criteria for the
present and future states of the system. An annual assessment of the transmission system is utilized to
determine the timing of system additions/modifications to ensure long term safe, reliable and
economical operation.
The North American Electric Reliability (NERC) Standard TPL-001-4 – Transmission System Planning
Performance Requirements includes the requirement for an annual Planning Assessment of the Planning
Authority’s portion of the Bulk Electric System (BES). While the Newfoundland and Labrador Hydro is not
a registered member of NERC or the regional reliability organization Northeast Power Coordinating
Council Inc. (NPCC), Hydro does complete annual assessments of its transmission system to determine if
Transmission Planning Criteria are met and if system additions/modifications are required. This report
provides the first Newfoundland and Labrador System Operator (NLSO) Annual Planning Assessment of
the transmission system within the Province of Newfoundland and Labrador under the control of the
NLSO. The 2018 report addresses the transmission system for which the NLSO Transmission Planning
Department is deemed to be the Planning Authority. The report is completed in accordance with
document TP-S-003 NLSO Standard – Annual Planning Assessment.
The near-term planning horizon covers the period 2018 to 2022. The assessment of the near-term
focuses on Year Two (2019) and Year Five (2022). The long-term planning horizon covers the period
from 2023 to 2027. The assessment of the long-term focuses on Year Ten (2027).
The study period for the 2018 Annual Planning Assessment covers a period of transition for the
interconnected systems in Labrador and on the Island. The addition of the Maritime Link (ML), the
Labrador – Island HVdc Link (LIL), the 315 kV transmission assets in Labrador (LTA) and the Muskrat Falls
Generating Station have a significant impact on the operation and performance of the transmission
system within the Province. The 2018 Annual Planning Assessment covers the first steps of the phased
approach to implementation including the addition of the ML, the Soldiers Pond synchronous
condensers and the LIL in monopolar mode metallic return. The assessment of the LIL in full bipole
mode and the completion of the Muskrat Falls Generating Station will be addressed in the 2019 Annual
Planning Assessment.
Given the limited transfer capacity of the system in western Labrador the NLSO Transmission Planning
Department has initiated a comprehensive study of the system to determine an appropriate expansion
plan to ensure a safe, reliable and economical transmission system for the benefit of users. The study
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will be filed with the Newfoundland and Labrador Board of Commissioners of Public Utilities (PUB) in the
fall of 2018. Consequently, the 2018 Annual Planning Assessment does not include a review of the
transmission system in western Labrador.
The existing load in eastern Labrador (Upper Lake Melville area) is supplied via a 269 km long 138 kV
transmission line from Churchill Falls and a 138/25 kV terminal station at Happy Valley. On July 27, 2017
Hydro filed its 2018 Capital Budget application with the PUB including a proposal to connect the 138 kV
supply to Happy Valley at the Muskrat Falls Terminal Station #2, reducing the overall transmission length
to 36 km, thereby improving the overall reliability of supply to the region. In addition, a new 138/25 kV
transformer would be added at the Happy Valley Terminal Station to ensure sufficient transformer
capacity with the largest of the existing transformers out of service, consistent with the existing
Transmission Planning Criteria. The proposed changes improved the transfer capacity of the system
from 77 MW to 129 MW for the single contingency loss of a 50 MVA 138/25 kV transformer at Happy
Valley with the Happy Valley gas turbine in operation for 25 MW.
In its Order No. P.U. 43(2017) the PUB found that the evidence presented in the application did not
demonstrate that the proposed project was necessary and consistent with the least-cost provision of
service and deferred consideration of the project until Hydro filed further information with the Board.
On January 29, 2018 Hydro filed revised information related to the Muskrat Falls to Happy Valley
Interconnection project. Following comments from intervenors, responses by Hydro, a meeting with the
PUB staff, Hydro and interested parties, and final comments, on March 23, 2018 the PUB found that
Hydro had fail to demonstrate that the proposed project is justified.
The PUB has ordered:
1. Hydro shall file on or before April 16, 2018 a proposed plan in relation to the provision of
reliable service in Labrador East in 2018/2019.
2. Hydro shall file on or before April 30, 2018 a proposal in relation to the process and timelines for
further consideration of the Muskrat Falls to Happy Valley-Goose Bay Interconnection project.
Hydro will continue to work with the PUB to determine the appropriate expansion of the transmission
system in Eastern Labrador. As this exercise is ongoing, the 2018 Annual Planning Assessment does not
include a review of this system.
The 2018 Annual Planning Assessment reveals:
• The pre-contingency steady state analysis indicates not transmission equipment overloads or
voltage violations in the near-term or long-term planning horizons.
o In Year Two, prior to the generators as Muskrat Falls being placed in service, the LIL
must be operated within specified limits to ensure acceptable voltage regulation of the
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315 kV transmission system in Labrador. This regulation will be impacted by PUB Order
No. P.U. 9(2018) and the fact that the Muskrat Falls-Happy Valley Interconnection
project has not been approved. This will be addressed in further operational studies.
• The steady state line out contingency analysis indicates:
o The loss of TL235 (Stony Brook to Grand Falls) or TL247/248 (Cat Arm to Deer Lake to
Massey Drive) will result in the loss of generation
� The generation deficiency is mitigated by re-dispatch of existing generation
o Loss of TL210 Stony Brook to Cobb’s Pond results in low voltages at Farewell Head
� The low voltages are mitigated by placing the 230/138 kV transformer OLTCs at
Stony Brook and Sunnyside in manual and adjusting the Sunnyside 138 kV bus
voltage to 1.031 p.u. and the Stony Brook 138 kV bus voltage to 1.030 p.u.
o Loss of TL219 Sunnyside to Salt Pond results in low voltages on the Burin Peninsula 138
kV system south of Bay l’Argent
� The low voltages are mitigated by placing the Greenhill Gas Turbine in service
at a minimum load of 5 MW
o In Year Two, prior to the interconnection of Muskrat Falls generators, the loss of 315
kV transmission lines L3101 or L3102 will result in undervoltages at Muskrat Falls
Terminal Station 2.
o The 315 kV, 150 MVAR shunt reactor at Muskrat Falls Terminal Station 2 will be
equipped with undervoltage protection to ensure that it is tripped if voltages drop
below 0.88 per unit (277.2 kV).
• The steady state multi transformer station transformer contingencies analysis indicates:
o Loss of Daniels Harbour T1, a 66/12.5 kV, 1.0/1.33 MVA unit, will result in the overload
of the remaining transformer T2, a 66/12.5 kV, 1.0 MVA unit in both the near-term and
long-term horizons.
� The overload is mitigated by installation of Hydro’s mobile transformer.
Further, Hydro is working with the manufacturer of the Daniels Harbor T2 unit
to determine if the unit can be upgraded to a 1.0/1.33 MVA rating.
o Loss of Happy Valley T1, a 138/25 kV, 30/40/50 MVA unit, will result in the overload of
the remaining transformers T2 and T3 (138/25 kV, 15/20/25//28 MVA units) in both
the near-term and long-term horizons even with the Happy Valley gas turbine
operating at 25 MW during the T1 outage over peak.
� Hydro will be addressing the issue in accordance with PUB Order No. P.U.
9(2018).
o Loss of Holyrood T10, a 230/69 kV, 15/20/25 MVA unit, will result in the overload of
the remaining transformer T5, a 230/69 kV, 15/20/25 MVA unit in both the near-term
and long-term horizons.
� The overload is mitigated by opening Newfoundland Power 66 kV line 52L
between Kelligrews and Seal Cove to offload Holyrood T5. The mitigation
action has no loss of customer load. Seal Cove Substation is supplied radially
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from Holyrood and Kelligrews Substation is supplied radially from
Chamberlains Substation. Chamberlains is supplied, in turn, by two 66 kV
transmission lines connected to Hardwoods Terminal Station.
o Loss of Western Avalon T1, a 230/66 kV, 15/20/25 MVA unit, will result in the overload
of the remaining transformer T2, a 230/66 kV, 15/20/25 MVA unit in both the near-
term and long-term horizons.
� The overload is mitigated by opening Newfoundland Power 66 kV line 41L
between Heart’s Content Substation and Carbonear Substation. The mitigation
action has no loss of customer load. Blaketown, New Harbour, Islington,
Heart’s Content, New Chelsea and Old Perlican Substations are supplied from
Western Avalon/Blaketown. Island Cove, Harbour Grace, Carbonear and
Victoria Substations are supplied from Bay Roberts Substation.
• The steady state looped system transformer contingency analysis indicates:
o The loss of Oxen Pond T3 (a 230/66 kV, 150/200/250 MVA unit) in the Hardwoods -
Oxen Pond 66 kV Loop will result in the highest loads levels on the remaining
transformers. Should Hydro retire the Hardwoods gas turbine in the 2022 time frame,
it is expected that there will be a transformer overload within the loop in the long-term
horizon.
� Potential mitigation measures for this potential long-term horizon overload
include:
• Replace the Hardwoods Gas Turbine
• Add new gas turbine capacity within the Hardwoods – Oxen Pond 66
kV Loop
• Increase transformer capacity in the Hardwoods – Oxen Pond 66 kV
Loop in 2027 to meet the load growth and planning criteria
� Each of these alternatives is being considered in Hydro’s Resource Adequacy
Study to be completed in 2018.
o No transformer overloads are expected in the Holyrood - Western Avalon 138 kV Loop
in either the near-term or long-term horizon.
o The loss of a 230/138 kV, 75/100/125 MVA transformer at Stony Brook Terminal
Station in the Stony Brook – Sunnyside 138 kV Loop will overload the remaining
230/138 kV transformers in both the near-term and long-term planning horizons.
� The overload is mitigated in the near-term by opening the 138 kV Loop on the
Gander/Gambo region to off load the remaining Stony Brook transformer.
Analysis has indicated that with the loop open during the transformer
contingency 138 kV bus voltages on the order of 90% can be expected to occur
in the Gambo area. To this end, Hydro is working with Newfoundland Power to
determine an appropriate long-term solution to the issue.
� Long-term transmission mitigation strategies may include:
• Additional transformer capacity within the loop
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• Construction of additional 138 kV transmission line(s) in the Gander to
Clarenville portion of the loop
• Addition of reactive power support to maintain acceptable voltages
during the transformer contingency
� Each alternative must be assessed for technical viability and a cost benefit
analysis completed to determine the least cost reliable alternative
o The Stephenville – Bottom Brook 66 kV Loop operates normally open at the Bottom
Brook end such that all load in the Stephenville area is supplied via 230 kV transmission
line TL209 and the Stephenville Terminal Station. For the loss of the single 230/66 kV
transformer at Stephenville, the Stephenville gas turbine is operated for 50 MW.
Under light load conditions the 66 kV loop can be closed such that the Stephenville is
supplied via a 138/66 kV, 15/20/25 MVA transformer, T2, at Bottom Brook and
Newfoundland Power 66 kV line 400 L. If Hydro were to retire the Stephenville gas
turbine in the 2022 time frame, it would not be able to supply all load in the
Stephenville area for loss of the 230/66 kV transformer at Stephenville Terminal
Station.
� Assuming retirement of the Stephenville gas turbine, the long-term mitigation
strategy to maintain full back up supply to the Stephenville area for loss of the
230/66 kV transformer at Stephenville or the loss of TL209, is to add a 230/66
kV, 40/53/3/66.6 MVA transformer at Bottom Brook to replace the 138/66 kV,
15/20/25 MVA unit.
• Steady state generator contingency analysis indicates:
o The loss of a synchronous condenser at Wabush Terminal Station in western Labrador
will result in low voltages and tripping of loads. Permanent loss of a synchronous
condenser requires a reduction in the transfer capacity of the system in western
Labrador.
� A comprehensive review of the transmission system in western Labrador is
underway and will be covered under a separate report.
o The loss of the Happy Valley gas turbine in synchronous condenser mode in eastern
Labrador will result in low voltages and tripping of loads. Permanent loss of the
synchronous condenser requires a reduction in the transfer capacity of the system in
eastern Labrador.
� Hydro will be addressing the issue in accordance with PUB Order No. P.U.
9(2018).
o Hydro is completing a long term resource adequacy analysis to assess the future
generator capacity requirements. The report will be completed in 2018.
• Steady State shunt contingency analysis indicates:
o Loss of the Granite Canal Tap shunt reactor results in a potential for self-excitation of
the Granite Canal generator.
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� To avoid potential for self-excitation of Granite Canal generator an operating
instruction has been prepared to remove TL269 from service when the Granite
Canal Tap shunt reactor is out of service.
o The loss of a 46 kV, 25.2 MVAR shunt capacitor at Wabush Terminal Station in western
Labrador will result in low voltages and tripping of loads. Permanent loss of a shunt
capacitor requires a reduction in the transfer capacity of the system in western
Labrador.
� A comprehensive review of the transmission system in western Labrador is
underway and will be covered under a separate report.
o The Happy Valley Terminal Station includes four switched shunt capacitor banks for a
total of 11.4 MVAR. In addition, the Muskrat Falls construction power station
(MFATS3) includes six 3.6 MVAR switched shunt capacitor banks. Combined these
switched shunts provide the necessary voltage support to transfer power from
Churchill Falls to Happy Valley. Loss of a shunt capacitor bank will result in low
voltages and a requirement to reduce transfer capacity on the 138 kV systems in
eastern Labrador.
� Hydro will be addressing the issue in accordance with PUB Order No. P.U.
9(2018).
o In Year Two the Muskrat Falls generators are not yet in service. The loss of the 315 kV,
150 MVAR shunt reactor at Muskrat Falls will result in overvoltages due to the charging
associated with 315 kV transmission lines L3101 and L3102.
� The extent of overvoltages at Muskrat Falls Terminal Station 2 is impacted by
PUB Order No. P.U. 9(2018) and the fact that the Muskrat Falls-Happy Valley
Interconnection project has not been approved. Hydro will address these
overvoltages in further operational studies and discussion will be included in
the 2019 Annual Planning Assessment.
• The short circuit analysis reveals not issues with circuit breaker ratings in the near-term or
long-term planning horizons.
• The stability analysis of the near term planning horizon indicates:
o For the addition of the Maritime Link ONLY:
� a firm import of 108 MW is available at Bottom Brook based upon the Island
Interconnected System ability to accept 108 MW of import capacity
independent of system load and generation dispatch.
� Up to an additional 192 MW of non-firm import capacity is available at Bottom
Brook depending upon the Island Interconnected System load.
� The export limit at Bottom Brook is a function of not only the Island load but
also the generation dispatch and particularly, the number of thermal units on
line at Holyrood.
• The firm export limit is set at 55 MW at Bottom Brook.
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• Up to an additional 70 MW of non-firm of non-firm export is available
at Bottom Brook depending upon the Island Interconnected System
load and status of generation at Holyrood.
o For the addition of the Maritime Link and Soldiers Pond Synchronous Condensers:
� a firm import of 108 MW is available at Bottom Brook based upon the Island
Interconnected System ability to accept 108 MW of import capacity
independent of system load and generation dispatch.
� Up to an additional 242 MW of non-firm import capacity is available at Bottom
Brook depending upon the Island Interconnected System load.
� The export limit at Bottom Brook is a function of not only the Island load but
also the generation dispatch and particularly, the number of thermal units on
line at Holyrood.
• The firm export limit is set at 55 MW at Bottom Brook.
• Up to an additional 70 MW of non-firm of non-firm export is available
at Bottom Brook depending upon the Island Interconnected System
load and status of generation at Holyrood.
o For the addition of the Maritime Link and Soldiers Pond Synchronous Condensers with
the Labrador – Island HVdc Link in monopolar mode, metallic return:
� LIL transfers are limited as a function of the following parameters:
• The status of the ML frequency controller
• The number of SOP synchronous condensers that are in service
• The Churchill Falls bus voltage
� There will be no frequency controller on the LIL in the initial monopolar mode
of operation. Therefore, the import and export limits on the Maritime Link will
be dependent upon the number of high inertia synchronous condensers in
service and the thermal units on-line at Holyrood.
• A firm import of 108 MW is available at Bottom Brook based upon the
Island Interconnected System ability to accept 108 MW of import
capacity independent of system load and generation dispatch.
• Up to an additional 242 MW of non-firm import capacity is available at
Bottom Brook depending upon the Island Interconnected System load.
• The export limit at Bottom Brook is a function of not only the Island
load but also the generation dispatch and particularly, the number of
thermal units on line at Holyrood.
o The firm export limit is set at 55 MW at Bottom Brook.
o Up to an additional 70 MW of non-firm of non-firm export is
available at Bottom Brook depending upon the Island
Interconnected System load and status of generation at
Holyrood and number of high inertia synchronous condensers
on-line at Soldiers Pond.
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Table of Contents
1 PURPOSE .................................................................................................................... 1
2 INTRODUCTION .......................................................................................................... 2
3 DEFINITIONS .............................................................................................................. 4
4 TRANSMISSION PLANNING CRITERIA .......................................................................... 9
4.1 Steady State Analysis Criteria............................................................................................................ 9
4.2 Dynamic (Stability) Analysis Criteria ................................................................................................. 9
5 SELECTION OF STUDY CASES ..................................................................................... 11
5.1 Near-Term Planning Horizon Cases ................................................................................................. 11
5.1.1 Year Two (2019) System Additions ................................................................................... 11
5.1.2 Year Five (2022) System Additions ................................................................................... 12
5.2 Long-Term Planning Horizon Case .................................................................................................. 12
5.2.1 Year Ten (2027) System Additions .................................................................................... 12
6 SPECIAL CONSIDERATIONS ....................................................................................... 13
6.1 Impacts of the Lower Churchill Project ........................................................................................... 13
6.2 Western Labrador ........................................................................................................................... 13
6.3 Eastern Labrador ............................................................................................................................. 13
7 LOAD FORECAST ....................................................................................................... 15
8 STEADY STATE ANALYSIS .......................................................................................... 16
8.1 Steady State Pre-Contingency Analysis ........................................................................................... 16
8.1.1 Pre-Contingency Analysis Near-Term Horizon .................................................................. 16
8.1.2 Pre-Contingency Analysis Long-Term Horizon .................................................................. 17
8.1.3 Summary of Pre-Contingency Transformer Peak Loads ................................................... 18
8.2 Steady State Contingency Analysis ................................................................................................. 21
8.2.1 Line Out Contingency Analysis Near-Term Horizon .......................................................... 25
8.2.2 Line Out Contingency Analysis Long-Term Horizon .......................................................... 25
8.2.3 Summary of Multi Transformer Station Contingency Loading ......................................... 26
8.2.4 Summary of Looped System Transformer Contingency Loading ...................................... 30
8.2.5 Generator and Synchronous Condenser Contingency Analysis Near-Term Horizon ........ 32
8.2.6 Generator and Synchronous Condenser Contingency Analysis Long-Term Horizon ........ 33
8.2.7 Shunt Contingency Analysis .............................................................................................. 33
9 SHORT CIRCUIT ANALYSIS ......................................................................................... 35
10 STABILITY ANALYSIS ................................................................................................. 36
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10.1 System Stability Near-Term Horizon ............................................................................................... 37
10.2 System Stability Long-Term Horizon ............................................................................................... 38
11 CONCLUSIONS .......................................................................................................... 39
12 REFERENCE DOCUMENTS .......................................................................................... 45
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Document #: TP-R-011 PURPOSE
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1 PURPOSE
The North American Electric Reliability (NERC) Standard TPL-001-4 – Transmission System Planning
Performance Requirements includes the requirement for an annual Planning Assessment of the Planning
Authority’s portion of the Bulk Electric System (BES). While the Newfoundland and Labrador Hydro is not
a registered member of NERC or the regional reliability organization Northeast Power Coordinating
Council Inc. (NPCC), Hydro does complete annual assessments of its transmission system to determine if
Transmission Planning Criteria are met and if additions/modifications to the system are required. The
purpose of this report is to provide the first Newfoundland and Labrador System Operator (NLSO)
Annual Planning Assessment of the transmission system within the Province of Newfoundland and
Labrador under the control of the NLSO. The 2018 report addresses the transmission system for which
the NLSO Transmission Planning Department is deemed to be the Planning Authority.
This report is completed in accordance with document TP-S-003 NLSO Standard – Annual Planning
Assessment.
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 INTRODUCTION
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2 INTRODUCTION
A key function of the NLSO Transmission Planning Department is to ensure the coordinated
development of a safe, reliable and economical transmission system for the benefit of users within the
Province of Newfoundland and Labrador.
The transmission planning process requires the use of computer software to perform power system
studies in order to demonstrate that the power system meets planning criteria for the present and
future states of the system. An annual assessment of the transmission system is utilized to determine
the timing of system additions/modifications to ensure long term safe, reliable and economical
operation.
The 2018 Annual Planning Assessment covers the near-term planning horizon through review of the
2019 and 2022 load cases and the long-term planning horizon through review of the 2027 load cases.
In general, the requirement for an annual planning assessment is focused on the Planning Authority’s
area of the NERC BES, or for NPCC the BPS. Given the size of the NLSO footprint, the decision has been
made to include the Radial, Local Network and Primary Transmission Systems under the authority of the
NLSO Transmission Planning Department in this 2018 Annual Planning Assessment.
Figure 1 provides a map of the Newfoundland and Labrador Interconnected System post completion of
the Lower Churchill Project.
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Figure 1 –Newfoundland and Labrador Interconnected System
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Document #: TP-R-011 DEFINITIONS
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3 DEFINITIONS
Bulk Electric System or NERC BES: Unless modified by the lists shown below, all Transmission Elements
operated at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or
higher. This does not include facilities used in the local distribution of electric energy. (This definition
has five inclusion clauses and four exclusion clauses.) (As per the NERC Glossary of Terms)
Bulk-Power System or NERC BPS: Bulk-Power System:
(A) facilities and control systems necessary for operating an interconnected electric energy
transmission network or any portion thereof); and
(B) electric energy from generation facilities needed to maintain transmission system reliability.
The term does not include facilities used in the local distribution of electric energy. (Note that
the terms “Bulk- Power System” or Bulk Power System” shall have the same meaning.) (As per
NPCC Glossary of Terms)
Bulk Power System or NPCC BPS: The interconnected electrical systems within northeastern North
America comprised of system elements on which faults or disturbances can have a significant adverse
impact outside the local area. (As per NPCC Glossary of Terms) Note that for NPCC BPS elements are
determined through application of NPCC Document A-10 “Classification of Bulk Power System
Elements”.
For greater clarity, the term BPS or Bulk Power System (with upper case letters) when used by the NLSO
is in reference to the NPCC definition. The term bulk power system (all lower case) is in reference to
the NERC definition.
Cascading: The uncontrolled successive loss of System Elements triggered by an incident at any location.
Cascading results in widespread electric service interruption that cannot be restrained from sequentially
spreading beyond an area predetermined by studies. (As per NERC Glossary of Terms)
Circuit Breaker: A device used to open and close a circuit by non-automatic means thereby breaking, or
interrupting load current. The device will automatically open the circuit on a predetermined overload of
current without damage to the device when properly applied.
Element: Any electrical device with terminals that may be connected to other electrical devices such as
generator, transformer, circuit breaker, bus section or transmission line. An element may be comprised
of one or more components. (As per NERC Glossary of Terms)
Extra High Voltage (EHV) Transmission: Transmission system with a nominal operating voltage greater
than 300 kV.
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High Voltage (HV) Transmission: Transmission system with a nominal operating voltage up to 300 kV.
Interconnected Reliability Operating Limit (IROL): A System Operating Limit, that if violated, could lead
to instability, uncontrolled separation, or Cascading outages that adversely impact the reliability of the
Bulk Electric System.
Local Network (LN)1: A group of contiguous transmission elements operated at less than 300 kV that
distribute power to load rather than transfer bulk power across the interconnected system. LN’s
emanate from multiple points of connection at 100 kV or higher to improve the level of service to retail
customers and not to accommodate bulk power transfer across the interconnected system. The LN is
characterized by all of the following:
• Limits on connected generation:
o The LN and its underlying elements do not include generation resources that:
� The high side of the generator step-up transformer(s) are connected at 100 kV
or above with:
• Gross individual nameplate rating greater than 20 MVA. Or
• aggregate capacity of nonretail generation greater than 75 MVA (gross
nameplate rating);
� Blackstart Resources identified in the Transmission Operator’s restoration plan
• Real Power flows only into the LN and the LN does not transfer energy originating outside the
LN for delivery through the LN; and
• Not part of a transfer path: The LN does not contain any part of a monitored Facility included in
an Interconnection Reliability Operating Limit (IROL).
Long-Term Transmission Planning Horizon: Transmission planning period that covers years six through
ten or beyond when required to accommodate any known longer lead time projects that may take
longer than ten years to complete. (As per NERC Glossary of Terms)
Near-Term Transmission Planning Horizon: The transmission planning period that covers Year One
through five. (As per NERC Glossary of Terms)
Newfoundland and Labrador Interconnected System: The interconnected transmission systems in both
Newfoundland and Labrador with a rated voltage of 46 kV and above including the Labrador – Island
HVdc Link. This term is interchangeable with the term Provincial Interconnected System.
1 NERC Glossary of Terms modified for NL context.
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Newfoundland and Labrador System Operator (NLSO): Newfoundland and Labrador Hydro operating in
its role as the system operator. This is synonymous with the role of Hydro’s Energy Control Centre (ECC)
and corresponding support staff.
NL: The Province of Newfoundland and Labrador.
NL Transmission System: The transmission facilities located in NL, primarily operating at a voltage level
of 230 kV or higher, including, without limitation, the Labrador-Island Link, the Labrador Transmission
Assets and Island Interconnected System but excluding the high voltage direct current portion of the
Maritime Link transmission line owned by NSP Maritime Link Incorporated. (utilized in commercial
agreements)
North American Electric Reliability Corporation (NERC): A not-for-profit international regulatory
authority whose mission is to assure the reliability and security of the bulk power system in North
America. NERC develops and enforces Reliability Standards; annually assesses seasonal and long-term
reliability; monitors the bulk power system through system awareness; and educates, trains, and
certifies industry personnel. NERC’s area of responsibility spans the continental United States, Canada,
and the northern portion of Baja California, Mexico.
Northeast Power Coordinating Council (NPCC): A not-for-profit corporation in the state of New York
responsible for promoting and enhancing the reliability of the international, interconnected bulk power
system in Northeastern North America.
Planning Authority: The responsible entity that coordinates and integrates transmission Facilities and
service plans, resource plans, and Protection Systems. (As per NERC Glossary of Terms) For the
Newfoundland and Labrador Interconnected System this is the NLSO Transmission Planning
Department.
Planning Coordinator: See Planning Authority (As per NERC Glossary of Terms)
Primary Transmission System or PTS: Given that Hydro is not a registered entity within NERC and/or
NPCC, it would be inappropriate to describe elements within the Newfoundland and Labrador
Interconnected System as BES or BPS. As a result the term Primary Transmission System is used to
define the bulk transmission facilities within the NLSO jurisdiction to which the NLSO Transmission
Planning Criteria will be applied to ensure reliable operation of the bulk power system. The PTS
elements form the basis of the NLSO’s future BES.
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Radial systems2: A group of contiguous transmission elements that emanates from a single point of
connection and:
• Only serves load. Or.
• Only includes generation resources that are not:
o Including the generator terminals through the high side of the step-up transformer(s)
connected at a voltage of 100 kV or above with:
� Gross individual nameplate rating greater that 20 MVA. Or,
� Gross plant/facility aggregate nameplate rating greater than 75 MVA.
o Blackstart resources identified in the Transmission Operator’s restoration plan.
o Dispersed power producing resources that aggregate tot a total capacity greater than 75
MVA (gross nameplate rating), and that are connected through a system designed
primarily for delivering such capacity to a common point of connection at a voltage of
100 kV or above.
• Where the radial system serves load and includes generation resources, not identified above,
with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross
nameplate rating).
Short Circuit: An abnormal connection (including an arc) of relatively low impedance, whether made
accidentally or intentionally, between two points of different potential. Note: The term fault or short-
circuit fault is used to describe a short circuit.
Significant Adverse Impact3: With due regard for the maximum operating capability of the affected
systems, one or more of the following conditions arising from faults or disturbances, shall be deemed as
having significant adverse impact:
a. instability;
• any instability that cannot be demonstrably contained to a well-defined local area.
• any loss of synchronism of generators that cannot be demonstrably contained to a well-defined
local area (such as synchronous machines at a paper mill).
b. unacceptable system dynamic response;
• an oscillatory response to a contingency that is not demonstrated to be clearly positively
damped within 30 seconds of the initiating event.
c. unacceptable equipment tripping;
2 NERC Glossary of Terms BES definition Exclusion E1 – the voltage of 100 kV or higher removed for this definition.
3 Modified from the NPCC Glossary of Terms. For the purposes of this definition local area is taken to mean a
confined area within the Newfoundland and Labrador Interconnected System such as a regional system such as
GNP, or a single industrial customer. Contingency is taken as a Hydro defined contingency. Bulk Power System is
taken in the general sense and not the NPCC defined BPS. Operation of Special Protection Systems has been
deleted. Emergency limits have been replaced with applicable limits as Hydro does not have defined “emergency”
limits.
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Document #: TP-R-011 DEFINITIONS
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• tripping of an un-faulted bulk power system element under planned system configuration due
to operation of a protection system in response to a stable power swing.
d. voltage levels in violation of applicable limits;
e. loadings on transmission facilities in violation of applicable limits.
System Operating Limit (SOL): The value (such as MW, MVAR, amperes, frequency or volts) that
satisfies the most limiting of prescribed operating criteria for a specified system configuration to ensure
operation within acceptable reliability criteria. System Operating Limits are based upon certain
operating criteria. These included, but are not limited to:
• Facility Ratings (applicable pre- and post-Contingency Equipment Ratings or Facility Ratings)
• transient stability ratings (applicable pre- and post-Contingency stability limits)
• voltage stability ratings (applicable pre- and post-Contingency voltage stability)
• system voltage limits (applicable pre- and post-Contingency voltage limits)
Transmission Planner: The entity that develops a long-term (generally one year and beyond) plan for
the reliability (adequacy) of the interconnected bulk electric transmission systems within its portion of
the Planning Authority area. (As per NERC Glossary of Terms). For the Newfoundland and Labrador
Interconnected System this is the NLSO Transmission Planning Department.
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 TRANSMISSION PLANNING CRITERIA
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4 TRANSMISSION PLANNING CRITERIA
This section provides a summary of the Transmission Planning Criteria used to complete the annual
planning assessment. The full Transmission Planning Criteria are provided in reference document TP-S-
007 NLSO Standard – Transmission Planning Criteria.
4.1 Steady State Analysis Criteria
• With a transmission element (line, transformer, synchronous condenser, shunt or series
compensation device) is out of service, power flow in all other elements of the power system
should be at or below normal rating
• Transformer additions at all major terminal stations (i.e. two or more transformers per voltage
class) are planned on the basis of being able to withstand the loss of the largest unit
• For normal operations all voltages be maintained between 95% and 105%
• For contingency or emergency situations all voltages be maintained between 90% and 110%
• Analysis will be conducted with one high inertia synchronous condenser out of service at
Soldiers Pond
4.2 Dynamic (Stability) Analysis Criteria
• System response shall be stable and well damped4 following a disturbance
• System disturbances include:
o Successful single pole reclosing on line to ground faults
o Unsuccessful single pole reclosing on line to ground faults
o Three phase faults except a three phase fault on, or near, the Bay d’Espoir 230 kV bus
with tripping of a 230 kV transmission line
o Loss of the largest generator on line on the Island System with and without fault
o Line to ground or three phase fault with tripping of a synchronous condenser
o Fault and tripping of a series compensated 230 kV transmission line with the series
compensation device out of service on the in service parallel 230 kV transmission line
o Temporary pole fault
o Permanent pole fault
o Temporary bipole fault
• Post fault recovery voltages on the ac system shall be as follows:
4 From the NPCC definition for Significant Adverse Impact an unacceptable system dynamic response is an
oscillatory response to a contingency that is not demonstrated to be clearly positively damped within 30 seconds
of the initiating event.
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o Transient under voltages following fault clearing should not drop below 70%
o The duration of the voltage below 80% following fault clearing should not exceed 20
cycles
• Post fault system frequencies shall not drop below 59 Hz
• Under frequency load shedding
o shall not occur for loss of on-island generation with the HVdc link in service
o shall not occur for permanent loss of HVdc pole
o shall not occur for a temporary bipole outage
o shall be controlled for a permanent bipole outage
• There shall be no commutation failures of the HVdc link during post fault recovery.
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Document #: TP-R-011 SELECTION OF STUDY CASES
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5 SELECTION OF STUDY CASES
Each year the NLSO Transmission Planning Department updates its set of system models to reflect the
latest load forecast and completed system changes and approved additions/modifications for future
years. The current planning cycle sets Year One as 2018 (the current year), Year Two as 2019 and so on,
such that Year Ten is 2027.
5.1 Near-Term Planning Horizon Cases
The near-term planning horizon covers Years One to Five. The 2018 Annual Assessment uses Years Two
(2019) and Year Five (2022). Year Two was selected given that it will be the first full year with the 315
kV transmission system in service in Labrador and the Labrador - Island HVdc Link in operation in
monopolar mode. Load flow plots of the primary transmission system for Years Two and Five are
provided in Appendices A and B, respectively.
5.1.1 Year Two (2019) System Additions
The following system additions are included in the 2019 study cases:
• The Labrador Transmission Assets (LTA) are in service including:
o L3101 and L3102 Churchill Falls to Muskrat Falls operating at 315 kV
o Churchill Falls Terminal Station 2 (CHFTS2) two 735/315 kV, 840 MVA autotransformers
in service
o Muskrat Falls Terminal Station 2 (MFATS2) two 315/138/25 kV, 75/100/125 MVA
autotransformers in service
o MFATS2 315 kV, 150 MVAR shunt reactor in service
• Muskrat Falls construction power load is supplied from the 25 kV DELTA tertiaries of the
315/138/25 kV autotransformers at MFATS2
• Happy Valley Terminal Station (HVYTS) is supplied via 138 kV transmission lines L1301/L1302
from Churchill Falls. The Muskrat Falls Construction Power Station (MFATS3) remains in service
to provide voltage support to the 138 kV system
• The Labrador-Island HVdc Link (LIL) is operating in Monopole Mode Metallic Return
o Two filter banks are available at each of Muskrat Falls and Soldiers Pond Converter
Stations
o Electrode lines and electrode sites not in service
o LIL transfers to Island based upon available recall in Labrador
• The Soldiers Pond 230 kV ac station is completed
• There are two Soldiers Pond 175 MVAR synchronous condensers in service for analysis (the third
unit is available)
• The rebuild of TL266 between Soldiers Pond and Hardwoods is complete
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Document #: TP-R-011 SELECTION OF STUDY CASES
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• The firm transfer on the Maritime Link (ML) is set at 0 MW
o The Nova Scotia Block flow begins following commissioning of the third unit at Muskrat
Falls Generating Station
5.1.2 Year Five (2022) System Additions
The following system additions are included in the 2022 study cases:
• The Muskrat Falls Generating Station (MFAGS) is complete
• The MFAST2 315 kV, 150 MVAR shunt reactor is removed from service
• The Happy Valley North Side Diesel Plant is assumed out of service
• A third transmission line is required in Labrador West. A separate comprehensive study is
underway to determine the appropriate alternative. For development of this study case a third
230 kV transmission line between Churchill Falls and Wabush Terminal Station has been added
so that solutions of the load flow cases can occur
• The LIL is operating in Bipole Mode up to its rated capacity of 900 MW
• Holyrood Thermal Generating Station is placed out of service with Unit 3 operating in
synchronous condenser mode
• The Holyrood black start diesels have been removed from service
• Stephenville gas turbine is out of service
• Hardwoods gas turbine is out of service
• The ML exports are set at the NS Block (157 MW at Bottom Brook terminal Station 2 – BBKTS2)
in both the peak and light load cases
5.2 Long-Term Planning Horizon Case
The long-term planning horizon covers Years Six to Ten. The 2018 Annual Assessment uses Year Ten
(2027) to assess the long-term planning horizon. Load flow plots of the primary transmission system for
Year Ten are provided in Appendix C.
5.2.1 Year Ten (2027) System Additions
At present there are no long-term planning horizon system additions or modifications beyond those
found in the Year Five (2022) study cases.
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Document #: TP-R-011 SPECIAL CONSIDERATIONS
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6 SPECIAL CONSIDERATIONS
The study period for the 2018 Annual Planning Assessment covers the period 2019 to 2027. This is a
transitional time for the interconnected systems in Labrador and on the Island of Newfoundland with
the addition of the Maritime Link (ML), the Labrador – Island HVdc Link (LIL), the 315 kV transmission
assets in Labrador (LTA) and the Muskrat Falls Generating Station.
6.1 Impacts of the Lower Churchill Project
The Lower Churchill Project will be delivered in a phased approach with the Maritime Link in service in
early 2018, the first pole of the LIL in service in monopolar metallic return in mid 2018, bipole mode of
operation for the LIL expected in late 2019 and the Muskrat Falls generation coming on line in the 2019
to 2020 timeframe. The change in approach and schedule has required rework of the system stability
studies. Therefore, the stability analysis covered within this Annual Planning Assessment covers the
operation of the Maritime Link and monopolar mode of the LIL. Specific stability analysis of the LIL in
bipole mode combined with the Muskrat Falls Generation Station will be completed as part of ongoing
operational studies and will be presented in the 2019 Annual Planning Assessment.
6.2 Western Labrador
The 230 kV transmission system in western Labrador was built by Twin Falls Power Corporation Limited
(TwinCo) to deliver power and energy from a 225 MW hydroelectric generating station on the Unknown
River to mining operations in western Labrador under a Sub-lease agreement with Churchill Falls
(Labrador) Corporation Limited - CF(L)Co. On December 31, 2014, the Sub-lease dated November 15,
1961 with CF(L)Co giving TwinCo the right to develop the Unknown River site expired. Through various
agreements, Hydro has taken over ownership of the 230 kV transmission system in western Labrador.
For the first time Hydro will be investigating the application of Transmission Planning Criteria to the 230
kV and 46 kV systems in western Labrador.
Given the limited transfer capacity of the system the NLSO Transmission Planning Department has
initiated a comprehensive study to determine an appropriate expansion plan to ensure a safe, reliable
and economical transmission system for the benefit of users. The study will be filed with the
Newfoundland and Labrador Board of Commissioners of Public Utilities (PUB) in the fall of 2018.
Consequently, the 2018 Annual Planning Assessment does not include a review of the transmission
system in western Labrador.
6.3 Eastern Labrador
The existing load in eastern Labrador (Upper Lake Melville area) is supplied via a 269 km long 138 kV
transmission line from Churchill Falls and a 138/25 kV terminal station at Happy Valley. On July 27, 2017
Hydro files its 2018 Capital Budget application with the PUB including a proposal to connect the 138 kV
NLSO REPORT – 2018 Annual Planning Assessment
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supply to Happy Valley at the Muskrat Falls Terminal Station #2, reducing the overall transmission length
to 36 km, thereby improving the overall reliability of supply to the region. In addition, a new 138/25 kV
transformer would be added at the Happy Valley Terminal Station to ensure sufficient transformer
capacity with the largest of the existing transformers out of service, consistent with the existing
Transmission Planning Criteria. The proposed changes improved the transfer capacity of the system
from 77 MW to 129 MW for the single contingency loss of a 50 MVA 138/25 kV transformer at Happy
Valley with the Happy Valley gas turbine in operation for 25 MW.
In its Order No. P.U. 43(2017) the PUB found that the evidence presented in the application did not
demonstrate that the proposed project was necessary and consistent with the least-cost provision of
service and deferred consideration of the project until Hydro filed further information with the Board.
On January 29, 2018 Hydro filed revised information related to the Muskrat Falls to Happy Valley
Interconnection project. Following comments from intervenors, responses by Hydro, a meeting with the
PUB staff, Hydro and interested parties, and final comments, on March 23, 2018 the PUB found that
Hydro had fail to demonstrate that the proposed project is justified.
The PUB has ordered5:
3. Hydro shall file on or before April 16, 2018 a proposed plan in relation to the provision of
reliable service in Labrador East in 2018/2019.
4. Hydro shall file on or before April 30, 2018 a proposal in relation to the process and timelines for
further consideration of the Muskrat Falls to Happy Valley-Goose Bay Interconnection project.
Hydro will continue to work with the PUB to determine the appropriate expansion of the transmission
system in Eastern Labrador. As this exercise is ongoing, the 2018 Annual Planning Assessment does not
include a review of this system.
5 Newfoundland and Labrador Board of Commissioners of Public Utilities Order of the Board No. P.U. 9(2018).
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 LOAD FORECAST
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7 LOAD FORECAST
The 2018 Annual Planning Assessment is based upon the following load forecasts prepared by the
Market Analysis Section, Rural Planning Department, Newfoundland and Labrador Hydro:
• Island Interconnected 10 Year P50 and P90 Peak Demand Summary – Summer 2017 dated
August 2017; and
• Labrador Interconnected 10 Year P50 and P90 Peak Demand Summary – Summer 2017 dated
July 6, 2017.
For the Year Two, Five and Ten winter peak load base cases, the P90 load forecast is used as the stress
case. Note that the Newfoundland and Labrador Interconnected System is characterized as being winter
peaking due to the heating requirements. That being said, the P90 load forecast for winter peak
provides for high loads and thereby permits the Transmission Planner to assess the system for potential
overloads and low voltage violations.
Given the lack of a large industrial base on the Island and low penetration levels of air conditioning load,
the summer peak load case is much lower than the winter peak. To this end, the P50 load forecast is
utilized in combination with the typical summer load shape to develop the summer peak load case for
each of the study years. Based upon the system load shape, summer peak is somewhat of a misnomer
and therefore the summer case identification typically does not include the term peak. The summer
load cases permit the Transmission Planner to assess the system for potential overloads in areas of
industrial loads and high voltage violations due to low loads.
The load spread between P90 for the winter peak and P50 for the summer is deemed to provide a
reasonable sensitivity to the load forecast for annual planning assessments.
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8 STEADY STATE ANALYSIS
The steady state analysis is completed in two distinct steps. The first step is the pre-contingency
analysis, for which the assessment assumes that all equipment is in service. The second step in the
contingency analysis, for which the prescribed contingency list in the Transmission Planning Criteria is
assessed.
8.1 Steady State Pre-Contingency Analysis
The pre-contingency analysis is performed to ensure that with all equipment in service under normal
operation, power flow in all elements are at or below normal rating and voltages are within acceptable
limits. The ratings are defined in the NLSO Facilities Rating Guide. This criterion applies to radial, local
networks and primary transmission system elements within the Newfoundland and Labrador
Interconnected System under the preview of the Transmission Planner and Planning Authority. Load
flow plots of the primary transmission systems in Labrador and on the Island are provided in Appendix
A.
8.1.1 Pre-Contingency Analysis Near-Term Horizon
A review of the pre-contingency winter and summer cases for Year Two and Year Five indicate that there
are no equipment loading violations, as illustrated in Appendix A and B.
There are no voltage violations in the near-term horizon for the Island portion of the system.
Voltage violations are observed in the near-term horizon related to voltages below 0.95 p.u. on the 230
kV bus at Wabush Terminal Station. Note that a comprehensive review of the transmission system in
western Labrador is underway and will be covered under a separate report.
In eastern Labrador voltage violations (low voltages) are observed on the 138 kV buses for Year Five.
Analysis indicates that with Happy Valley supplied via the 138 kV transmission from Churchill Falls
voltage collapse will occur when the Upper Lake Melville are load exceeds 77 MW. Figure 2 provides the
power versus 138 kV Happy Valley bus voltage curve. Given that the Year Five load for Happy Valley
exceeds the 77 MW transfer limit the Happy Valley gas turbine is operated as a generator to unload the
138 kV transmission line. This issue will be dealt with separately from this assessment by Hydro in
accordance with PUB Order No. P.U. 9(2018).
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Figure 2 - Power versus Voltage Profile – Happy Valley Goose Bay
In Year Two, prior to the generators as Muskrat Falls being placed in service, the LIL must be operated
within specified limits to ensure acceptable voltage regulation of the 315 kV transmission system in
Labrador. This regulation will be impacted by PUB Order No. P.U. 9(2018) and the fact that the Muskrat
Falls-Happy Valley Interconnection project has not been approved. Hydro will address voltage regulation
of the 315 kV transmission system in further operational studies and results will be presented in the
2019 Annual Planning Assessment.
8.1.2 Pre-Contingency Analysis Long-Term Horizon
A review of the pre contingency winter and summer cases for Year Ten indicate that there are no
equipment loading violations. Plots are provided in Appendix C.
Voltage violations in western Labrador are observed in the long-term horizon related to voltages below
0.95 p.u. on the 230 kV bus at Wabush Terminal Station during peak load conditions. Note that a
comprehensive review of the transmission system in western Labrador is underway and will be covered
under a separate report.
Voltage violations in eastern Labrador are observed in the long-term horizon related to low voltages on
the 138 kV bus at Happy Valley during peak load conditions. In addition, to avoid voltage collapse during
peak load conditions it is necessary to operate the Happy Valley gas turbine at 20 MW. This issue will be
dealt with separately from this assessment by Hydro in accordance with PUB Order No. P.U. 9(2018).
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8.1.3 Summary of Pre-Contingency Transformer Peak Loads
Table 1 provides a summary of the pre contingency transformer loading levels across the planning
horizons.
Table 1 – Pre Contingency Transformer Load Levels1,2
Station Unit Rating
MVA
2019 2022 2027
MVA % MVA % MVA %
Barachoix T1 10/13.3/16.7 8.32 49.8% 7.70 46.1% 7.53 45.1%
Bay d’Espoir T10 15/20/25 11.02 44.1% 10.64 42.6% 10.39 41.6%
T12 15/20/25 7.43 44.5% 7.00 41.9% 6.85 41.0%
T11 10/13.3/16.7 12.58 50.3% 10.56 42.3% 10.31 41.3%
Bear Cove T1 10/13.3/16.7 5.67 33.9% 5.29 31.7% 5.17 31.0%
Berry Hill T1 15/20/25 2.06 8.2% 1.92 7.7% 1.88 7.5%
Bottom Brook T1 25/33.3/41.7 25.07 60.1% 24.58 58.9% 18.20 43.6%
T2 15/20/25 0.37 1.5% 0.37 1.5% 0.36 1.4%
T3 25/33.3/41.7 7.54 18.1% 7.62 18.3% 7.43 17.8%
Bottom Waters T1 10/13.3/16.7 13.54 81.1% 12.32 73.8% 11.62 69.6%
Buchans T1 40/53.3/66.6 15.31 23.0% 15.45 23.2% 15.80 23.7%
T2 5/6.6/8.3 2.60 31.3% 2.59 31.2% 2.66 32.0%
Churchill Falls T31 75/100/125 Note 3
T32 25/33/42
Churchill Falls 2 T1 840 Note 4
T2 840
Come By Chance T1 30/40/50 19.41 38.8% 19.36 38.7% 19.37 38.7%
T2 30/40/50 19.41 38.8% 19.36 38.7% 19.37 38.7%
Coney Arm T1 2.5/3.3/4.0 0.00 0.0% 0.00 0.0% 0.00 0.0%
Conne River T1 2.5 3.05 92.5% 2.83 85.6% 2.76 83.8%
Cooper Hill T1 7.5/10 Note 3
Corner Brook
Converter
T1 21/28 18.01 64.3% 18.01 64.3% 18.01 64.3%
T2 21/28 18.15 64.8% 18.15 64.8% 18.15 64.8%
Cow Head T1 5/6.7/8.3 2.00 24.1% 1.85 22.3% 1.81 21.8%
Daniel’s Harbor T1 1/1.3 0.61 47.3% 0.57 43.5% 0.55 42.6%
T2 1 0.61 46.8% 0.56 43.1% 0.55 42.2%
Deer Lake T1 25/33.3/41.7 2.61 7.8% 3.06 9.2% 3.96 11.9%
T2 45/60/75 20.11 26.8% 23.31 31.1% 24.27 32.4%
Doyles T1 25/33.3/41.7 25.49 61.1% 24.90 59.7% 18.93 45.4%
Duck Pond T1 10/13.3/16.7 0.59 3.5% 0.59 3.5% 0.00 0.0%
English Harbour
West
T1 5/6.7 3.07 45.8% 2.84 42.4% 2.78 41.5%
Farewell Head T1 10/13.3/16.7 7.11 42.6% 6.64 39.8% 6.27 37.6%
Glenburnie T1 1.5/3.3 2.22 67.3% 2.04 61.9% 2.00 60.5%
Grand Falls
Frequency
T1 30/40/50 20.74 41.5% 20.26 40.5% 20.13 40.3%
T2 30/40/50 27.07 54.1% 26.48 53.0% 26.33 52.7%
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Converter T3 30/40/50 18.66 37.3% 19.14 38.3% 19.30 38.6%
Grandy Brook T1 7.5/10/12.5 5.44 43.5% 5.01 40.1% 4.70 37.6%
Hampden T1 2.5/3.3/4.0 1.40 35.1% 1.28 32.0% 1.21 30.3%
Happy Valley5 T1 30/40/50 39.85 79.7% 42.35 84.7% 43.37 86.7%
T2 15/20/25//28 22.22 79.4% 23.61 84.3% 24.18 86.4%
T4 15/20/25//28 22.22 79.4% 23.61 84.3% 24.18 86.4%
Hardwoods
T1 75/100/125 88.32 70.7% 90.59 72.5% 93.00 74.4%
T2 40/53.3/66.6 45.07 67.6% 46.22 69.3% 47.45 71.1%
T3 40/53.3/66.6 48.66 73.0% 49.91 74.8% 51.24 76.8%
T4 75/100/125 87.62 70.1% 89.87 71.9% 92.26 73.8%
Hawke’s Bay
T1 5/6 4.20 62.6% 3.86 57.5% 3.77 56.3%
T2 2.5/3.3 2.30 69.7% 2.11 64.0% 2.07 62.7%
Holyrood T5 15/20/25 20.18 80.7% 21.45 85.8% 22.46 89.9%
T10 15/20/25 19.65 78.6% 20.88 83.5% 21.87 87.5%
T6 25/33.3/41.7 10.60 25.4% 11.35 27.2% 11.82 28.4%
T7 25/33.3/41.7 10.54 25.3% 11.28 27.0% 11.75 28.2%
T8 75/100/125 30.78 24.6% 32.95 26.4% 34.32 27.5%
Howley5 T2 7.5/10/12.5 1.39 11.1% 1.73 13.9% 1.81 14.4%
Jackson’s Arm T1 5/6.6/8.3 1.52 18.3% 1.39 16.7% 1.31 15.8%
Main Brook T1 1.5 0.81 54.3% 0.77 51.2% 0.73 48.4%
Massey Drive T1 75/100/125 52.26 41.8% 54.05 43.2% 50.39 40.3%
T2 40/53.3/66.6 32.05 48.0% 32.32 48.4% 33.11 49.6%
T3 75/100/125 56.80 45.4% 57.28 45.8% 58.69 46.9%
Muskrat Falls TS1 T1 2 0.07 3.7% 0.07 3.7% 0.07 3.7%
Muskrat Falls TS2 T5 75/100/125 45.41 36.3% 45.50 36.4% 46.69 37.4%
T6 75/100/125 40.66 32.5% 45.59 36.5% 46.78 37.4%
Muskrat Falls TS3 T1 30/40/50 0.00 0.0% 0.00 0.0% 0.00 0.0%
Oxen Pond
T1 75/100/125 156.76 62.7% 156.71 62.7% 160.73 64.3%
T2 150/200/250 75.59 60.5% 75.57 60.5% 77.51 62.0%
T3 150/200/250 156.76 62.7% 156.71 62.7% 160.73 64.3%
Parson’s Pond T1 1/1.3 0.90 69.5% 0.83 63.9% 0.81 62.5%
Peter’s Barren T1 15/20/25 8.76 35.0% 8.05 32.2% 7.87 31.5%
Plum Point T1 10/13.3/16.7 4.14 24.8% 3.80 22.8% 3.72 22.3%
Quartzite T1 15/20/25 Note 3
T2 15/20/25
Rocky Harbour T1 5/6.6/8.3 4.22 50.8% 3.88 46.8% 3.80 45.8%
Roddickton T2 5/6.6/8.3 2.99 59.8% 2.75 55.0% 2.60 52.0%
South Brook T1 5/6.6/8.3 8.00 96.4% 7.45 89.8% 7.02 84.6%
Stephenville
T3 40/53.3/66.6 49.47 74.2% 49.64 74.4% 50.98 76.4%
Stony Brook
T1 75/100/125 98.17 78.5% 90.35 72.3% 93.03 74.4%
T2 75/100/125 96.99 77.6% 89.26 71.4% 91.91 73.5%
St. Anthony Airport T1 15/20/25 15.36 61.4% 6.70 26.8% 14.02 56.1%
Sunnyside T1 75/100/125 69.91 55.9% 77.62 62.1% 79.73 63.8%
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T4 75/100/125 70.41 56.3% 78.17 62.5% 80.30 64.2%
Vanier T1 15/20/25 Note 3
T2 15/20/25
Voisey’s Bay Nickel T1 75/100/125 31.66 25.3% 32.78 26.2% 31.97 25.6%
T2 75/100/125 31.57 25.3% 30.96 24.8% 30.55 24.4%
Wabush Terminal T1 35/47/65
Note 3
T2 35/47/65
T3 35/47/65
T4 35/47/65
T5 35/47/65
T6 35/47/65
T7 50/66.6/83.3
T8 50/66.6/83.3
Wabush Substation T3 5/6.6/8.3
T4 5/6.6/8.3
T5 3.0
T6 10/13.3/16.7
Western Avalon T1 15/20/25 18.17 72.7% 17.77 71.1% 18.69 74.7%
T2 15/20/25 18.50 74.0% 18.10 72.4% 19.03 76.1%
T3 25/33.3/41.7 18.36 44.0% 16.68 40.0% 16.83 40.4%
T4 25/33.3/41.7 18.26 43.8% 16.59 39.8% 16.74 40.2%
T5 75/100/125 53.51 42.8% 48.61 38.9% 49.07 39.3%
Wiltondale T1 1.0 0.07 4.8% 0.07 4.4% 0.06 4.3%
Notes:
1.) The generator step up transformers and converter transformers are no included as these units
have been sized for the full unit capability.
2.) Single Phase 167 kVA and 333 kVA units excluded.
3.) The long-term plan for the Labrador Interconnected System is currently under review.
4.) Expected loading on the 735kV/315kV transformers in Churchill Falls Terminal Station 2 will be
determined based on the results of a 2018 operational study.
5.) Happy Valley Gas Turbine online as a synchronous condenser.
6.) Rattle Brook assumed to be operating at 4MW.
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8.2 Steady State Contingency Analysis
The steady state contingency analysis:
• Shall include simulation of the removal of all elements that the Protection System and other
automatic controls are expected to disconnect for each Contingency without operator
intervention. The analyses shall include the impact of subsequent:
o Tripping of generators where simulations show generator bus voltages or high side of
the generation step up (GSU) voltages are less than known or assumed minimum
generator steady state or ride through voltage limitations.
o For loss of TL207 between Sunnyside and Come By Chance
� Two 230 kV switched shunt capacitor banks and Come by Chance (C1 and C2)
are removed from service
� Come By Chance T1 is removed from service
� Come By Chance T1 load is assumed to be switched automatically to T2 via the
closing of a 13.8 kV bus tie circuit breaker
o For loss of TL237 between Come By Chance and Western Avalon
� Two 230 kV switched shunt capacitor banks and Come by Chance (C3 and C4)
are removed from service
� Come By Chance T2 is removed from service
� Come By Chance T2 load is assumed to be switched automatically to T1 via the
closing of a 13.8 kV bus tie circuit breaker
o The loss of TL248 between Deer Lake and Massey Drive will result in the tripping of
TL248 and the Cat Arm Generating Station
• Shall include simulation of the expected automatic operation of existing and planned devices
designed to provide steady state control of electrical system quantities when such devices
impact the study area. These devices include equipment such as load tap changing transformers,
the Maritime Link converters when in voltage control mode during normal operation and when
in STATCOM mode, and switched capacitors and inductors/reactors.
In addition, the following actions are considered reasonable actions within the power system
operational time frame to ensure post-contingency loads on equipment are returned to within rating:
• changes in generation dispatch (i.e. start of stand by generation)
• changes in system configuration (i.e. opening of loops)
• non-firm export reductions
• non-firm load reductions
For the steady state contingency analysis one must recognize that loss of a transmission line on a radial
system, or loss of a transformer is a station containing only one transformer will result in customer
outage. From a planning assessment perspective and application of Transmission Planning Criteria this
outcome is viewed as acceptable given the nature of the radial system.
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Radial systems that will be impacted by loss of a transmission line are summarized in Table 2. Steady
state contingency analysis is not completed on these lines.
Table 2 – Radial Transmission Systems and Impact of Line Loss
TL # kV From To Impact
208 230 Western Avalon Voisey’s Bay Nickel Loss of industrial Customer
209 230 Bottom Brook TS2 Stephenville Loss of Stephenville area customers
Operation of the gas turbine over peak to restore load. Under
summer conditions up to 20 MW of load can be supplied via
Bottom Brook T2 and Newfoundland Power’s 66 kV
transmission line 400L
214 138 Bottom Brook Doyles Loss of load in Doyles/Port-aux-Basques area. Newfoundland
Power owns mobile gas turbine and mobile diesel located at
Grand Bay as well as Rose Blanche hydro site which can supply
limited load in area.
215 66 Doyles Grand Bay Loss of load in Port-aux-Basques area. Newfoundland Power
owns mobile gas turbine and mobile diesel located at Grand
Bay as well as Rose Blanche hydro site which can supply limited
load in area.
220 69 Bay d’Espoir Barachoix Loss of load on the Connaigre Peninsula
221 66 Peter’s Barren Hawke’s Bay Loss of load in the Hawke’s Bay/Port Saunders area. Hydro
maintains a 5 MW diesel plant at Hawke’s Bay that provides
limited back up.
226 66 Deer Lake Berry Hill Loss of load in Bonne Bay. TL226 can be isolated in various
locations such that Bonne bay area loads can be supplied from
Berry Hill following line switching.
227 66 Berry Hill Daniel’s Harbour Loss of load from Sally’s Cove to Parson’s Pond. TL227 can be
isolated in various locations such that loads from Sally’s Cove to
Daniel’s Harbour can be supplied from either Berry Hill or
Peter’s Barren following line switching.
229 66 Wiltondale Glenburnie Loss of load on western arm of Bonne Bay to Woody Point
239 138 Deer Lake Berry Hill Loss of load on Great Northern Peninsula north of Bonne Bay.
Hydro maintains 5 MW diesel plant at Hawke’s Bay and 9.7 MW
diesel plant at St. Anthony. With TL239 out switching on the 66
kV will permit up to 25 MVA to be supplied from Deer Lake on
the 66 kV TL226 to Berry Hill and then through the Berry Hill
138/66 kV transformer to the 138 kV system via TL259.
241 138 Berry Hill Plum Point Loss of load on Great Northern Peninsula north of Daniel’s
Harbour. Hydro maintains 9.7 MW diesel plant at St. Anthony
that provides limited back up.
244 138 Plum Point Bear Cove Loss of load on Great Northern Peninsula Bear Cove and north.
Hydro maintains 9.7 MW diesel plant at St. Anthony that
provides limited back up.
250 138 Bottom Brook Grandy Brook Loss of load in Burgeo
251 69 Howley Hampden Loss of load in White Bay
252 69 Hampden Jackson’s Arm Loss of load Jackson’s area of White Bay
254 66 Boyd’s Cove Farewell Head Loss of load Fogo and Change Islands
256 138 Bear Cove St. Anthony Airport Loss of load St. Anthony – Roddickton area. Hydro maintains 9.7
MW diesel plant at St. Anthony that provides limited back up.
257 69 St. Anthony Airport Roddickton Loss of load main brook and Roddickton
259 138 Berry Hill Peter’s Barren Loss of load on Great Northern Peninsula north of Parson’s
Pond. Hydro maintains 5 MW diesel plant at Hawke’s Bay and
9.7 MW diesel plant at St. Anthony. With TL259 out switching
on the 66 kV will permit up to 25 MVA to be supplied from
Berry Hill on the 66 kV TL227 to Peter’s Barren and then
through the Peter’s Barren 138/66 kV transformer to the 138
kV system via TL259.
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260 138 Seal Cove Bottom Waters Loss of load on the Baie Verte Peninsula
261 69 St. Anthony Airport St. Anthony Diesel Loss of load in the St. Anthony area. Hydro maintains 9.7 MW
diesel plant at St. Anthony that provides limited back up.
262 66 Peter’s Barren Daniel’s Harbour Loss of load in Daniel’s Harbour area. Switching on the 66 kV
results in supply of Daniel’s harbour via TL227
264 66 Buchans Duck Pond Loss of industrial customer
L1301/L1302 138 Churchill Falls Happy Valley Loss of load upper Lake Melville area. Hydro maintains a 25
MW gas turbine in Happy Valley that provides limited back up.
For single transformer stations with voltage ratings 138/66 kV, 138/25 kV, 138/12.5 kV, 66-69/25 kV and
66-69/12.5 kV Hydro maintains a 15 MVA mobile transformer that can be placed in service following the
failure of a transformer. For larger rated transformers, Newfoundland Power has mobile transformers
rated 25 MVA and 50 MVA that may be utilized by Hydro.
The contingency list for the steady state contingency analysis includes tripping of single elements. Table
3 highlights the elements and rationale for steady state contingency analysis.
Table 3 – Steady State Contingency Analysis Contingency List
Line Outs From To Rationale
TL202 Bay d’Espoir Sunnyside TL206 is parallel line with same rating
TL204 Bay d’Espoir Stony Brook TL231 is parallel line with same rating
TL207 Sunnyside Come by Chance TL203 is parallel line with lower rating
TL210 Stony Brook Cobb’s Pond
TL211 Massey Drive Bottom Brook TS2 Reduced capacity to ML
TL217 Western Avalon Soldiers Pond TL201 is parallel line with lower rating
TL218 Holyrood Oxen Pond
TL219 Sunnyside Salt Pond TL212 is parallel line with lower rating
TL222 Stony Brook Springdale Opens 138 kV loop
TL223 Springdale Indian River Opens 138 kV loop
TL224 Indian River Howley Opens 138 kV loop
TL232 Stony Brook Buchans TL205 is parallel line with lower rating
TL233 Buchans Bottom Brook TS2 Reduced capacity to west
TL234 Upper Salmon Bay d’Espoir Forces Upper Salmon and Granite Canal west
TL235 Stony Brook Grand Falls Freq Isolates Exploits generation
TL236 Hardwoods Oxen Pond Splits supply to St. John’s Area
TL237 Western Avalon Come By Chance TL203 is parallel line with lower rating
TL242 Soldiers Pond Hardwoods TL266 is parallel line with lower rating
TL245 Deer Lake Howley Opens 138 kV loop
TL247 Cat Arm Deer Lake Isolates Cat Arm generation
TL248 Deer Lake Massey Drive Isolates Cat Arm generation
TL2631
Granite Canal Tap Upper Salmon Operating Instruction in place
TL265 Holyrood Soldiers Pond TL268 is parallel line with same capacity
TL267 Bay d’Espoir Western Avalon Reduces capacity Bay d’Espoir east
TL269 Granite Canal Tap Bottom Brook TS2 Reduces capacity to ML
L3101 Churchill Falls TS2 Muskrat Falls TS2 L3102 is parallel line with same rating
L2303 Churchill Falls Wabush Terminal L2304 is parallel line with same rating
L3501 Muskrat Falls CS Soldiers Pond CS Loss of HVdc pole
Multi
Transformer
Stations
Station Unit Rationale
Wabush Terminal T7 Largest unit on 46 kV Bus #1
T8 Largest unit on 46 kV Bus #2
Wabush Substation T6 Largest unit in Station
Quartzite T1 Two units of same rating
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Vanier T1 Two units of same rating
Churchill Falls TS2 T1 Two units of same rating
Muskrat Falls TS2 T5 Two units of same rating
Happy Valley T1 Largest unit, run gas turbine
Bottom Brook T1 Two units same rating, close bus tie
Massey Drive T1 Largest unit close 66 kV Bus tie, CBP&P and NP on
same bus
Bay d’Espoir T10 Two units same rating
Grand Falls T2 Requires use of 13.8/6.9 kV tie transformers
Holyrood T5 Two units of same rating
Western Avalon T1 Two units of same rating
Looped Systems Station Unit Rationale
HWD-OPD Oxen Pond T3 Largest unit in Hardwoods – Oxen Pond Loop
WAV-HRD Holyrood T8 Largest unit in Western Avalon – Holyrood loop.
Alternative unit is WAV T5
STB-SSD Stony Brook T1 Largest unit in Stony Brook – Sunnyside Loop.
Alternative unit is SSD T1
Generation Station Unit Rationale
Holyrood G1 Largest unit
Bay d’Espoir G7
Cat Arm Plant Captured for TL247 outage
Soldiers Pond SC1 Loss of voltage support
Holyrood G3 as SC Loss of voltage control
Wabush Terminal SC1 Loss of voltage support
Wabush Terminal SC2 Loss of Voltage support
Shunts
Station Unit Rationale
Wabush Terminal C1 Loss of voltage support
C2 Loss of voltage support
Come By Chance C1 Four banks of same rating
Granite Canal Tap2
R1 Operating Instruction in place
Bear Cove R1 Light load cases only
Plum Point R2 Light load cases only
St. Anthony Airport C3 Peak load cases
Hardwoods C1 Two cap banks of same rating
Oxen Pond C2 Largest cap bank in station
HVdc
System Unit Rationale
LIL Pole 1 or Pole 2 Loss of active power
Loss of MFA Filter Loss of voltage support
Loss of SOP Filter Loss of voltage support
ML Pole 1 or Pole 2 Loss of active power and voltage support
Loss of BBK Filter Loss of voltage support
Loss of Link Loss of active power, voltage support intact
Notes:
1. There is an operating Instruction in place that requires Granite Canal tap shunt reactor R1 must be in-service to
avoid potential for self-excitation of Granite Canal for outages to TL263
2. For loss of Granite Canal Tap 230 kV shunt reactor there is an operating instruction in place to remove TL269 from
service, or shut down Granite Canal Generating Station to avoid self-excitation of the unit for loss of TL263.
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8.2.1 Line Out Contingency Analysis Near-Term Horizon
A review of the steady state line out contingency analysis for the near-term (Years Two and Five) reveal
that the following conditions:
• Loss of TL235 Stony Brook to Grand Falls results in loss of generation
• Loss of TL247/248 results in loss of Cat Arm generation
• In Year Two, prior to the interconnection of Muskrat Falls generators, the loss of 315 kV
transmission lines L3101 or L3102 will result in undervoltages at Muskrat Falls Terminal Station
2.
8.2.1.1 Near-Term Line Out Potential Mitigations
Line outages resulting in the loss of generation including TL235 and TL247/248 are mitigated by re-
dispatching generation to ensure sufficient generation and reserves are available.
The 315 kV, 150 MVAR shunt reactor at Muskrat Falls Terminal Station 2 will be equipped with
undervoltage protection to ensure that it is tripped if voltages drop below 0.88 per unit (277.2 kV).
8.2.2 Line Out Contingency Analysis Long-Term Horizon
A review of the steady state line out contingency analysis for the peak load condition in Year Ten (2027)
reveals no thermal overloads within the system.
The following conditions were noted for the peak load case:
• Loss of TL210 Stony Brook to Cobb’s Pond results in low voltages at Farewell Head
• Loss of TL219 Sunnyside to Salt Pond results in low voltages on the Burin Peninsula 138 kV
system south of Bay l’Argent
• Loss of TL235 Stony Brook to Grand Falls results in loss of generation
• Loss of TL247/248 results in loss of Cat Arm generation
A review of the steady state line out contingency analysis for the light load condition in Year Ten (2027)
reveals no thermal overloads within the system.
The following criteria violations were noted for the light load case:
• Loss of TL235 Stony Brook to Grand Falls results in loss of generation
• Loss of TL245 Deer Lake to Howley results in high line end voltages at Howley
• Loss of TL247/248 results in loss of Cat Arm generation
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8.2.2.1 Long-Term Line Out Potential Mitigations
Each of the criteria violations noted in the steady state line out contingency analysis of Year Tern can be
corrected by operator action as noted below.
The long-term peak load case criteria violations are corrected as follows:
• The low voltages at Farewell Head resulting from the loss of TL210 Stony Brook to Cobb’s Pond
are corrected by placing the 230/138 kV transformer OLTCs at Stony Brook and Sunnyside in
manual and adjusting the Sunnyside 138 kV bus voltage to 1.031 p.u. and the Stony Brook 138
kV bus voltage to 1.030 p.u.
• low voltages on the Burin Peninsula 138 kV system south of Bay l’Argent resulting from the loss
of TL219 Sunnyside to Salt Pond are corrected by placing the Greenhill Gas Turbine in service at
a minimum load of 5 MW
• the generation deficiency resulting from the loss of TL235 Stony Brook to Grand Falls can be
eliminated by increasing the Labrador – Island HVdc Link power order by 60 MW or increasing
the output of the Holyrood Combustion Turbine to 123 MW
• the generation deficiency resulting from the loss of TL247/248 and Cat Arm can be eliminated by
increasing the LIL import by 70 MW and the Holyrood Combustion Turbine output to 123.5 MW
The long-term light load case criteria violations are corrected as follows:
• The generation deficiency resulting from the loss of TL235 Stony Brook to Grand Falls can be
eliminated by increasing the LIL import by 60 MW
• Potential high line end voltages at Howley resulting from the loss of TL245 Deer Lake to Howley
are eliminated by reducing the Stony Brook 138 kV bus voltage to 1.01 p.u. through manual
operation of the Stony Brook 230/138 kV transformer OLTCs
• The generation deficiency resulting from the loss of TL247/248 and Cat Arm can be eliminated
by increasing generation output at the Bay d’Espoir generating Station during the light load
conditions.
The steady state line out contingency analysis for the long term planning horizon has not indicated a
need for transmission line addition or reinforcement.
8.2.3 Summary of Multi Transformer Station Contingency Loading
Table 4 provides the transformer loading for each multi transformer station with the largest transformer
out of service. Mitigations for prospective overload conditions are addressed in the following section.
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Table 4– Multi Transformer Contingency Load Levels1
Station Unit Rating
MVA
2019 2022 2027
MVA % MVA % MVA %
Bay d’Espoir T10 15/20/25 Out-of-Service
T12 15/20/25 23.65 94.6% 21.80 87.2% 21.26 85.0%
Bottom Brook2
T1 25/33.3/41.7 29.76 71.4% 29.05 69.7% 18.20 43.6%
T3 25/33.3/41.7 Out-of-Service
Churchill Falls T31 75/100/125 Note 3
T32 25/33/42
Churchill Falls 2 T1 840 Note 4
T2 840
Come By Chance T1 30/40/50 Out-of-Service
T2 30/40/50 40.28 80.6% 40.04 80.1% 40.09 80.2%
Daniel’s Harbour T1 1/1.3 Out-of-Service
T2 1 1.22 122.0% 1.13 113.0% 1.10 110.0%
Grand Falls Frequency
Converter
T1 30/40/50 32.56 65.1% 32.26 64.5% 32.19 64.4%
T2 30/40/50 Out-of-Service
T3 30/40/50 30.88 61.8% 31.28 62.6% 31.41 62.8%
Happy Valley10
T1 30/40/50 Out-of-Service
T2 15/20/25//28 30.25 108.0% 32.56 116.3% 33.63 120.1%
T4 15/20/25//28 30.25 108.0% 32.56 116.3% 33.63 120.1%
Hawke’s Bay5
T1 5/6.7 Out-of-Service
T2 2.5/3.3 1.51 45.8% 1.02 31.0% 0.87 26.3%
Holyrood6 T5 15/20/25 12.19 48.8% 12.55 50.2% 12.83 51.3%
T10 15/20/25 Out-of-Service
Massey Drive7
T1 75/100/125 Out-of-Service
T2 40/53.3/66.6 51.04 76.6% 52.2 78.2% 50.38 75.6%
T3 75/100/125 90.47 68.7% 92.5 70.1% 89.29 67.8%
Muskrat Falls TS2
T5 75/100/125 Note 3
T6 75/100/125
Quartzite T1 15/20/25 Note 3
T2 15/20/25
Vanier T1 15/20/25 Note 3
T2 15/20/25
Voisey’s Bay Nickel T1 75/100/125 62.18 49.7% 61.32 49.1% 61.29 49.0%
T2 75/100/125 Out-of-Service
Wabush Terminal8
T1 35/47//65
Note 3
T2 35/47//65
T3 35/47//65
T4 35/47//65
T5 35/47//65
T6 35/47//65
T7 50/66.6/83.3
T8 50/66.6/83.3
Wabush Substation T3 5/6.6/8.3
T4 5/6.6/8.3
T5 3.0
T6 10/13.3/16.7
Western Avalon9 T1 15/20/25 Out-of-Service
T2 15/20/25 24.34 97.4% 23.19 92.8% 16.49 66.0%
Notes:
1. The loading provided is with the largest transformer in the station removed from service and back up generation on line where applicable.
2. Bottom Brook 138 kV bus tie switch B2B3 closed
3. The long-term plan for the Labrador Interconnected System is currently under review.
4. Expected loading on the 735kV/315kV transformers in Churchill Falls Terminal Station 2 will be determined based on the results of a 2018
operational study.
5. Hawke’s Bay diesels on line for 5 MW.
6. The Holyrood diesel units were assumed to not be in-service, as black start diesels will not be required at Holyrood following shut down of
the thermal plant. In the event T10 is out-of-service, transmission line 52L must be opened to offload T5.
7. 66 kV bus tie B2B4-1 closed
8. Wabush Terminal Station T1, T2, T3 loading with T7 out, T4, T5, T6 loading with T8 out.
9. In the event T1 is out-of-service, transmission line 41L must be opened to offload T1.
10. For the loss of a transformer at Happy Valley it is assumed that the gas turbine will operate for 25 MW.
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The analysis of multi transformer station transformer contingencies indicates:
• Loss of Daniels Harbour T1, a 66/12.5 kV, 1.0/1.33 MVA unit, will result in the overload of the
remaining transformer T2, a 66/12.5 kV, 1.0 MVA unit in both the near-term and long-term
horizons.
• Loss of Happy Valley T1, a 138/25 kV, 30/40/50 MVA unit, will result in the overload of the
remaining transformers T2 and T3 (138/25 kV, 15/20/25//28 MVA units) in both the near-term
and long-term horizons even with the Happy Valley gas turbine operating at 25 MW during the
T1 outage over peak.
• Loss of Holyrood T10, a 230/69 kV, 15/20/25 MVA unit, will result in the overload of the
remaining transformer T5, a 230/69 kV, 15/20/25 MVA unit in both the near-term and long-term
horizons.
• Loss of Western Avalon T1, a 230/66 kV, 15/20/25 MVA unit, will result in the overload of the
remaining transformer T2, a 230/66 kV, 15/20/25 MVA unit in both the near-term and long-term
horizons.
8.2.3.1 Multi-Transformer Mitigations
The following mitigation measures are employed for the overloads identified in the multi transformer
station transformer contingency analysis:
• For loss of Daniels Harbour T1, a 66/12.5 kV, 1.0/1.33 MVA unit, which results in the overload of
the remaining transformer T2, a 66/12.5 kV, 1.0 MVA unit in both the near-term and long-term
horizons, Hydro’s mobile transformer can be installed. Further, Hydro is working with the
manufacturer of the Daniels Harbor T2 unit to determine if the unit can be upgraded to a
1.0/1.33 MVA rating. In addition, given the land slides in the vicinity of the Daniels Harbour
Terminal Station, Hydro is investigating the relocation of the 66/12.5 kV transformers at Daniels
Harbour to Peter’s Barren Terminal Station.
• For loss of Happy Valley T1, a 138/25 kV, 30/40/50 MVA unit, which results in the overload of
the remaining transformers T2 and T3 (138/25 kV, 15/20/25//28 MVA units) in both the near-
term and long-term horizons even with the Happy Valley gas turbine operating at 25 MW during
the T1 outage over peak, Hydro will be addressing the issue in accordance with PUB Order No.
P.U. 9(2018).
• Loss of Holyrood T10, a 230/69 kV, 15/20/25 MVA unit, which results in the overload of the
remaining transformer T5, a 230/69 kV, 15/20/25 MVA unit in both the near-term and long-term
horizons, is dealt with by opening Newfoundland Power 66 kV line 52L between Kelligrews and
Seal Cove to offload Holyrood T5. The mitigation action has no loss of customer load. Seal Cove
Substation is supplied radially from Holyrood and Kelligrews Substation is supplied radially from
Chamberlains Substation. Chamberlains is supplied, in turn, by two 66 kV transmission lines
connected to Hardwoods Terminal Station.
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• Loss of Western Avalon T1, a 230/66 kV, 15/20/25 MVA unit, which results in the overload of
the remaining transformer T2, a 230/66 kV, 15/20/25 MVA unit in both the near-term and long-
term horizons, is dealt with by opening Newfoundland Power 66 kV line 41L between Heart’s
Content Substation and Carbonear Substation. The mitigation action has no loss of customer
load. Blaketown, New Harbour, Islington, Heart’s Content, New Chelsea and Old Perlican
Substations are supplied from Western Avalon/Blaketown. Island Cove, Harbour Grace,
Carbonear and Victoria Substations are supplied from Bay Roberts Substation.
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8.2.4 Summary of Looped System Transformer Contingency Loading
Table 5 provides the transformer loading for each Looped System following the loss of the largest
transformer in the Loop. Mitigations for each prospective overload condition are addressed in the
following section.
Table 5– Looped System Transformer Contingency Load Levels1
Station Unit Rating
MVA
2019 2022 2027
MVA % MVA % MVA %
Hardwoods – Oxen Pond 66 kV Loop2
Hardwoods T1 75/100/125 82.8 66.1% 97.2 76.4% 100.0 78.4%
T2 40/53.3/66.6 42.3 63.4% 49.6 73.2% 51.0 75.1%
T3 40/53.3/66.6 45.6 85.6% 53.6 98.8% 55.1 101.2%
T4 75/100/125 82.1 65.6% 96.4 75.8% 99.2 77.8%
Oxen Pond T1 75/100/125 244.2 94.5% 250.0 96.4% 256.6 98.8%
T2 150/200/250 117.8 91.1% 120.6 92.9% 123.7 95.2%
T3 150/200/250 Out-of-Service
Holyrood - Western Avalon 138 kV Loop
Holyrood T6 25/33.3/41.7 14.2 33.1% 14.8 34.4% 15.2 35.5%
T7 25/33.3/41.7 14.1 32.9% 14.7 34.2% 15.1 35.2%
T8 75/100/125 41.1 32.0% 42.9 33.3% 44.2 34.3%
Western Avalon T1 15/20/25 18.25 72.9% 17.31 66.9% 18.42 71.8%
T2 15/20/25 18.58 74.2% 17.62 68.1% 18.76 73.2%
T3 25/33.3/41.7 37.10 89.0% 34.06 79.1% 34.14 80.0%
T4 25/33.3/41.7 36.90 88.5% 33.87 78.6% 33.95 79.5%
T5 75/100/125 Out-of-Service
Stony Brook - Sunnyside 138 kV Loop3
Sunnyside T1 75/100/125 92.68 72.8% 92.38 73.3% 95.65 75.6%
T4 75/100/125 93.34 76.1% 93.04 73.8% 96.33 76.1%
Stony Brook T1 75/100/125 Out-of-Service
T2 75/100/125 111.96 88.0% 118.73 92.5% 118.47 92.5%
Stephenville – Bottom Brook 66kV Loop4
Stephenville T3 40/53.3/66.6 Out-of-Service Note 5
Bottom Brook T2 15/20/25 4.2 16.8%
Notes:
1. The operation of each loop of transformers assumes the loss of the largest unit contained within the loop
at each end to provide for maximum operational reliability. If there is more than one transformer with the
same rating, the one with the lowest impedance is chosen to be switched off. In scenarios where there is
a transformer overloaded, it may be mitigated by breaking the loop in various locations to offload the
overloaded transformer.
2. For loss of a transformer in the Hardwoods – Oxen Pond 66 kV Loop the Hardwoods gas turbine is
operated at 50 MW. It is assumed that Hardwoods Gas Turbine will be retired in 2022.
3. The following generation is assumed to be online within this 138kV loop: Greenhill Gas Turbine, Paradise
River , Wesleyville Gas Turbine, St. Anthony Diesels , Hind’s Lake, Hawke’s Bay Diesel and Rattle Brook
4. The Stephenville Gas Turbine is assumed to be online (50MW) in 2019
5. The Stephenville Gas Turbine is to be retired by 2022. The plan is to install a 230/66 kV, 40/53.3/66.7
MVA power transformer at Bottom Brook Terminal Station. The addition of the 230/66 kV transformer at
Bottom Brook Terminal Station will provide back up or spare transformer capacity for the loss of existing
230/66 kV transformer T3 at Stephenville Terminal Station or loss of 230 kV transmission line TL209.
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The analysis of looped system transformer contingencies indicates:
• For the Hardwoods - Oxen Pond 66 kV Loop the loss of Oxen Pond T3 (a 230/66 kV, 150/200/250
MVA unit) will result in the highest loads levels on the remaining transformers. Should Hydro
retire the Hardwoods gas turbine in the 2022 time frame, it is expected that there will be a
transformer overload within the loop in the long-term horizon.
• No transformer overloads are expected in the Holyrood - Western Avalon 138 kV Loop in either
the near-term or long-term horizon.
• For the Stony Brook – Sunnyside 138 kV Loop overload of the remaining 230/138 kV
transformers is expected for the loss of a 230/138 kV, 75/100/125 MVA transformer at Stony
Brook Terminal Station.
• The Stephenville – Bottom Brook 66 kV Loop operates normally open at the Bottom Brook end
such that all load in the Stephenville area is supplied via 230 kV transmission line TL209 and the
Stephenville Terminal Station. For the loss of the single 230/66 kV transformer at Stephenville,
the Stephenville gas turbine is operated for 50 MW. Under light load conditions the 66 kV loop
can be closed such that the Stephenville is supplied via a 138/66 kV, 15/20/25 MVA transformer,
T2, at Bottom Brook and Newfoundland Power 66 kV line 400 L. If Hydro were to retire the
Stephenville gas turbine in the 2022 time frame, it would not be able to supply all load in the
Stephenville area for loss of the 230/66 kV transformer at Stephenville Terminal Station.
8.2.4.1 Looped System Transformer Mitigations
The following mitigation measures are employed/proposed for the overloads identified in the looped
system transformer contingency analysis:
• For the Hardwoods - Oxen Pond 66 kV Loop the loss of Oxen Pond T3 (a 230/66 kV, 150/200/250
MVA unit) results in transformer overload in the long-term horizon should Hydro decide to
retire the Hardwoods Gas Turbine. Several capacity/transmission mitigation measures are
available, including:
o Replace the Hardwoods Gas Turbine
o Add new gas turbine capacity within the Hardwoods – Oxen Pond 66 kV Loop
o Increase transformer capacity in the Hardwoods – Oxen Pond 66 kV Loop in 2027 to
meet the load growth and planning criteria
o Each of these alternatives is being considered in Hydro’s Resource Adequacy Study to be
completed in 2018.
• For the Stony Brook – Sunnyside 138 kV Loop overload of the remaining 230/138 kV
transformers is expected for the loss of a 230/138 kV, 75/100/125 MVA transformer at Stony
Brook Terminal Station is mitigated in the near-term by opening the 138 kV Loop on the
Gander/Gambo region to off load the remaining Stony Brook transformer. Analysis has
indicated that with the loop open during the transformer contingency 138 kV bus voltages on
the order of 90% can be expected to occur in the Gambo area. To this end, Hydro is working
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with Newfoundland Power to determine an appropriate long-term solution to the issue. Long-
term transmission mitigation strategies may include:
o Additional transformer capacity within the loop
o Construction of additional 138 kV transmission line(s) in the Gander to Clarenville
portion of the loop
o Addition of reactive power support to maintain acceptable voltages during the
transformer contingency
o Each alternative must be assessed for technical viability and a cost benefit analysis
completed to determine the least cost reliable alternative
• The retirement of the Stephenville Gas Turbine will have a significant impact on the reliability of
the supply to the customer sin the Stephenville area. Instead of being able to supply the entire
load for loss of the 230/66 kV transformer at Stephenville or the loss of the 230 kV line TL209,
the transfer capacity will be reduced to approximately 20 MW. The long-term mitigation
strategy to maintain full back up supply to the Stephenville area for loss of the 230/66 kV
transformer at Stephenville or the loss of TL209 is to add a 230/66 kV, 40/53/3/66.6 MVA
transformer at Bottom Brook to replace the 138/66 kV, 15/20/25 MVA unit.
8.2.5 Generator and Synchronous Condenser Contingency Analysis Near-Term Horizon
Hydro operates the system with sufficient spinning reserve to cover the loss of the largest on line unit.
Prior to the completion of the Muskrat Falls Generating Station, the largest on-line unit has a capacity of
170 MW (i.e. Holyrood Units 1 and 2). Following the loss of a generator the spinning reserve is utilized
to match generation and load. In the near-term there is sufficient capacity to meet the load
requirement with spinning reserve.
The loss of a synchronous condenser at Wabush Terminal Station in western Labrador will result in low
voltages and tripping of loads. Permanent loss of a synchronous condenser requires a reduction in the
transfer capacity of the system in western Labrador. Note that a comprehensive review of the
transmission system in western Labrador is underway and will be covered under a separate report.
The loss of the Happy Valley gas turbine in synchronous condenser mode in eastern Labrador will result
in low voltages and tripping of loads. Permanent loss of the synchronous condenser requires a reduction
in the transfer capacity of the system in eastern Labrador. Hydro will be addressing the issue in
accordance with PUB Order No. P.U. 9(2018).
8.2.5.1 Near-Term Generator and Synchronous Condenser Potential Mitigations
Hydro has historically utilized an under frequency load shedding (UFLS) scheme to trip predefined load
blocks following a generator trip to re-establish a balance between generation and load and return the
system frequency to 60 Hz. This scheme has been necessary given the limited inertia on the isolated
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system on the Island and the response of the Island generator governors. With the addition of the HVdc
links, the application of frequency controllers will mitigate UFLS. Analysis associated with the final
configuration of frequency controllers and the coordinated runbacks of the links will be completed as
part of operational studies and will be included in the 2019 Annual Planning Assessment.
8.2.6 Generator and Synchronous Condenser Contingency Analysis Long-Term Horizon
In addition to operational studies, Hydro is completing a long term resource adequacy analysis to assess
the future generator capacity requirements. The report will be completed in 2018.
8.2.6.1 Long-Term Generator and Synchronous Condenser Potential Mitigations
Long-term generator contingency mitigation strategies will be assessed under the resource adequacy
report.
8.2.7 Shunt Contingency Analysis
The 230 kV, 15 MVAR shunt reactor at Granite Canal Tap was added to the system as part of the 230 kV
TL269 (Granite Canal Tap to Bottom Brook) transmission line addition to prevent self-excitation of the
Granite Canal generator should the generator and TL269 become isolated from the system. Loss of the
Granite Canal Tap shunt reactor results in a potential for self-excitation of the Granite Canal generator.
The transmission system on the Great Northern Peninsula (GNP) has three 138 kV, 5 MVAR shunt
reactors (two at Plum Point and one at Bear Cove) for voltage reduction during light load, and three 69
kV, 3 MVAR switched shunt capacitor banks at St. Anthony Airport for voltage support during peak load.
There is sufficient shunt reactor capacity to maintain acceptable bus voltages under light load with one
shunt reactor and all capacitor banks out of service through the long-term horizon. There is sufficient
shunt capacitor capacity to maintain acceptable bus voltages under peak load conditions through the
long-term horizon with one shunt capacitor unavailable.
The transmission system within the Hardwoods – Oxen Pond 66 kV Loop contains four 66 kV switched
shunt capacitor banks; two at each of Hardwoods and Oxen Pond Terminal Stations. An outage to any
single capacitor bank within the loop does not result in unacceptable bus voltages.
There are four, 230 kV, 38.4 MVAR shunt capacitor banks at Come By Chance Terminal Station. Two
banks may are removed from service for a 230 kV bus outage or 230 kV line outage at Come By Chance.
This potential loss of two capacitor banks does not result in unacceptable bus voltages through the long-
term horizon.
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In Year Two the Muskrat Falls generators are not yet in service. The loss of the 315 kV, 150 MVAR shunt
reactor at Muskrat Falls will result in overvoltages due to the charging associated with 315 kV
transmission lines L3101 and L3102.
The loss of a 46 kV, 25.2 MVAR shunt capacitor at Wabush Terminal Station in western Labrador will
result in low voltages and tripping of loads. Permanent loss of a shunt capacitor requires a reduction in
the transfer capacity of the system in western Labrador. A comprehensive review of the transmission
system in western Labrador is underway and will be covered under a separate report.
The Happy Valley Terminal Station includes four switched shunt capacitor banks for a total of 11.4
MVAR. In addition, the Muskrat Falls construction power station (MFATS3) includes six 3.6 MVAR
switched shunt capacitor banks. Combined these switched shunts provide the necessary voltage support
to transfer power from Churchill Falls to Happy Valley. Loss of a shunt capacitor bank will result in low
voltages and a requirement to reduce transfer capacity on the 138 kV system in eastern Labrador. Hydro
will be addressing the issue in accordance with PUB Order No. P.U. 9(2018).
8.2.7.1 Shunt Device Potential Mitigations
To avoid potential for self-excitation of Granite Canal generator an operating instruction has been
prepared to remove TL269 from service when the Granite Canal Tap shunt reactor is out of service.
The extent of overvoltages at Muskrat Falls Terminal Station 2 as a result of the tripping of the 315 kV,
150 MVAR shunt reactor are impacted by PUB Order No. P.U. 9(2018) and the fact that the Muskrat
Falls-Happy Valley Interconnection project has not been approved. Hydro will address these
overvoltages in further operational studies and discussion will be included in the 2019 Annual Planning
Assessment.
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9 SHORT CIRCUIT ANALYSIS
Short circuit analysis is required to ensure that the prospective short circuits at equipment locations do
not exceed the interrupting capacity of the circuit breakers used to protect the equipment. As
equipment is added, or reconfigured, short circuit levels change. Therefore, regular assessment of the
system short circuit levels is prudent. The maximum short circuit levels will be observed when all
equipment is in service and all generation and motor load is connected. Given the known system
changes occurring between Year One, Two, Five and Ten the Planning Authority is completing short
circuit analysis for Year Two, Year Five and Year Ten as part of the 2018 Annual Planning Assessment.
A review of short circuit levels for Years Two, Five and Ten reveals that the maximum short circuit levels
within the Island Interconnected System (IIS) will occur in Year Two. The Year Two levels are the highest
within the planning horizon given the phased approach of the Lower Churchill Project implementation.
In Year Two the Holyrood Thermal Generating Station will be in operation over peak. At the same time
the Soldiers Pond synchronous condensers and LIL will be in-service delivering un-used recall power
from Labrador.
The Year Five and Year Ten cases have the Muskrat Falls Generating Station complete and the Holyrood
Thermal Generating Station out of service. With Holyrood Units 1 and 2 not in operation in Years Five
and Ten, the IIS short circuit levels will be reduced when compared to Year Two.
The short circuit analysis indicates that there are no circuit breaker rating violations within the near-
term or long-term planning horizons.
Hydro’s ongoing supply adequacy analysis includes prospective generation additions that will impact
short circuit levels within the IIS. Transmission Planning analysis will be performed as part of this
exercise to identify if circuit breaker ratings are exceeded and if replacements are required.
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10 STABILITY ANALYSIS
Stability studies are required for planning events to determine whether the transmission system meets
the performance requirements on the Contingency list described in the NLSO Standard Transmission
Planning Criteria. This contingency list includes:
• Tripping of a single transmission line, transformer, generator, synchronous condenser, shunt
capacitor bank, shunt reactor or series compensation device without a fault
• Successful single pole reclosing for ac transmission lines on line to ground faults
• Unsuccessful single pole reclosing for ac transmission lines on line to ground faults
• Three phase faults except a three phase fault on, or near, the Bay d’Espoir 230 kV bus with
tripping of a 230 kV transmission line
• Loss of the largest generator on line on the Island System with and without fault
• Line to ground or three phase fault with tripping of a synchronous condenser
• Fault and tripping of a series compensated 230 kV transmission line with the series
compensation device out of service on the in service parallel 230 kV transmission line
• Temporary pole fault on HVdc system
• Permanent pole fault on HVdc system
• Temporary bipole fault on HVdc system
Further, contingency analyses for the Stability Analysis shall:
• Simulate the removal of all elements that the Protection System and other automatic controls
are expected to disconnect for each Contingency without operator intervention. The analyses
includes the impact of subsequent:
o Successful high speed (less than one second) reclosing and unsuccessful high speed
reclosing into a Fault where high speed reclosing is utilized.
o Tripping of generators where simulations show generator bus voltages or high side of
the GSU voltages are less than known or assumed generator low voltage ride through
capability. Include in the assessment any assumptions made.
o Tripping of Transmission lines and transformers where transient swings cause
Protection System operation based on generic or actual relay models.
o Simulation of the expected automatic operation of existing and planned devices
designed to provide dynamic control of electrical system quantities when such devices
impact the study area. These devices may include equipment such as generation exciter
control and power system stabilizers, static var compensators, power flow controllers,
and DC Transmission controllers.
• For single contingency planning events (N-1): No generating unit shall pull out of synchronism. A
generator being disconnected from the System by fault clearing action or by a Special Protection
System is not considered pulling out of synchronism.
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10.1 System Stability Near-Term Horizon
Given the phased approach for the implementation of the Lower Churchill Project, TransGrid Solutions
Inc. (TGS), on behalf of, and in cooperation with, the NLSO Transmission Planning Department, has
completed a number of system studies to assess system stability and transfer limits in the near-term
horizon.
Stability analysis has been completed for the addition of the Maritime Link. Detailed results can be
found in the TGS report entitled “Operational Studies: Maritime Link ONLY”, dated November 10, 2017
and filed with the PUB. Import and export limits were determined to ensure that the steady state and
dynamic Transmission Planning Criteria were met. The results indicate that a firm import of 108 MW is
available at Bottom Brook based upon the Island Interconnected System ability to accept 108 MW of
import capacity independent of system load and generation dispatch. Up to an additional 192 MW of
non-firm import capacity is available at Bottom Brook depending upon the Island Interconnected System
load. The export limit at Bottom Brook is a function of not only the Island load but also the generation
dispatch and particularly, the number of thermal units on line at Holyrood. The firm export limit is set at
55 MW at Bottom Brook. Up to an additional 70 MW of non-firm of non-firm export is available at
Bottom Brook depending upon the Island Interconnected System load and status of generation at
Holyrood.
Stability analysis has been completed for the addition of the Maritime Link and Soldiers Pond
Synchronous Condensers. Detailed results can be found in the TGS report entitled “Operational Studies:
Maritime Link and Soldiers Pond Synchronous Condensers”, dated November 10, 2017 and filed with the
PUB. Import and export limits were determined to ensure that the steady state and dynamic
Transmission Planning Criteria were met. The results indicate that a firm import of 108 MW is available
at Bottom Brook based upon the Island Interconnected System ability to accept 108 MW of import
capacity independent of system load and generation dispatch. Up to an additional 242 MW of non-firm
import capacity is available at Bottom Brook depending upon the Island Interconnected System load.
The export limit at Bottom Brook is a function of not only the Island load but also the generation
dispatch and particularly, the number of thermal units on line at Holyrood. The firm export limit is set at
55 MW at Bottom Brook. Up to an additional 70 MW of non-firm of non-firm export is available at
Bottom Brook depending upon the Island Interconnected System load and status of generation at
Holyrood.
Stability analysis has been completed for the addition of the Maritime Link and Soldiers Pond
Synchronous Condensers with the Labrador – Island HVdc Link in monopolar mode. Detailed results can
be found in the TGS reports:
• “Operational Studies: Maritime Link, SOP Syncs and LIL Monopole”, dated February 27, 2018
and
• “Maximization of LIL Power Transfer using SPS (phased monopolar approach)”, dated March 5,
2018
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Import and export limits on the Maritime Link and import limits on the LIL were determined to ensure
that the steady state and dynamic Transmission Planning Criteria were met. The results indicate that a
LIL transfers are limited as a function of the following parameters:
• The status of the ML frequency controller
• The number of SOP synchronous condensers that are in service
• The Churchill Falls bus voltage
• Loads at Happy Valley Terminal Station6
There will be no frequency controller on the LIL in the initial monopolar mode of operation. Therefore,
the import and export limits on the Maritime Link will be dependent upon the number of high inertia
synchronous condensers in service and the thermal units on-line at Holyrood. The results indicate that a
firm import of 108 MW is available at Bottom Brook based upon the Island Interconnected System
ability to accept 108 MW of import capacity independent of system load and generation dispatch. Up to
an additional 242 MW of non-firm import capacity is available at Bottom Brook depending upon the
Island Interconnected System load. The export limit at Bottom Brook is a function of not only the Island
load but also the generation dispatch and particularly, the number of thermal units on line at Holyrood.
The firm export limit is set at 55 MW at Bottom Brook. Up to an additional 70 MW of non-firm of non-
firm export is available at Bottom Brook depending upon the Island Interconnected System load and
status of generation at Holyrood and number of high inertia synchronous condensers on-line at Soldiers
Pond.
A special protection scheme (SPS) was proposed to trip the LIL, its harmonic filters and the Muskrat Falls
shunt reactor for the loss of a 315 kV line (either L3101 or L3102) in Labrador to avoid steady state
voltages below 0.90 p.u. Voltage regulation of the 315 kV transmission system will be impacted by PUB
Order No. P.U. 9(2018) and the fact that the Muskrat Falls-Happy Valley Interconnection project has not
been approved. This will be addressed in further operational studies.
10.2 System Stability Long-Term Horizon
Stability studies of the completed Lower Churchill Project (HVdc link in operation at bipole mode at
rated capacity and Muskrat Falls Generating Station complete) are the subject of the ongoing
operational studies. The results of these studies will be included in the 2019 annual assessment.
6 At the time of the analysis, it was assumed that the Muskrat Falls-Happy Valley interconnection project would be
in-service for the near-term planning horizon. This interconnected would impact the 315 kV bus voltages at
Muskrat Falls Terminal Station 2 and would therefore impact LIL power transfers. As this project has not been
approved, the impacts of this parameter on LIL power transfers can be neglected.
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11 CONCLUSIONS
The 2018 Annual Planning Assessment focuses on Year Two (2019) and Year Five (2022) for the near-
term planning horizon and Year Ten (2027) for the long-term planning horizon. This assessment does
not include the transmission system in western Labrador, which is the subject of a separate
comprehensive review and will be covered under a separate report. In addition, the assessment does
not include a detailed review of the transmission system in eastern Labrador, as this will be covered in
accordance with the PUB Order No. P.U. 9(2018). Given the phased approach to the implementation of
the Lower Churchill Project, stability analysis of the long-term horizon case is in progress as part of the
ongoing operational studies of the new approach and will be submitted with the 2019 Annual Planning
Assessment.
The 2018 Annual Planning Assessment reveals:
• The pre-contingency steady state analysis indicates not transmission equipment overloads or
voltage violations in the near-term or long-term planning horizons.
o In Year Two, prior to the generators as Muskrat Falls being placed in service, the LIL
must be operated within specified limits to ensure acceptable voltage regulation of the
315 kV transmission system in Labrador. This regulation will be impacted by PUB Order
No. P.U. 9(2018) and the fact that the Muskrat Falls-Happy Valley Interconnection
project has not been approved. This will be addressed in further operational studies.
• The steady state line out contingency analysis indicates:
o The loss of TL235 (Stony Brook to Grand Falls) or TL247/248 (Cat Arm to Deer Lake to
Massey Drive) will result in the loss of generation
� The generation deficiency is mitigated by re-dispatch of existing generation
o Loss of TL210 Stony Brook to Cobb’s Pond results in low voltages at Farewell Head
� The low voltages are mitigated by placing the 230/138 kV transformer OLTCs at
Stony Brook and Sunnyside in manual and adjusting the Sunnyside 138 kV bus
voltage to 1.031 p.u. and the Stony Brook 138 kV bus voltage to 1.030 p.u.
o Loss of TL219 Sunnyside to Salt Pond results in low voltages on the Burin Peninsula 138
kV system south of Bay l’Argent
� The low voltages are mitigated by placing the Greenhill Gas Turbine in service
at a minimum load of 5 MW
o In Year Two, prior to the interconnection of Muskrat Falls generators, the loss of 315
kV transmission lines L3101 or L3102 will result in undervoltages at Muskrat Falls
Terminal Station 2.
o The 315 kV, 150 MVAR shunt reactor at Muskrat Falls Terminal Station 2 will be
equipped with undervoltage protection to ensure that it is tripped if voltages drop
below 0.88 per unit (277.2 kV).
• The steady state multi transformer station transformer contingencies analysis indicates:
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o Loss of Daniels Harbour T1, a 66/12.5 kV, 1.0/1.33 MVA unit, will result in the overload
of the remaining transformer T2, a 66/12.5 kV, 1.0 MVA unit in both the near-term and
long-term horizons.
� The overload is mitigated by installation of Hydro’s mobile transformer.
Further, Hydro is working with the manufacturer of the Daniels Harbor T2 unit
to determine if the unit can be upgraded to a 1.0/1.33 MVA rating.
o Loss of Happy Valley T1, a 138/25 kV, 30/40/50 MVA unit, will result in the overload of
the remaining transformers T2 and T3 (138/25 kV, 15/20/25//28 MVA units) in both
the near-term and long-term horizons even with the Happy Valley gas turbine
operating at 25 MW during the T1 outage over peak.
� Hydro will be addressing the issue in accordance with PUB Order No. P.U.
9(2018).
o Loss of Holyrood T10, a 230/69 kV, 15/20/25 MVA unit, will result in the overload of
the remaining transformer T5, a 230/69 kV, 15/20/25 MVA unit in both the near-term
and long-term horizons.
� The overload is mitigated by opening Newfoundland Power 66 kV line 52L
between Kelligrews and Seal Cove to offload Holyrood T5. The mitigation
action has no loss of customer load. Seal Cove Substation is supplied radially
from Holyrood and Kelligrews Substation is supplied radially from
Chamberlains Substation. Chamberlains is supplied, in turn, by two 66 kV
transmission lines connected to Hardwoods Terminal Station.
o Loss of Western Avalon T1, a 230/66 kV, 15/20/25 MVA unit, will result in the overload
of the remaining transformer T2, a 230/66 kV, 15/20/25 MVA unit in both the near-
term and long-term horizons.
� The overload is mitigated by opening Newfoundland Power 66 kV line 41L
between Heart’s Content Substation and Carbonear Substation. The mitigation
action has no loss of customer load. Blaketown, New Harbour, Islington,
Heart’s Content, New Chelsea and Old Perlican Substations are supplied from
Western Avalon/Blaketown. Island Cove, Harbour Grace, Carbonear and
Victoria Substations are supplied from Bay Roberts Substation.
• The steady state looped system transformer contingency analysis indicates:
o The loss of Oxen Pond T3 (a 230/66 kV, 150/200/250 MVA unit) in the Hardwoods -
Oxen Pond 66 kV Loop will result in the highest loads levels on the remaining
transformers. Should Hydro retire the Hardwoods gas turbine in the 2022 time frame,
it is expected that there will be a transformer overload within the loop in the long-term
horizon.
� Potential mitigation measures for this potential long-term horizon overload
include:
• Replace the Hardwoods Gas Turbine
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• Add new gas turbine capacity within the Hardwoods – Oxen Pond 66
kV Loop
• Increase transformer capacity in the Hardwoods – Oxen Pond 66 kV
Loop in 2027 to meet the load growth and planning criteria
� Each of these alternatives is being considered in Hydro’s Resource Adequacy
Study to be completed in 2018.
o No transformer overloads are expected in the Holyrood - Western Avalon 138 kV Loop
in either the near-term or long-term horizon.
o The loss of a 230/138 kV, 75/100/125 MVA transformer at Stony Brook Terminal
Station in the Stony Brook – Sunnyside 138 kV Loop will overload the remaining
230/138 kV transformers in both the near-term and long-term planning horizons.
� The overload is mitigated in the near-term by opening the 138 kV Loop on the
Gander/Gambo region to off load the remaining Stony Brook transformer.
Analysis has indicated that with the loop open during the transformer
contingency 138 kV bus voltages on the order of 90% can be expected to occur
in the Gambo area. To this end, Hydro is working with Newfoundland Power to
determine an appropriate long-term solution to the issue.
� Long-term transmission mitigation strategies may include:
• Additional transformer capacity within the loop
• Construction of additional 138 kV transmission line(s) in the Gander to
Clarenville portion of the loop
• Addition of reactive power support to maintain acceptable voltages
during the transformer contingency
� Each alternative must be assessed for technical viability and a cost benefit
analysis completed to determine the least cost reliable alternative
o The Stephenville – Bottom Brook 66 kV Loop operates normally open at the Bottom
Brook end such that all load in the Stephenville area is supplied via 230 kV transmission
line TL209 and the Stephenville Terminal Station. For the loss of the single 230/66 kV
transformer at Stephenville, the Stephenville gas turbine is operated for 50 MW.
Under light load conditions the 66 kV loop can be closed such that the Stephenville is
supplied via a 138/66 kV, 15/20/25 MVA transformer, T2, at Bottom Brook and
Newfoundland Power 66 kV line 400 L. If Hydro were to retire the Stephenville gas
turbine in the 2022 time frame, it would not be able to supply all load in the
Stephenville area for loss of the 230/66 kV transformer at Stephenville Terminal
Station.
� Assuming retirement of the Stephenville gas turbine, the long-term mitigation
strategy to maintain full back up supply to the Stephenville area for loss of the
230/66 kV transformer at Stephenville or the loss of TL209, is to add a 230/66
kV, 40/53/3/66.6 MVA transformer at Bottom Brook to replace the 138/66 kV,
15/20/25 MVA unit.
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• Steady state generator contingency analysis indicates:
o The loss of a synchronous condenser at Wabush Terminal Station in western Labrador
will result in low voltages and tripping of loads. Permanent loss of a synchronous
condenser requires a reduction in the transfer capacity of the system in western
Labrador.
� A comprehensive review of the transmission system in western Labrador is
underway and will be covered under a separate report.
o The loss of the Happy Valley gas turbine in synchronous condenser mode in eastern
Labrador will result in low voltages and tripping of loads. Permanent loss of the
synchronous condenser requires a reduction in the transfer capacity of the system in
eastern Labrador.
� Hydro will be addressing the issue in accordance with PUB Order No. P.U.
9(2018).
o Hydro is completing a long term resource adequacy analysis to assess the future
generator capacity requirements. The report will be completed in 2018.
• Steady State shunt contingency analysis indicates:
o Loss of the Granite Canal Tap shunt reactor results in a potential for self-excitation of
the Granite Canal generator.
� To avoid potential for self-excitation of Granite Canal generator an operating
instruction has been prepared to remove TL269 from service when the Granite
Canal Tap shunt reactor is out of service.
o The loss of a 46 kV, 25.2 MVAR shunt capacitor at Wabush Terminal Station in western
Labrador will result in low voltages and tripping of loads. Permanent loss of a shunt
capacitor requires a reduction in the transfer capacity of the system in western
Labrador.
� A comprehensive review of the transmission system in western Labrador is
underway and will be covered under a separate report.
o The Happy Valley Terminal Station includes four switched shunt capacitor banks for a
total of 11.4 MVAR. In addition, the Muskrat Falls construction power station
(MFATS3) includes six 3.6 MVAR switched shunt capacitor banks. Combined these
switched shunts provide the necessary voltage support to transfer power from
Churchill Falls to Happy Valley. Loss of a shunt capacitor bank will result in low
voltages and a requirement to reduce transfer capacity on the 138 kV system in
eastern Labrador.
� Hydro will be addressing the issue in accordance with PUB Order No. P.U.
9(2018).
o In Year Two the Muskrat Falls generators are not yet in service. The loss of the 315 kV,
150 MVAR shunt reactor at Muskrat Falls will result in overvoltages due to the charging
associated with 315 kV transmission lines L3101 and L3102.
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43
� The extent of overvoltages at Muskrat Falls Terminal Station 2 is impacted by
PUB Order No. P.U. 9(2018) and the fact that the Muskrat Falls-Happy Valley
Interconnection project has not been approved. Hydro will address these
overvoltages in further operational studies and discussion will be included in
the 2019 Annual Planning Assessment.
• The short circuit analysis reveals not issues with circuit breaker ratings in the near-term or
long-term planning horizons.
• The stability analysis of the near term planning horizon indicates:
o For the addition of the Maritime Link ONLY:
� a firm import of 108 MW is available at Bottom Brook based upon the Island
Interconnected System ability to accept 108 MW of import capacity
independent of system load and generation dispatch.
� Up to an additional 192 MW of non-firm import capacity is available at Bottom
Brook depending upon the Island Interconnected System load.
� The export limit at Bottom Brook is a function of not only the Island load but
also the generation dispatch and particularly, the number of thermal units on
line at Holyrood.
• The firm export limit is set at 55 MW at Bottom Brook.
• Up to an additional 70 MW of non-firm of non-firm export is available
at Bottom Brook depending upon the Island Interconnected System
load and status of generation at Holyrood.
o For the addition of the Maritime Link and Soldiers Pond Synchronous Condensers:
� a firm import of 108 MW is available at Bottom Brook based upon the Island
Interconnected System ability to accept 108 MW of import capacity
independent of system load and generation dispatch.
� Up to an additional 242 MW of non-firm import capacity is available at Bottom
Brook depending upon the Island Interconnected System load.
� The export limit at Bottom Brook is a function of not only the Island load but
also the generation dispatch and particularly, the number of thermal units on
line at Holyrood.
• The firm export limit is set at 55 MW at Bottom Brook.
• Up to an additional 70 MW of non-firm of non-firm export is available
at Bottom Brook depending upon the Island Interconnected System
load and status of generation at Holyrood.
o For the addition of the Maritime Link and Soldiers Pond Synchronous Condensers with
the Labrador – Island HVdc Link in monopolar mode, metallic return:
� LIL transfers are limited as a function of the following parameters:
• The status of the ML frequency controller
• The number of SOP synchronous condensers that are in service
• The Churchill Falls bus voltage
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 CONCLUSIONS
44
� There will be no frequency controller on the LIL in the initial monopolar mode
of operation. Therefore, the import and export limits on the Maritime Link will
be dependent upon the number of high inertia synchronous condensers in
service and the thermal units on-line at Holyrood.
• A firm import of 108 MW is available at Bottom Brook based upon the
Island Interconnected System ability to accept 108 MW of import
capacity independent of system load and generation dispatch.
• Up to an additional 242 MW of non-firm import capacity is available at
Bottom Brook depending upon the Island Interconnected System load.
• The export limit at Bottom Brook is a function of not only the Island
load but also the generation dispatch and particularly, the number of
thermal units on line at Holyrood.
o The firm export limit is set at 55 MW at Bottom Brook.
o Up to an additional 70 MW of non-firm of non-firm export is
available at Bottom Brook depending upon the Island
Interconnected System load and status of generation at
Holyrood and number of high inertia synchronous condensers
on-line at Soldiers Pond.
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 REFERENCE DOCUMENTS
45
12 REFERENCE DOCUMENTS
TP-S-003 NLSO Standard – Annual Planning Assessment
TP-S-007 NLSO Standard – Transmission Planning Criteria
TGS Report “Operational Studies: Maritime Link ONLY”, dated November 10, 2017
TGS Report “Operational Studies: Maritime Link and Soldiers Pond Synchronous Condensers”, dated
November 10, 2017
TGS Report “Operational Studies: Maritime Link, SOP Syncs and LIL Monopole”, dated February 27, 2018
TGS Report “Maximization of LIL Power Transfer using SPS (phased monopolar approach)”, dated March
5, 2018
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 Document Summary
46
Document Summary
Document Owner: Transmission Planning
Document Distribution: Publically available on NLSO OASIS site
Revision History
Revision Prepared by Reason for change Effective Date
1 P. Thomas Approved for release 2018/03/29
.
Document Approvers
Position Signature Approval Date
Manager, Transmission Planning
2018/03/29
Document Control
Regarding NLSO documents: The electronic version of this document is the CONTROLLED version. Please check the
NLSO Document Management System SharePoint site for the official copy of this document. This document, when
downloaded or printed, becomes UNCONTROLLED.
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 Appendix A
47
APPENDIX A
Load Flow Plots Primary Transmission System Year Two (2019)
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 Appendix A
48
2019 Island Peak Load Case
103.2
22.8
TL2
03
38
.8SW
10
.7
85
.6
19
.6
10
2.2
VA
LE
13
0.1
29
.6
46
.7
1.0
46
.7
2.3
0.8
5.7
6.2
13
1.6
13
3.6
0.7
G1
G2
0.8
29.7
89.4 89.2
88.4
49.1
88.2
50.1
85
.5
83
.6
31
.3
24.4
15.5
0.8
70
.9 0.0
0.0
57
.2
10
.2
4.3
13
1.0
29
.5
50.7
75
.0
71
.0
1.0
50
14
.5
26
.32
.0
8.6
TL2
33
0.9
1.0
25
23
5.7
1.0
35
14
.3
0.8
1.0
04
23
0.8
16
.3
26
.0
3.9
0.8
TL208
40.0
24.0
1.0
00
23
0.0
1.0
00
34
5.0
95.1
24.2
1.0
30
32
4.5
GT
G3
82.8
ST
ON
Y B
RO
OK
1.0
25
14
.1
218.7
55
.1
1.0
03
23
0.8
0.9
75
13
.5
0.9
75
13
.5
1.0
13
14
.0
22.8
11.6
SW
0.9
99
22
9.7
0.0
218.0
HA
RD
WO
OD
S
SC
1
SC
2
1.0
42
23
9.7
188.2
210.5
21.4
187.7
HO
LYR
OO
D
TL2
01
211.5
1.75.4TL242
TL265
115.6
34.7
1.0
13
23
3.1
92.1
37.3
0.0
0.0000
0.00 0.00
0.0000
20.50
0.9600
11.80
1.1200
0.0
0.0
LO
AD
S:
GE
NE
RA
TIO
N:
SW
SO
LDIE
RS
PO
ND
1.0
20
23
4.6
WE
ST
ER
N A
VA
LON
2.9
71.6
84.8
1.0
28
23
6.5
16
.2
8.4
TL2
32
9.9
0.9
BU
CH
AN
S
3.9
TL2
63
TL2
17
1.0
06
23
1.4
1.0
05
23
1.2
1.0
00
13
.81
.02
01
6.3
1.0
08
23
1.9
SC
3
0.0
TL2
69
8.6
57.1
6.757.2
6.6
TL204
177.5
29.2
19.8
178.6
32.8TL218
TL2
36
TL268
TL266
274.3
6.5R
6.5R
154.4
73.7
15.7
6.5
1.0
35
14
.31
.03
51
4.3
1.0
35
14
.3
1.0
25
14
.1
1.0
30
14
.2
71.3
4.8
12
.6
74.3
74.3
6.5R
1.0
05
23
1.2
40
.01
.00
01
3.8
1.0
49
4.4
74.3
6.5R
74.3
6.5R
1.0
20
23
4.5
OX
EN
PO
ND
1.0
32
23
7.3
1.0
30
23
6.8
TL207
TL2
37
TL2
05
55
.5
TL231
TL234
49.7
TL202
TL206
178.0
17.8
184.3
0.1
177.8
17.7
184.1
0.2
NO
RT
H A
TLA
NT
IC =
29
.2 M
W
KR
UG
ER
60
Hz
TO
TA
L =
9
5.8
MW
VA
LE +
PR
AX
AIR
=
5
7.1
MW
HV
DC
:
R
AT
TLE
BR
OO
K =
0
.0 M
W
FE
RM
EU
SE
=
-0
.0 M
W
TO
TA
L IN
DU
ST
RIA
L =
18
2.6
MW
CO
RN
ER
BR
OO
K C
OG
EN
=
8.0
MW
ST
AR
LA
KE
- E
XP
LOIT
S =
81
.0 M
W
ISL
AN
D S
YS
TE
M O
VE
RV
IEW
ST
LA
WR
EN
CE
=
-0.0
MW
LIL
IMP
OR
T A
T S
OP
23
0 k
V =
92
.1 M
W
NLH
GE
NE
RA
TIO
N =
14
53
.5 M
W
H
YD
RO
RU
RA
L =
9
6.7
MW
GR
OS
S A
VA
LON
LO
AD
= 9
85
.4 M
W
10.0
30.0
1.0
00
12
0.0
1 0.0
0.0R
1 0.0
0.0R
1.0
00
12
0.0
1.0
9.3
10
.0
60
.0
0.9
63
11
5.6
10
.0
59
.4R
0.9
63
11
5.6
10
.0
59
.4R
1.0
30
23
6.8
12.2
5.2
12
.2
8.7
39.9
3.0
39
.9
3.0
TL270
51
.4
23
.5
52
.1
4.3
SW
15
.9
TL267 166.2
4.6
ST
AT
ION
SE
RV
ICE
+ L
OS
SE
S:
HR
D S
TA
TIO
N S
ER
VIC
E =
23
.9 M
W
BB
K C
ON
VE
RT
ER
LO
SS
ES
= 0
.8 M
W
TR
AN
SM
ISS
ION
LO
SS
ES
= 4
6.5
MW
G2
G3
G4
G5
G6
G1
G7
1.0
20
16
.3
1 145.0
66.6R 1.0
20
16
.3
1 140.0
56.4R
G1
G2
0.9
83
13
.6
1
1.0
25
14
.1
0.9
67
12
.8
1
1.0
31
4.3
0.9
90
13
.71
18
.0
3.6
RS
TA
R L
AK
E
GR
AN
ITE
CA
NA
L
1.0
25
7.1
15
.0
2.0
R
0.9
70
4.1
1
PA
RA
DIS
E
RIV
ER
SW
152.8
SW
154.1
TE
CK
=
0
.5 M
W
MA
SS
EY
DR
IVE
CA
T A
RM
DE
ER
LA
KE
TL2
48
TL2
47
WO
OD
BIN
E,
NS
ML
PO
LE 2
ML
PO
LE 1
RO
SE
BLA
NC
HE
ST
EP
HE
NV
ILLE
TL2
09
FIL
TE
RS
BO
TT
OM
BR
OO
K
CB
P&
P G
2
CB
F F
RC
TL2
11
28
.3
RA
TT
LE B
RO
OK
HIN
DS
LA
KE
1.0
08
13
.9
1.0
00
6.6
TL2
28
DE
ER
LA
KE
PO
WE
R 1.0
20
6.1
HA
WK
E'S
BA
Y =
0.0
MW
0.0
Mv
ar
ST
. A
NT
HO
NY
= 0
.0 M
W0
.0 M
va
r
NP
ST
AN
DB
Y T
HE
RM
AL
GR
EE
NH
ILL
GT
WE
SLE
YV
ILLE
GT
MO
BIL
E G
T
BA
Y d
'ES
PO
IR
40.0
8.1
GR
AN
ITE
TA
P
UP
PE
R
SA
LMO
N
11
.33.9
1.0
21
23
4.8
140.0
60.5
10
.9
MU
SK
RA
T F
ALL
S
17.2
SU
NN
YS
IDE
1.0
05
23
1.1
8.0
3.3
CO
ME
BY
CH
AN
CE
159.4
84.0
2.0
56.9
10.3
56.8
10.3
GR
AN
D F
ALL
S1
.02
12
34
.8
TL235
6.5
67
.0
HY
DR
O P
UR
CH
AS
ES
:
CB
P&
P N
LH S
UP
PLI
ED
= -
3.2
MW
CU
ST
OM
ER
GE
NE
RA
TIO
N:
NL
PO
WE
R G
EN
ER
AT
ION
=
76
.4 M
W
VA
LE D
IES
ELS
=
0.0
MW
DLP
60
Hz
GE
NE
RA
TIO
N =
8
1.1
MW
DLP
FR
C 6
0 H
z =
1
8.0
MW
NL
PO
WE
R I
NC
GE
NE
RA
TIO
N =
14
53
.5 M
W
TO
TA
L U
TIL
ITY
= 1
55
0.2
MW
SO
P S
TA
TIO
N S
ER
VIC
E =
6.9
MW
TO
TA
L IS
LAN
D 6
0 H
z G
EN
ER
AT
ION
= 1
71
8.0
MW
ISLA
ND
60
Hz
GE
NE
RA
TIO
N +
LIL
= 1
81
0.1
MW
ML
EX
PO
RT
AT
BB
K =
-0
.0 M
W
ML
IMP
OR
T A
T B
BK
= 0
.0 M
W
20
19
CA
SE
, P
EA
K L
OA
DS
WE
D,
MA
R 0
7 2
01
8 1
4:1
3
18
.0
1.8
R
16
7.0
6.8
R
18
1.1
8.0
R
11
8.0
2.2
R
62
.4
11
.0
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 Appendix A
49
2019 Labrador Peak Load Case
4
1
1
95.1
24.1
1.0
13
23
3.1
92.2
37.3
0.00.0
0.0
1.0
00
15
.0
0.0
1
1.0
00
15
.01
.00
01
5.0
3
MO
NT
AG
NA
IS S
UB
ST
AT
ION
GE
NE
RA
TIO
N:
LOA
DS
:
SY
ST
EM
OV
ER
VIE
W
HA
PP
Y V
ALL
EY
0.9
73
13
4.2
1.0
00
15
.0
1.0
23
14
.1
0.0
22
.5R
2
157.5
SW
1.0
46
32
9.4
MU
SK
RA
T F
ALL
S
154.1
SW
SO
LDIE
RS
PO
ND
0.00
0.0000
0.9450
20.5011.86
1.1200
0.00
0.0000
1.0
33
14
.31
.01
71
4.0
1
WA
BU
SH
SW
11
.4
1.1
34.6R
1.1
45.2R0
.97
01
4.6
0.9
90
14
.90
.99
01
4.9 1.0
43
23
9.9
23
1
0.9
90
14
.90
.99
01
4.9 1.0
43
23
9.9
54
0.9
80
14
.70
.98
01
4.7
11
1.0
43
23
9.9
0.9
90
14
.90
.99
01
4.8
98
0.9
90
14
.90
.99
01
4.8 1.0
43
23
9.9
76
XL1
XL2
XL3
LAB
HQ
T
L2303
L2304
SC
1S
C2
SW
SW
1.0
13
46
.6
1.0
13
46
.6
C1
C2
MU
SK
RA
T F
ALL
S =
0.0
MW
HA
PP
Y V
ALL
EY
GT
=
0.0
MW
LAB
RA
OR
IS
LAN
D L
INK
= 9
5.1
MW
1.0
40
23
9.2
GU
LL
MF
AT
S1
L13
01
L1302
MF
AT
S3
L31
01
L31
02
MF
AT
S2
CH
UR
CH
ILL
FA
LLS
L7051
L7052
L7053
25.9
25.9
510.0
21.0R
48.1R
510.0
48.1R
510.0
47.6R
510.0
47.6R
510.0
48.3R
510.0
48.1R
510.0
47.3R
510.0
47.1R
510.0
36.6R
510.0
36.6R
510.0
0.9
96
73
2.0
CH
UR
CH
ILL
FA
LLS
= 5
61
0.0
MW
1.0
35
23
8.0
LAB
RA
DO
R I
SLA
ND
LIN
K =
95
.1 M
W
MF
CO
NS
TR
UC
TIO
N =
3.8
MW
HA
PP
Y V
ALL
EY
= 7
6.1
MW
EX
PO
RT
S
HY
DR
O Q
UE
BE
C @
BO
RD
ER
= 4
96
5.6
MW
LAB
RA
DO
R S
UM
MA
RY
LAB
RA
DO
R E
AS
T T
OT
AL
= 7
9.8
MW
EX
PO
RT
S T
OT
AL
= 5
06
0.7
MW
TO
TA
L E
XP
OR
TS
= 5
06
0.7
MW
TO
TA
L IN
TE
RN
AL
LOA
D =
40
4.7
MW
TO
TA
L LO
AD
= 5
46
5.4
MW
TO
TA
L LA
BR
AD
OR
= 5
61
0.0
MW
TO
TA
L LO
SS
ES
= 1
44
.6 M
W
IND
US
TR
IAL
LAB
RA
DO
R W
ES
T
LAB
RA
DO
R E
AS
T
UT
ILIT
Y
UT
ILIT
Y
LAB
-HQ
T I
NT
ER
FA
CE
LIM
ITS
EX
PO
RT
= 5
20
0.0
MW
IMP
OR
T =
0.0
MW
LAB
RA
DO
R I
SLA
ND
LIN
K L
IMIT
S
BIP
OLE
EX
PO
RT
= 9
00
.0 M
W
MO
NO
PO
LE C
ON
T E
XP
OR
T =
67
5.0
MW
WA
BU
SH
= 2
2.0
MW
HQ
FE
RM
ON
T =
0.0
MW
LAB
RA
DO
R C
ITY
= 5
8.2
MW
TO
TA
L U
TIL
ITY
= 8
0.2
MW
LAB
RA
DO
R W
ES
T T
OT
AL
=
32
4.9
MW
TO
TA
L IN
DU
ST
RIA
L =
2
44
.7 M
W
IOC
C =
2
44
.7 M
W
WA
BU
SH
MIN
ES
=
0.0
MW
20
19
CA
SE
, P
EA
K L
OA
DS
MO
N,
MA
R 2
6 2
01
8 1
4:4
2
19
53
20
CH
F 3
15
1.0
15
31
9.6
51.7
16.6
52
.0
91
.1
51.7
16.6
SW
164.0
52.7
88.9
1
52.6
88.6
1
91
.1
52
.0
1.0
19
14
0.6
2.4
0.7
1.0
25
2.4
0.7
1.0
25 0
.97
71
34
.8
74.4
13.9
0.9
77
13
4.8
75
.5
11
.6
75.5
11.6
0.9
77
13
4.8
75
.5
31
.6
88.3
1.4
1.0
5
0.9
90
13
6.6
86.9
3.6
75.4
31.7
0.9
27
21
3.1
176.3
34.4
164.8
4.8
176.3
34.4
164.8
4.8
SW
21
.4
1666.5
375.5
1655.2
210.2
1666.5
375.5
1655.2
210.2
1666.5
375.5
1655.2
210.2
SW
163.6
SW
163.6
SW
163.6
1652.6
182.9
1.0
18
74
8.2
1 4957.7
659.8R
SW
513.0
1652.6
182.9
1652.6
182.9
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 Appendix A
50
2019 Island Light Load Case
71.7
16.1
TL2
03
0.0SW
8.3
58
.3
10
.3
71
.3
VA
LE
33
.0
39
.0
12
.5
29
.5
12
.5
25
.9
0.6
4.9
5.3
34
.73
4.9
15
.8
G1
G2
0.8
29.7
33.9 33.9
33.5
17.2
33.5
19.0
56
.8
55
.7
12
.4
2.6
1.6
0.8
69
.8 0.0
0.0
57
.2
9.9
6.1
33
.2
11
.0
19.2
0.0
70
.0
0.9
66
13
.3
29
.14
.8
4.2
TL2
33
0.4
1.0
25
23
5.7
1.0
18
14
.0
0.6
1.0
06
23
1.3
7.2
24
.8
12
.6
0.8
TL208
0.0
0.0
1.0
00
23
0.0
1.0
00
34
5.0
120.1
33.2
1.0
38
32
6.8
GT
G3
55.4
ST
ON
Y B
RO
OK
1.0
25
14
.1
78.0
26
.8
1.0
10
23
2.3
0.9
75
13
.5
0.9
75
13
.5
1.0
12
14
.0
1.3
0.5
SW
0.9
94
22
8.7
0.0
77.9
HA
RD
WO
OD
S
SC
1
SC
2
1.0
23
23
5.4
72.2
75.0
5.5
72.1
HO
LYR
OO
D
TL2
01
75.2
2.9 4.9TL242
TL265
87.9
4.1
1.0
13
23
3.0
115.6
47.6
0.0
0.0000
0.00 0.00
0.0000
20.50
0.9450
12.69
1.1000
0.0
0.0
LO
AD
S:
GE
NE
RA
TIO
N:
SW
SO
LDIE
RS
PO
ND
1.0
14
23
3.3
WE
ST
ER
N A
VA
LON
28.4
72.7
56.5
1.0
06
23
1.3
7.2
16
.7
TL2
32
10
.9
0.4
BU
CH
AN
S
0.0
TL2
63
TL2
17
1.0
14
23
3.1
1.0
14
23
3.3
1.0
00
13
.81
.00
01
6.0
1.0
12
23
2.7
SC
3
0.0
TL2
69
4.3
1.1
29.31.1
29.3
TL204
44.2
10.9
6.9
44.3
4.5TL218
TL2
36
TL268
TL266
2
110.0
51.3
57.2
17.0
0.9
75
13
.50
.95
01
3.1
0.9
75
13
.5
0.9
50
13
.1
0.9
50
13
.1
72.4
21.7
21
.0
1.0
14
23
3.3
0.0
1.0
00
13
.8
1.0
49
4.4
52.1
17.4R
1.0
22
23
5.1
OX
EN
PO
ND
0.9
97
22
9.4
0.9
99
22
9.7
TL207
TL2
37
TL2
05
27
.8
TL231
TL234
17.4
TL202
TL206
92.0
13.5
93.8
26.8
91.9
13.4
93.7
26.8
NO
RT
H A
TLA
NT
IC =
29
.2 M
W
KR
UG
ER
60
Hz
TO
TA
L =
9
5.9
MW
VA
LE +
PR
AX
AIR
=
5
7.1
MW
HV
DC
:
R
AT
TLE
BR
OO
K =
0
.0 M
W
FE
RM
EU
SE
=
0
.0 M
W
TO
TA
L IN
DU
ST
RIA
L =
18
2.7
MW
CO
RN
ER
BR
OO
K C
OG
EN
=
8.0
MW
ST
AR
LA
KE
- E
XP
LOIT
S =
81
.0 M
W
ISL
AN
D S
YS
TE
M O
VE
RV
IEW
ST
LA
WR
EN
CE
=
-0.0
MW
LIL
IMP
OR
T A
T S
OP
23
0 k
V =
11
5.5
MW
NLH
GE
NE
RA
TIO
N =
35
2.4
MW
H
YD
RO
RU
RA
L =
3
2.7
MW
GR
OS
S A
VA
LON
LO
AD
= 3
72
.9 M
W
10.0
30.0
1.0
00
12
0.0
1 0.0
0.0R
1 0.0
0.0R
1.0
00
12
0.0
7.1
10
.1
10
.0
60
.0
0.9
69
11
6.2
10
.0
48
.6R
0.9
69
11
6.2
10
.0
48
.6R
0.9
99
22
9.7
0.1
8.5
0.1
4.6
23.0
8.9
23
.0
8.9
TL270
22
.9
11
.2
23
.1
19
.2
SW
15
.0
TL267 88.9
27.2
ST
AT
ION
SE
RV
ICE
+ L
OS
SE
S:
HR
D S
TA
TIO
N S
ER
VIC
E =
7.4
MW
BB
K C
ON
VE
RT
ER
LO
SS
ES
= 0
.8 M
W
TR
AN
SM
ISS
ION
LO
SS
ES
= 1
4.0
MW
G2
G3
G4
G5
G6
G1
G7
1.0
00
16
.0
1
1.0
00
16
.0
1
G1
G2
1.0
15
14
.0
1
0.9
50
13
.1
1.0
15
13
.4
1
1.0
38
4.3
0.9
90
13
.71
18
.0
3.9
RS
TA
R L
AK
E
GR
AN
ITE
CA
NA
L
1.0
00
6.9
15
.0
3.7
R
1.0
15
4.3
1
PA
RA
DIS
E
RIV
ER
SW
155.0
SW
153.9
TE
CK
=
0
.5 M
W
MA
SS
EY
DR
IVE
CA
T A
RM
DE
ER
LA
KE
TL2
48
TL2
47
WO
OD
BIN
E,
NS
ML
PO
LE 2
ML
PO
LE 1
RO
SE
BLA
NC
HE
ST
EP
HE
NV
ILLE
TL2
09
FIL
TE
RS
BO
TT
OM
BR
OO
K
CB
P&
P G
2
CB
F F
RC
TL2
11
29
.9
RA
TT
LE B
RO
OK
HIN
DS
LA
KE
1.0
08
13
.9
1.0
00
6.6
TL2
28
DE
ER
LA
KE
PO
WE
R 1.0
20
6.1
HA
WK
E'S
BA
Y =
0.0
MW
0.0
Mv
ar
ST
. A
NT
HO
NY
= 0
.0 M
W0
.0 M
va
r
NP
ST
AN
DB
Y T
HE
RM
AL
GR
EE
NH
ILL
GT
WE
SLE
YV
ILLE
GT
MO
BIL
E G
T
BA
Y d
'ES
PO
IR
23.0
6.8
GR
AN
ITE
TA
P
UP
PE
R
SA
LMO
N
10
.212
.7
1.0
25
23
5.6
0.0
38.5
9.9
MU
SK
RA
T F
ALL
S
8.0
SU
NN
YS
IDE
1.0
15
23
3.4
8.0
2.6
CO
ME
BY
CH
AN
CE
86.8
73.0
26.7
1.0
10.2
1.0
10.1
GR
AN
D F
ALL
S1
.02
52
35
.7
TL235
16
.7
0.0
HY
DR
O P
UR
CH
AS
ES
:
CB
P&
P N
LH S
UP
PLI
ED
= -
3.1
MW
CU
ST
OM
ER
GE
NE
RA
TIO
N:
NL
PO
WE
R G
EN
ER
AT
ION
=
76
.4 M
W
VA
LE D
IES
ELS
=
0.0
MW
DLP
60
Hz
GE
NE
RA
TIO
N =
8
1.1
MW
DLP
FR
C 6
0 H
z =
1
8.0
MW
NL
PO
WE
R I
NC
GE
NE
RA
TIO
N =
48
8.7
MW
TO
TA
L U
TIL
ITY
= 5
21
.4 M
W
SO
P S
TA
TIO
N S
ER
VIC
E =
6.9
MW
TO
TA
L IS
LAN
D 6
0 H
z G
EN
ER
AT
ION
= 6
16
.9 M
W
ISLA
ND
60
Hz
GE
NE
RA
TIO
N +
LIL
= 7
32
.4 M
W
ML
EX
PO
RT
AT
BB
K =
0.0
MW
ML
IMP
OR
T A
T B
BK
= -
0.0
MW
20
19
CA
SE
, LI
GH
T L
OA
DS
WE
D,
MA
R 0
7 2
01
8 1
4:1
6
18
.0
2.7
R
13
5.0
28
.4R
18
1.1
3.0
R
11
8.0
1.3
R
62
.4
8.3
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 Appendix A
51
2019 Labrador Light Load Case
41
120.1
34.7
1.0
13
23
3.0
115.6
47.6
0.00.0
0.0
1.0
00
15
.0
0.0
1
1.0
00
15
.01
.00
01
5.0
3
MO
NTA
GN
AIS
SU
BST
ATI
ON
GE
NE
RA
TIO
N:
LO
AD
S:
SYST
EM
OV
ERV
IEW
HA
PP
Y V
ALL
EY
1.0
12
13
9.7
1.0
00
15
.0
0.9
78
13
.5
2
156.0
SW
1.0
41
32
7.9
MU
SK
RA
T F
AL
LS
153.9
SW
SO
LD
IER
S P
ON
D
0.00
0.0000
0.9450
20.5013.48
1.1000
0.00
0.0000
0.9
60
13
.20
.98
71
3.6
1
WA
BU
SH
SW
2.5
1.1
15.7R
1.1
0.7R
1.0
15
15
.20
.99
01
4.9
0.9
90
14
.9
1.0
45
24
0.4
23
1
0.9
90
14
.90
.99
01
4.9
1.0
45
24
0.4
54
0.9
90
14
.90
.99
01
4.9
11
1.0
45
24
0.4
0.9
90
14
.90
.99
01
4.9
98
0.9
90
14
.90
.99
01
4.9 1.0
45
24
0.3
76
XL1
XL
2X
L3
LA
B
HQ
T
L2303
L2304
SC
1SC
2
SW
SW
1.0
13
46
.6
1.0
13
46
.6
C1
C2
MU
SK
RA
T F
ALL
S =
0
.0 M
W
HA
PP
Y V
ALL
EY
GT
=
0.0
MW
LAB
RA
OR
IS
LAN
D L
INK
= 1
20
.1 M
W
1.0
60
24
3.8
GU
LL
MF
AT
S1
L13
01
L1302
MF
AT
S3
L3
10
1
L3
10
2
MFA
TS2
CH
UR
CH
ILL
FA
LLS
L7051
L7052
L7053
25.9
25.9
500.0
91.8R
34.8R
475.0
36.6R
500.0
37.8R
499.7
37.8R
500.0
39.1R
503.5
38.3R
500.0
37.6R
499.7
37.1R
500.0
42.8R
475.0
42.9R
475.0
0.9
99
73
4.5
CH
UR
CH
ILL
FA
LLS
= 5
42
7.9
MW
1.0
44
24
0.0
ASSUMED ADDITION
LAB
RA
DO
R I
SLA
ND
LIN
K =
12
0.1
MW
MF
CO
NS
TR
UC
TIO
N =
3.8
MW
HA
PP
Y V
ALL
EY
= 2
5.7
MW
EX
PO
RT
S
HY
DR
O Q
UE
BE
C @
BO
RD
ER
= 4
88
2.9
MW
LAB
RA
DO
R S
UM
MA
RY
LAB
RA
DO
R E
AS
T T
OT
AL
= 2
9.4
MW
EX
PO
RT
S T
OT
AL
= 5
00
2.9
MW
TO
TA
L E
XP
OR
TS
= 5
00
2.9
MW
TO
TA
L LA
BR
AD
OR
= 5
42
7.9
MW
IND
US
TR
IAL
LAB
RA
DO
R W
ES
T
LAB
RA
DO
R E
AS
T
UT
ILIT
Y
UT
ILIT
Y
LAB
-HQ
T IN
TER
FA
CE
LIM
ITS
EX
PO
RT
= 5
20
0.0
MW
IMP
OR
T =
0.0
MW
LA
BR
AD
OR
ISL
AN
D L
INK
LIM
ITS
BIP
OL
E E
XP
OR
T =
90
0.0
MW
MO
NO
PO
LE
CO
NT
EX
PO
RT
= 6
75
.0 M
W
IOC
C =
24
4.7
MW
WA
BU
SH
MIN
ES
=
0
.0 M
W
TO
TA
L IN
DU
ST
RIA
L =
24
4.7
MW
LAB
RA
DO
R C
ITY
= 1
9.4
MW
WA
BU
SH
= 7
.4 M
W
HQ
FER
MO
NT
= 0
.0 M
W
TOTA
L U
TIL
ITY
= 2
6.8
MW
LAB
RA
DO
R W
ES
T T
OT
AL
=
2
71
.6 M
W
TO
TA
L IN
TE
RN
AL
LOA
D =
30
1.0
MW
TO
TA
L LO
AD
= 5
30
3.9
MW
TO
TA
L LO
SS
ES
= 1
24
.0 M
W
20
19
CA
SE
, LIG
HT
LO
AD
S
MO
N,
MA
R 2
6 2
01
8
14
:32
19
53
20
CH
F 3
15
1.0
17
32
0.2
64.8
21.8
65
.2
84
.6
64.8
21.8
SW
162.5
65.9
82.3
1
65.7
82.1
1
84
.6
65
.2
1.0
15
14
0.0
2.4
0.3
1.0
25
2.4
0.3
1.0
25 1
.01
71
40
.3
25.7
1.5
1.0
17
14
0.3
25
.8
0.0
25.8
0.0
1.0
17
14
0.3
25
.8
0.0
27.0
12.1
1.0
5
1.0
19
14
0.6
27.0
12.8
25.9
0.0
0.9
35
21
5.1
145.8
29.3
137.9
21.0
145.8
29.3
137.9
21.0
1638.4
336.0
1627.6
156.3
1638.4
336.0
1627.6
156.3
1638.4
336.0
1627.6
156.3
SW
164.7SW
164.7SW
164.7
1625.1
128.0
1.0
18
74
8.2
1 4875.2
508.5R
SW
513.0
1625.1
128.0
1625.1
128.0
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 Appendix B
52
APPENDIX B
Load Flow Plots Primary Transmission System Year Five (2022)
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 Appendix C
53
2022 Island Peak Load Case
51.7
2.2
TL2
03
38
.4SW
8.7
41
.0
4.4
51
.5
VA
LE
14
2.4
11
.6
46
.9
1.1
47
.0
2.2
44
.9
11
.1
8.4
13
1.5
13
3.5
19
.5
G1
G2
153.0
26.9
94.2 94.4
93.2
41.9
93.3
42.7
20
.8
20
.6
2.0
12.9
24.5
0.8
24
.5 0.0
0.0
56
.3
10
.5
16
.9
14
3.5
2.7
43.2
75
.0
24
.5
1.0
50
14
.5
14
.8 5
.1
60
.7T
L23
34
7.9
1.0
11
23
2.5
1.0
35
14
.3
44
.6
0.9
97
22
9.4
73
.6
20
.7
44
.8
0.8
TL208
60.0
47.5
1.0
00
23
0.0
1.0
00
34
5.0
350.7
125.7
1.0
27
32
3.5
GT
G3
20.6
ST
ON
Y B
RO
OK
0.9
75
13
.5
257.6
54
.9
0.9
76
22
4.4
0.9
75
13
.5
0.9
75
13
.5
0.9
88
13
.6
13.6
17.3
SW
0.9
99
22
9.7
0.0
256.5
HA
RD
WO
OD
S
SC
1
SC
2
1.0
06
23
1.4
229.9
247.9
25.3
229.1
HO
LYR
OO
D
TL2
01
249.3
5.512.5TL242
TL265
70.4
17.8
0.9
89
22
7.4
330.1
158.4
330.1
1.0750
12.94 20.50
0.9300
20.50
0.9300
12.94
1.0750
350.7
125.7
LO
AD
S:
GE
NE
RA
TIO
N:
SW
SO
LDIE
RS
PO
ND
0.9
92
22
8.1
WE
ST
ER
N A
VA
LON
0.9
20.7
20.7
1.0
29
23
6.6
73
.1
14
.5
TL2
32
6.0
47
.7
BU
CH
AN
S
5.3
TL2
63
TL2
17
1.0
01
23
0.2
0.9
96
22
9.0
1.0
00
13
.81
.02
01
6.3
0.9
81
22
5.7
SC
3
158.4
TL2
69
61
.4
99.4
6.899.7
6.8
TL204
149.1
30.0
21.6
149.9
31.4TL218
TL2
36
TL268
TL266
274.3
6.2R
6.2R
154.4
73.8
15.2
6.3
1.0
35
14
.31
.03
51
4.3
1.0
35
14
.3
1.0
25
14
.1
1.0
30
14
.2
20.7
8.9
12
.6
74.3
74.3
6.2R
0.9
96
22
9.0
0.0
1.0
00
13
.8
1.0
49
4.4
74.3
6.2R
74.3
6.2R
1.0
18
23
4.0
OX
EN
PO
ND
1.0
31
23
7.2
1.0
26
23
6.0
TL207
TL2
37
TL2
05
55
.2
TL231
TL234
42.4
TL202
TL206
137.0
0.9
140.7
0.7
136.8
1.0
140.5
0.7
NO
RT
H A
TLA
NT
IC =
29
.2 M
W
KR
UG
ER
60
Hz
TO
TA
L =
9
5.1
MW
VA
LE +
PR
AX
AIR
=
5
6.2
MW
HV
DC
:
R
AT
TLE
BR
OO
K =
0
.0 M
W
FE
RM
EU
SE
=
0
.0 M
W
TO
TA
L IN
DU
ST
RIA
L =
18
1.0
MW
CO
RN
ER
BR
OO
K C
OG
EN
=
8.0
MW
ST
AR
LA
KE
- E
XP
LOIT
S =
81
.0 M
W
ISL
AN
D S
YS
TE
M O
VE
RV
IEW
ST
LA
WR
EN
CE
=
-0.0
MW
LIL
IMP
OR
T A
T S
OP
23
0 k
V =
66
0.2
MW
NLH
GE
NE
RA
TIO
N =
10
13
.8 M
W
H
YD
RO
RU
RA
L =
8
9.7
MW
GR
OS
S A
VA
LON
LO
AD
= 9
69
.7 M
W
10.0
30.0
1.0
00
12
0.0
1 76.9
1.4R
1 76.9
1.4R
1.0
00
12
0.0
20
.9
2.3
10
.0
60
.0
0.9
76
11
7.1
1 7
9.0
32
.7R
0.9
76
11
7.1
1 7
9.0
32
.7R
1.0
26
23
6.0
63.1
6.8
62
.7
4.5
39.9
4.1
39
.9
4.1
TL270
10
0.1
7.8
10
2.6
7.3
SW
15
.8
TL267 119.5
3.4S
TA
TIO
N S
ER
VIC
E +
LO
SS
ES
:
HR
D S
TA
TIO
N S
ER
VIC
E =
7.4
MW
BB
K C
ON
VE
RT
ER
LO
SS
ES
= 0
.8 M
W
TR
AN
SM
ISS
ION
LO
SS
ES
= 4
0.2
MW
G2
G3
G4
G5
G6
G1
G7
1.0
00
16
.0
1
1.0
00
16
.0
1
G1
G2
1.0
09
13
.9
1
0.9
75
13
.5
0.9
74
12
.9
1
1.0
31
4.3
0.9
90
13
.71
18
.0
3.4
RS
TA
R L
AK
E
GR
AN
ITE
CA
NA
L
1.0
25
7.1
15
.0
2.0
R
0.9
72
4.1
1
PA
RA
DIS
E
RIV
ER
SW
303.7
SW
293.1
TE
CK
=
0
.5 M
W
MA
SS
EY
DR
IVE
CA
T A
RM
DE
ER
LA
KE
TL2
48
TL2
47
WO
OD
BIN
E,
NS
ML
PO
LE 2
ML
PO
LE 1
RO
SE
BLA
NC
HE
ST
EP
HE
NV
ILLE
TL2
09
FIL
TE
RS
BO
TT
OM
BR
OO
K
CB
P&
P G
2
CB
F F
RC
TL2
11
11
.9
RA
TT
LE B
RO
OK
HIN
DS
LA
KE
1.0
08
13
.9
1.0
00
6.6
TL2
28
DE
ER
LA
KE
PO
WE
R 1.0
20
6.1
HA
WK
E'S
BA
Y =
5.0
MW
2.6
Mv
ar
ST
. A
NT
HO
NY
= 0
.0 M
W0
.0 M
va
r
NP
ST
AN
DB
Y T
HE
RM
AL
GR
EE
NH
ILL
GT
WE
SLE
YV
ILLE
GT
MO
BIL
E G
T
BA
Y d
'ES
PO
IR
40.0
9.2
GR
AN
ITE
TA
P
UP
PE
R
SA
LMO
N
7.74
5.2
1.0
20
23
4.7
0.0
92.4
11
.8
MU
SK
RA
T F
ALL
S
5.9
SU
NN
YS
IDE
1.0
00
23
0.1
8.0
2.9
CO
ME
BY
CH
AN
CE
116.0
84.0
2.4
98.8
4.0
98.5
4.1
GR
AN
D F
ALL
S1
.02
02
34
.7
TL235
2.2
67
.0
HY
DR
O P
UR
CH
AS
ES
:
CB
P&
P N
LH S
UP
PLI
ED
= -
4.0
MW
CU
ST
OM
ER
GE
NE
RA
TIO
N:
NL
PO
WE
R G
EN
ER
AT
ION
=
76
.4 M
W
VA
LE D
IES
ELS
=
0.0
MW
DLP
60
Hz
GE
NE
RA
TIO
N =
8
1.1
MW
DLP
FR
C 6
0 H
z =
1
8.0
MW
NL
PO
WE
R I
NC
GE
NE
RA
TIO
N =
14
55
.4 M
W
TO
TA
L U
TIL
ITY
= 1
54
5.1
MW
SO
P S
TA
TIO
N S
ER
VIC
E =
6.8
MW
TO
TA
L IS
LAN
D 6
0 H
z G
EN
ER
AT
ION
= 1
27
8.3
MW
ISLA
ND
60
Hz
GE
NE
RA
TIO
N +
LIL
= 1
93
8.5
MW
ML
EX
PO
RT
AT
BB
K =
15
8.0
MW
ML
IMP
OR
T A
T B
BK
= -
15
8.0
MW
20
22
CA
SE
, P
EA
K L
OA
DS
WE
D,
MA
R 0
7 2
01
8 1
4:2
0
18
.0
1.3
R
16
7.0
2.0
R
18
1.1
9.0
R
11
8.0
2.6
R
62
.4
11
.5
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 Appendix C
54
2022 Labrador Peak Load Case
4
1
1
350.7
128.1
0.9
88
22
7.3
330.1
158.4
330.1350.7
128.1
1.0
20
15
.3
158.4
1
1.0
20
15
.31
.02
01
5.3
3
MO
NT
AG
NA
IS S
UB
ST
AT
ION
GE
NE
RA
TIO
N:
LOA
DS
:
SY
ST
EM
OV
ER
VIE
W
HA
PP
Y V
ALL
EY
0.8
77
12
1.0
1.0
20
15
.3
1.0
23
14
.1
15
.0
10
.8R
2
176.0
13.7R
304.9
SW
1.0
29
32
4.1
MU
SK
RA
T F
ALL
S
293.0
SW
SO
LDIE
RS
PO
ND
20.50
0.9300
0.9300
20.5013.45
1.0750
13.45
1.0750
0.9
75
13
.50
.95
81
3.2
1
WA
BU
SH
176.0
176.0
13.7R
13.7R
SW
12
.2
1.1
1.8R
1.1
8.7R
176.0
13.7R
0.9
77
14
.70
.99
01
4.9
0.9
90
14
.9 1.0
43
23
9.8
23
1
0.9
90
14
.90
.99
01
4.9 1.0
43
23
9.9
54
0.9
79
14
.70
.97
91
4.7
11
1.0
43
23
9.9
0.9
90
14
.90
.99
01
4.9
98
0.9
90
14
.90
.99
01
4.9 1.0
43
23
9.8
76
XL1
XL2
XL3
LAB
HQ
T
L2303
L2304
SC
1S
C2
SW
SW
1.0
13
46
.6
1.0
13
46
.6
C1
C2
MU
SK
RA
T F
ALL
S =
70
4.0
MW
HA
PP
Y V
ALL
EY
GT
=
15
.0 M
W
LAB
RA
OR
IS
LAN
D L
INK
= 7
01
.4 M
W
1.0
40
23
9.2
GU
LL
MF
AT
S1
L13
01
L1302
MF
AT
S3
L31
01
L31
02
MF
AT
S2
CH
UR
CH
ILL
FA
LLS
L7051
L7052
L7053
25.9
25.9
510.0
0.1R
49.4R
510.0
49.4R
510.0
48.9R
510.0
48.9R
510.0
49.5R
510.0
49.4R
510.0
48.6R
510.0
48.4R
510.0
32.1R
510.0
32.1R
510.0
0.9
95
73
1.6
CH
UR
CH
ILL
FA
LLS
= 5
61
0.0
MW
1.0
35
23
8.0
ASSUMED ADDITION
LAB
RA
DO
R I
SLA
ND
LIN
K =
70
1.4
MW
MF
CO
NS
TR
UC
TIO
N =
0.0
MW
HA
PP
Y V
ALL
EY
= 8
8.7
MW
EX
PO
RT
S
HY
DR
O Q
UE
BE
C @
BO
RD
ER
= 5
07
1.3
MW
LAB
RA
DO
R S
UM
MA
RY
LAB
RA
DO
R E
AS
T T
OT
AL
= 8
8.7
MW
EX
PO
RT
S T
OT
AL
= 5
77
2.7
MW
TO
TA
L E
XP
OR
TS
= 5
77
2.7
MW
TO
TA
L LA
BR
AD
OR
= 6
32
9.0
MW
IND
US
TR
IAL
LAB
RA
DO
R W
ES
T
LAB
RA
DO
R E
AS
T
UT
ILIT
Y
UT
ILIT
Y
LAB
-HQ
T I
NT
ER
FA
CE
LIM
ITS
EX
PO
RT
= 5
20
0.0
MW
IMP
OR
T =
0.0
MW
LAB
RA
DO
R I
SLA
ND
LIN
K L
IMIT
S
BIP
OLE
EX
PO
RT
= 9
00
.0 M
W
MO
NO
PO
LE C
ON
T E
XP
OR
T =
67
5.0
MW
IOC
C =
2
44
.4 M
W
WA
BU
SH
MIN
ES
=
0.0
MW
TO
TA
L IN
DU
ST
RIA
L =
2
44
.4 M
W
LAB
RA
DO
R C
ITY
= 5
9.3
MW
WA
BU
SH
= 2
2.4
MW
HQ
FE
RM
ON
T =
0.0
MW
TO
TA
L U
TIL
ITY
= 8
1.8
MW
LAB
RA
DO
R W
ES
T T
OT
AL
=
32
6.2
MW
TO
TA
L IN
TE
RN
AL
LOA
D =
41
4.9
MW
TO
TA
L LO
AD
= 6
18
7.7
MW
TO
TA
L LO
SS
ES
= 1
41
.3 M
W
20
22
CA
SE
, P
EA
K L
OA
DS
MO
N,
MA
R 2
6 2
01
8 1
4:5
7
19
53
20
CH
F 3
15
1.0
11
31
8.3
2.4
35.3
2.4
73
.5
2.4
35.3
SW
3.0
72.4
1
3.0
72.2
1
73
.5
2.4
1.0
16
14
0.2
0.0
0.0
1.0
12
5
0.0
0.0
1.0
12
5
0.8
91
12
2.9
74.1
2.2
0.8
91
12
2.9
75
.3
1.2
75.3
1.2
0.8
91
12
2.9
75
.4
19
.9
87.4
18.8
1.0
25
1.0
01
13
8.1
87.2
12.8
75.4
19.8
0.9
44
21
7.1
115.3
18.2
110.3
26.3
115.3
18.2
110.3
26.3
115.3
18.2
110.3
26.3
SW
22
.6
1702.2
380.1
1690.4
228.9
1702.2
380.1
1690.4
228.9
1702.2
380.1
1690.4
228.9
SW
163.5
SW
163.5
SW
163.5
1687.7
203.2
1.0
18
74
8.2
1 5063.1
703.2R
SW
513.0
1687.7
203.2
1687.7
203.2
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 Appendix C
55
2022 Island Light Load Case
14.3
1.8
TL2
03
0.0SW
4.4
8.6
6.2
14
.3
VA
LE
41
.6
37
.6
12
.6
29
.5
12
.6
26
.0
48
.4
11
.5
8.6
34
.73
4.9
15
.3
G1
G2
153.0
26.9
40.6 40.7
40.2
21.8
40.2
23.6
12
.8
12
.3
7.8
19.3
1.3
0.8
62
.7 0.0
0.0
56
.3
10
.2
6.6
41
.8
7.7
23.8
0.0
62
.8
0.9
66
13
.3
19
.9 0
.5
57
.5T
L23
35
1.5
1.0
24
23
5.5
1.0
16
14
.0
48
.0
1.0
05
23
1.1
48
.4
15
.5
56
.6
0.8
TL208
0.0
0.0
1.0
00
23
0.0
1.0
00
34
5.0
138.1
44.7
1.0
34
32
5.8
GT
G3
12.3
ST
ON
Y B
RO
OK
1.0
25
14
.1
79.8
26
.6
1.0
06
23
1.4
0.9
75
13
.5
0.9
75
13
.5
1.0
09
13
.9
19.2
0.7
SW
0.9
94
22
8.7
0.0
79.7
HA
RD
WO
OD
S
SC
1
SC
2
1.0
23
23
5.3
74.4
76.8
5.0
74.3
HO
LYR
OO
D
TL2
01
76.9
2.8 4.7TL242
TL265
37.9
15.0
1.0
09
23
2.1
134.9
56.4
134.9
1.1050
15.15 20.50
0.9450
20.50
0.9450
15.15
1.1050
138.1
44.7
LO
AD
S:
GE
NE
RA
TIO
N:
SW
SO
LDIE
RS
PO
ND
1.0
11
23
2.5
WE
ST
ER
N A
VA
LON
26.6
22.0
12.9
1.0
08
23
1.8
48
.2
4.9
TL2
32
5.7
51
.4
BU
CH
AN
S
0.0
TL2
63
TL2
17
1.0
17
23
3.9
1.0
16
23
3.7
1.0
00
13
.81
.00
01
6.0
1.0
08
23
1.8
SC
3
56.4
TL2
69
58
.1
46.1
32.046.2
32.0
TL204
43.5
12.2
6.3
43.5
5.8TL218
TL2
36
TL268
TL266
2
110.0
50.5
59.7
18.4
0.9
75
13
.50
.95
01
3.1
0.9
75
13
.5
0.9
50
13
.1
0.9
50
13
.1
21.9
17.6
21
.0
1.0
16
23
3.7
0.0
1.0
00
13
.8
1.0
49
4.4
51.3
18.7R
1.0
23
23
5.3
OX
EN
PO
ND
0.9
99
22
9.7
0.9
97
22
9.4
TL207
TL2
37
TL2
05
27
.6
TL231
TL234
22.0
TL202
TL206
47.1
3.3
47.5
25.5
47.0
3.3
47.5
25.5
NO
RT
H A
TLA
NT
IC =
29
.2 M
W
KR
UG
ER
60
Hz
TO
TA
L =
9
5.1
MW
VA
LE +
PR
AX
AIR
=
5
6.2
MW
HV
DC
:
R
AT
TLE
BR
OO
K =
0
.0 M
W
FE
RM
EU
SE
=
-0
.0 M
W
TO
TA
L IN
DU
ST
RIA
L =
18
1.0
MW
CO
RN
ER
BR
OO
K C
OG
EN
=
8.0
MW
ST
AR
LA
KE
- E
XP
LOIT
S =
81
.0 M
W
ISL
AN
D S
YS
TE
M O
VE
RV
IEW
ST
LA
WR
EN
CE
=
-0.0
MW
LIL
IMP
OR
T A
T S
OP
23
0 k
V =
26
9.7
MW
NLH
GE
NE
RA
TIO
N =
35
0.8
MW
H
YD
RO
RU
RA
L =
3
0.3
MW
GR
OS
S A
VA
LON
LO
AD
= 3
72
.7 M
W
10.0
30.0
1.0
00
12
0.0
1 76.9
1.4R
1 76.9
1.4R
1.0
00
12
0.0
3.4
1.8
10
.0
60
.0
0.9
77
11
7.2
1 7
9.0
29
.7R
0.9
77
11
7.2
1 7
9.0
29
.7R
0.9
97
22
9.4
50.8
11.1
50
.5
0.2
23.0
8.4
23
.0
8.4
TL270
72
.1
1.1
73
.5
23
.1
SW
14
.9
TL267 39.5
25.5
ST
AT
ION
SE
RV
ICE
+ L
OS
SE
S:
HR
D S
TA
TIO
N S
ER
VIC
E =
7.4
MW
BB
K C
ON
VE
RT
ER
LO
SS
ES
= 0
.8 M
W
TR
AN
SM
ISS
ION
LO
SS
ES
= 1
2.1
MW
G2
G3
G4
G5
G6
G1
G7
1.0
00
16
.0
1
1.0
00
16
.0
1
G1
G2
1.0
21
14
.1
1
0.9
50
13
.1
1.0
20
13
.5
1
1.0
37
4.3
0.9
90
13
.71
18
.0
2.7
RS
TA
R L
AK
E
GR
AN
ITE
CA
NA
L
1.0
00
6.9
15
.0
3.7
R
1.0
15
4.3
1
PA
RA
DIS
E
RIV
ER
SW
154.1
SW
152.7
TE
CK
=
0
.5 M
W
MA
SS
EY
DR
IVE
CA
T A
RM
DE
ER
LA
KE
TL2
48
TL2
47
WO
OD
BIN
E,
NS
ML
PO
LE 2
ML
PO
LE 1
RO
SE
BLA
NC
HE
ST
EP
HE
NV
ILLE
TL2
09
FIL
TE
RS
BO
TT
OM
BR
OO
K
CB
P&
P G
2
CB
F F
RC
TL2
11
28
.7
RA
TT
LE B
RO
OK
HIN
DS
LA
KE
1.0
08
13
.9
1.0
00
6.6
TL2
28
DE
ER
LA
KE
PO
WE
R 1.0
20
6.1
HA
WK
E'S
BA
Y =
0.0
MW
0.0
Mv
ar
ST
. A
NT
HO
NY
= 0
.0 M
W0
.0 M
va
r
NP
ST
AN
DB
Y T
HE
RM
AL
GR
EE
NH
ILL
GT
WE
SLE
YV
ILLE
GT
MO
BIL
E G
T
BA
Y d
'ES
PO
IR
23.0
6.4
GR
AN
ITE
TA
P
UP
PE
R
SA
LMO
N
3.257
.2
1.0
26
23
6.0
0.0
42.6
11
.7
MU
SK
RA
T F
ALL
S
5.0
SU
NN
YS
IDE
1.0
18
23
4.2
8.0
2.4
CO
ME
BY
CH
AN
CE
39.1
73.0
27.4
46.0
15.0
45.9
14.9
GR
AN
D F
ALL
S1
.02
62
36
.0
TL235
16
.9
0.0
HY
DR
O P
UR
CH
AS
ES
:
CB
P&
P N
LH S
UP
PLI
ED
= -
4.0
MW
CU
ST
OM
ER
GE
NE
RA
TIO
N:
NL
PO
WE
R G
EN
ER
AT
ION
=
76
.4 M
W
VA
LE D
IES
ELS
=
0.0
MW
DLP
60
Hz
GE
NE
RA
TIO
N =
8
1.1
MW
DLP
FR
C 6
0 H
z =
1
8.0
MW
NL
PO
WE
R I
NC
GE
NE
RA
TIO
N =
48
9.4
MW
TO
TA
L U
TIL
ITY
= 5
19
.7 M
W
SO
P S
TA
TIO
N S
ER
VIC
E =
6.9
MW
TO
TA
L IS
LAN
D 6
0 H
z G
EN
ER
AT
ION
= 6
15
.3 M
W
ISLA
ND
60
Hz
GE
NE
RA
TIO
N +
LIL
= 8
85
.0 M
W
ML
EX
PO
RT
AT
BB
K =
15
8.0
MW
ML
IMP
OR
T A
T B
BK
= -
15
8.0
MW
20
22
CA
SE
, LI
GH
T L
OA
DS
WE
D,
MA
R 0
7 2
01
8 1
4:2
5
18
.0
2.6
R
13
5.0
28
.2R
18
1.1
3.3
R
11
8.0
1.4
R
62
.4
7.2
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 Appendix C
56
2022 Labrador Light Load Case
4
1
1
138.1
45.0
1.0
09
23
2.1
134.9
56.4
134.9138.1
45.0
1.0
20
15
.3
56.4
1
1.0
20
15
.31
.02
01
5.3
3
MO
NT
AG
NA
IS S
UB
ST
AT
ION
GE
NE
RA
TIO
N:
LOA
DS
:
SY
ST
EM
OV
ER
VIE
W
HA
PP
Y V
ALL
EY
0.9
87
13
6.2
1.0
20
15
.3
0.9
77
13
.5
2
69.8
29.6R
154.3
SW
1.0
35
32
6.0
MU
SK
RA
T F
ALL
S
152.7
SW
SO
LDIE
RS
PO
ND
20.50
0.9450
0.9450
20.5015.27
1.1050
15.27
1.1050
0.9
05
12
.50
.93
31
2.9
1
WA
BU
SH
69.8
69.8
29.6R
29.6R
SW
2.5
1.1
15.6R
1.1
30.5R
69.8
29.6R
1.0
16
15
.20
.99
01
4.9
0.9
90
14
.9 1.0
45
24
0.4
23
1
0.9
90
14
.90
.99
01
4.9 1.0
45
24
0.3
54
0.9
90
14
.90
.99
01
4.9
11
1.0
45
24
0.3
0.9
90
14
.90
.99
01
4.9
98
0.9
90
14
.90
.99
01
4.9 1.0
45
24
0.3
76
XL1
XL2
XL3
LAB
HQ
T
L2303
L2304
SC
1S
C2
SW
SW
1.0
13
46
.6
1.0
13
46
.6
C1
C2
MU
SK
RA
T F
ALL
S =
27
9.0
MW
HA
PP
Y V
ALL
EY
GT
=
0.0
MW
LAB
RA
OR
IS
LAN
D L
INK
= 2
76
.2 M
W
1.0
60
24
3.8
GU
LL
MF
AT
S1
L13
01
L1302
MF
AT
S3
L31
01
L31
02
MF
AT
S2
CH
UR
CH
ILL
FA
LLS
L7051
L7052
L7053
25.9
25.9
500.0
97.7R
35.6R
475.0
37.4R
500.0
38.5R
499.7
38.5R
500.0
39.8R
503.5
39.1R
500.0
38.3R
499.7
37.8R
500.0
42.5R
475.0
42.7R
475.0
0.9
99
73
4.2
CH
UR
CH
ILL
FA
LLS
= 5
42
7.9
MW
1.0
44
24
0.0
ASSUMED ADDITION
LAB
RA
DO
R I
SLA
ND
LIN
K =
27
6.2
MW
MF
CO
NS
TR
UC
TIO
N =
0.0
MW
HA
PP
Y V
ALL
EY
= 3
0.1
MW
EX
PO
RT
S
HY
DR
O Q
UE
BE
C @
BO
RD
ER
= 5
00
9.0
MW
LAB
RA
DO
R S
UM
MA
RY
LAB
RA
DO
R E
AS
T T
OT
AL
= 3
0.1
MW
EX
PO
RT
S T
OT
AL
= 5
28
5.2
MW
TO
TA
L E
XP
OR
TS
= 5
28
5.2
MW
TO
TA
L LA
BR
AD
OR
= 5
70
6.9
MW
IND
US
TR
IAL
LAB
RA
DO
R W
ES
T
LAB
RA
DO
R E
AS
T
UT
ILIT
Y
UT
ILIT
Y
LAB
-HQ
T I
NT
ER
FA
CE
LIM
ITS
EX
PO
RT
= 5
20
0.0
MW
IMP
OR
T =
0.0
MW
LAB
RA
DO
R I
SLA
ND
LIN
K L
IMIT
S
BIP
OLE
EX
PO
RT
= 9
00
.0 M
W
MO
NO
PO
LE C
ON
T E
XP
OR
T =
67
5.0
MW
IOC
C =
2
44
.4 M
W
WA
BU
SH
MIN
ES
=
0.0
MW
TO
TA
L IN
DU
ST
RIA
L =
2
44
.4 M
W
LAB
RA
DO
R C
ITY
= 1
9.9
MW
WA
BU
SH
= 7
.6 M
W
HQ
FE
RM
ON
T =
0.0
MW
TO
TA
L U
TIL
ITY
= 2
7.5
MW
LAB
RA
DO
R W
ES
T T
OT
AL
=
27
1.9
MW
TO
TA
L IN
TE
RN
AL
LOA
D =
30
2.0
MW
TO
TA
L LO
AD
= 5
58
7.2
MW
TO
TA
L LO
SS
ES
= 1
19
.7 M
W
20
22
CA
SE
, LI
GH
T L
OA
DS
MO
N,
MA
R 2
6 2
01
8 1
5:1
3
19
53
20
CH
F 3
15
1.0
15
31
9.6
1.7
33.8
1.8
76
.1
1.7
33.7
SW
2.4
75.0
1
2.4
74.7
1
76
.1
1.8
1.0
34
14
2.8
0.0
0.0
1
0.0
0.0
1 0.9
94
13
7.1
30.1
2.4
0.9
94
13
7.1
30
.3
1.2
30.3
1.2
0.9
94
13
7.1
30
.3
1.1
31.9
8.8
1.0
5
1.0
16
14
0.2
31.8
9.6
30.4
1.2
0.9
51
21
8.7
95.2
18.3
91.7
35.4
95.2
18.3
91.7
35.4
95.2
18.3
91.7
35.4
SW 0.0
1681.0
337.2
1669.7
173.5
1681.0
337.2
1669.7
173.5
1681.0
337.2
1669.7
173.5
SW
164.6
SW
164.6
SW
164.6
1667.0
147.0
1.0
18
74
8.2
1 5000.9
545.4R
SW
513.0
1667.0
147.0
1667.0
147.0
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 Appendix D
57
APPENDIX C
Load Flow Plots Primary Transmission System Year Ten (2027)
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 Appendix C
58
2027 Island Peak Load Case
59.8
2.3
TL2
03
38
.6SW
12
.5
47
.9
8.5
59
.5
VA
LE
14
0.8
10
.7
48
.2
1.3
48
.3
2.0
44
.4
10
.6
7.9
13
1.5
13
3.5
18
.9
G1
G2
153.0
26.9
96.6 96.8
95.5
43.6
95.7
44.3
25
.9
25
.8
5.2
15.9
29.7
0.8
21
.2 0.0
0.0
56
.3
10
.6
16
.4
14
1.9
6.0
44.8
75
.0
21
.1
1.0
50
14
.5
15
.3 4
.8
59
.3T
L23
34
7.2
1.0
10
23
2.3
1.0
35
14
.3
44
.1
0.9
97
22
9.3
69
.5
21
.5
45
.4
0.8
TL208
60.0
48.8
1.0
00
23
0.0
1.0
00
34
5.0
355.7
128.0
1.0
26
32
3.2
GT
G3
25.7
ST
ON
Y B
RO
OK
0.9
75
13
.5
264.7
54
.8
0.9
74
22
4.0
0.9
75
13
.5
0.9
75
13
.5
0.9
86
13
.6
16.7
21.8
SW
0.9
99
22
9.7
0.0
263.6
HA
RD
WO
OD
S
SC
1
SC
2
1.0
06
23
1.3
233.3
254.9
17.5
232.4
HO
LYR
OO
D
TL2
01
256.4
9.617.2TL242
TL265
77.4
13.9
0.9
87
22
6.9
334.5
161.1
334.5
1.0750
12.91 20.50
0.9300
20.50
0.9300
12.91
1.0750
355.7
128.0
LO
AD
S:
GE
NE
RA
TIO
N:
SW
SO
LDIE
RS
PO
ND
0.9
90
22
7.7
WE
ST
ER
N A
VA
LON
1.6
22.2
25.8
1.0
29
23
6.8
69
.0
14
.5
TL2
32
6.5
47
.1
BU
CH
AN
S
8.6
TL2
63
TL2
17
1.0
04
23
0.9
0.9
96
22
9.2
1.0
00
13
.81
.02
01
6.3
0.9
79
22
5.1
SC
3
161.1
TL2
69
60
.0
97.3
6.597.5
6.5
TL204
152.7
30.2
13.7
153.6
32.0TL218
TL2
36
TL268
TL266
272.2
5.5R
5.5R
154.4
71.7
14.1
5.5
1.0
35
14
.31
.03
51
4.3
1.0
35
14
.3
1.0
25
14
.1
1.0
30
14
.2
22.2
8.1
12
.8
72.2
72.2
5.5R
0.9
96
22
9.1
0.0
1.0
00
13
.8
1.0
49
4.4
72.2
5.5R
72.2
5.5R
1.0
18
23
4.1
OX
EN
PO
ND
1.0
32
23
7.4
1.0
26
23
6.1
TL207
TL2
37
TL2
05
55
.7
TL231
TL234
44.1
TL202
TL206
134.2
0.3
137.7
1.1
134.1
0.3
137.6
1.2
NO
RT
H A
TLA
NT
IC =
29
.2 M
W
KR
UG
ER
60
Hz
TO
TA
L =
9
5.0
MW
VA
LE +
PR
AX
AIR
=
5
6.2
MW
HV
DC
:
R
AT
TLE
BR
OO
K =
0
.0 M
W
FE
RM
EU
SE
=
-0
.0 M
W
TO
TA
L IN
DU
ST
RIA
L =
18
0.5
MW
CO
RN
ER
BR
OO
K C
OG
EN
=
8.0
MW
ST
AR
LA
KE
- E
XP
LOIT
S =
81
.0 M
W
ISL
AN
D S
YS
TE
M O
VE
RV
IEW
ST
LA
WR
EN
CE
=
0.0
MW
LIL
IMP
OR
T A
T S
OP
23
0 k
V =
66
8.9
MW
NLH
GE
NE
RA
TIO
N =
10
00
.9 M
W
H
YD
RO
RU
RA
L =
8
7.6
MW
GR
OS
S A
VA
LON
LO
AD
= 9
92
.8 M
W
10.0
30.0
1.0
00
12
0.0
1 76.9
1.4R
1 76.9
1.4R
1.0
00
12
0.0
21
.3
2.8
10
.0
60
.0
0.9
75
11
6.9
1 7
9.0
34
.9R
0.9
75
11
6.9
1 7
9.0
34
.9R
1.0
26
23
6.1
61.6
6.5
61
.2
4.9
39.9
3.9
39
.9
3.9
TL270
98
.7
8.6
10
1.1
7.0
SW
15
.8
TL267 119.0
3.3
ST
AT
ION
SE
RV
ICE
+ L
OS
SE
S:
HR
D S
TA
TIO
N S
ER
VIC
E =
7.4
MW
BB
K C
ON
VE
RT
ER
LO
SS
ES
= 0
.8 M
W
TR
AN
SM
ISS
ION
LO
SS
ES
= 3
7.4
MW
G2
G3
G4
G5
G6
G1
G7
1.0
00
16
.0
1
1.0
00
16
.0
1
G1
G2
1.0
50
14
.5
12
0.0
1.6
R
0.9
75
13
.5
1.0
00
13
.2
18
.0
0.4
R
0.9
56
4.0
0.9
90
13
.71
18
.0
3.4
RS
TA
R L
AK
E
GR
AN
ITE
CA
NA
L
1.0
25
7.1
15
.0
2.3
R
1.0
00
4.2
16
.0
0.6
R
PA
RA
DIS
E
RIV
ER
SW
303.2
SW
292.1
TE
CK
=
0
.0 M
W
MA
SS
EY
DR
IVE
CA
T A
RM
DE
ER
LA
KE
TL2
48
TL2
47
WO
OD
BIN
E,
NS
ML
PO
LE 2
ML
PO
LE 1
RO
SE
BLA
NC
HE
ST
EP
HE
NV
ILLE
TL2
09
FIL
TE
RS
BO
TT
OM
BR
OO
K
CB
P&
P G
2
CB
F F
RC
TL2
11
10
.8
RA
TT
LE B
RO
OK
HIN
DS
LA
KE
1.0
08
13
.9
1.0
00
6.6
TL2
28
DE
ER
LA
KE
PO
WE
R 1.0
20
6.1
HA
WK
E'S
BA
Y =
5.0
MW
3.2
Mv
ar
ST
. A
NT
HO
NY
= 0
.0 M
W0
.0 M
va
r
NP
ST
AN
DB
Y T
HE
RM
AL
GR
EE
NH
ILL
GT
WE
SLE
YV
ILLE
GT
MO
BIL
E G
T
BA
Y d
'ES
PO
IR
40.0
9.1
GR
AN
ITE
TA
P
UP
PE
R
SA
LMO
N
8.64
5.8
1.0
21
23
4.8
0.0
94.5
9.7
MU
SK
RA
T F
ALL
S
6.2
SU
NN
YS
IDE
1.0
04
23
0.8
8.0
2.8
CO
ME
BY
CH
AN
CE
115.5
84.0
2.0
96.6
4.8
96.4
4.8
GR
AN
D F
ALL
S1
.02
12
34
.8
TL235
1.9
67
.0
HY
DR
O P
UR
CH
AS
ES
:
CB
P&
P N
LH S
UP
PLI
ED
= -
4.0
MW
CU
ST
OM
ER
GE
NE
RA
TIO
N:
NL
PO
WE
R G
EN
ER
AT
ION
=
11
0.4
MW
VA
LE D
IES
ELS
=
0.0
MW
DLP
60
Hz
GE
NE
RA
TIO
N =
8
1.1
MW
DLP
FR
C 6
0 H
z =
1
8.0
MW
NL
PO
WE
R I
NC
GE
NE
RA
TIO
N =
14
90
.6 M
W
TO
TA
L U
TIL
ITY
= 1
57
8.3
MW
SO
P S
TA
TIO
N S
ER
VIC
E =
6.8
MW
TO
TA
L IS
LAN
D 6
0 H
z G
EN
ER
AT
ION
= 1
29
9.4
MW
ISLA
ND
60
Hz
GE
NE
RA
TIO
N +
LIL
= 1
96
8.3
MW
ML
EX
PO
RT
AT
BB
K =
15
8.0
MW
ML
IMP
OR
T A
T B
BK
= -
15
8.0
MW
20
27
CA
SE
, P
EA
K L
OA
DS
WE
D,
MA
R 0
7 2
01
8 1
4:3
8
18
.0
1.3
R
16
7.0
1.7
R
18
1.1
9.7
R
11
8.0
2.6
R
62
.4
11
.0
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 Appendix C
59
2027 Labrador Peak Load Case
4
1
1
355.7
130.6
0.9
86
22
6.9
334.5
161.1
334.5355.7
130.6
1.0
20
15
.3
161.1
1
1.0
20
15
.31
.02
01
5.3
3
MO
NT
AG
NA
IS S
UB
ST
AT
ION
GE
NE
RA
TIO
N:
LOA
DS
:
SY
ST
EM
OV
ER
VIE
W
HA
PP
Y V
ALL
EY
0.9
39
12
9.6
1.0
20
15
.3
1.0
23
14
.1
20
.0
11
.5R
2
186.0
11.4R
304.4
SW
1.0
28
32
3.8
MU
SK
RA
T F
ALL
S
291.9
SW
SO
LDIE
RS
PO
ND
20.50
0.9300
0.9300
20.5013.47
1.0750
13.47
1.0750
0.9
77
13
.50
.95
81
3.2
1
WA
BU
SH
186.0
186.0
11.4R
11.4R
SW
12
.2
1.1
1.6R
1.1
9.6R
186.0
11.4R
0.9
75
14
.60
.99
01
4.9
0.9
90
14
.9 1.0
43
23
9.8
23
1
0.9
90
14
.90
.99
01
4.9 1.0
43
23
9.8
54
0.9
79
14
.70
.97
91
4.7
11
1.0
43
23
9.9
0.9
90
14
.90
.99
01
4.9
98
0.9
90
14
.80
.99
01
4.9 1.0
43
23
9.8
76
XL1
XL2
XL3
LAB
HQ
T
L2303
L2304
SC
1S
C2
SW
SW
1.0
13
46
.6
1.0
13
46
.6
C1
C2
MU
SK
RA
T F
ALL
S =
74
4.0
MW
HA
PP
Y V
ALL
EY
GT
=
20
.0 M
W
LAB
RA
OR
IS
LAN
D L
INK
= 7
11
.4 M
W
1.0
40
23
9.2
GU
LL
MF
AT
S1
L13
01
L1302
MF
AT
S3
L31
01
L31
02
MF
AT
S2
CH
UR
CH
ILL
FA
LLS
L7051
L7052
L7053
25.9
25.9
510.0
10.5R
49.6R
510.0
49.6R
510.0
49.1R
510.0
49.1R
510.0
49.7R
510.0
49.6R
510.0
48.8R
510.0
48.6R
510.0
32.5R
510.0
32.5R
510.0
0.9
95
73
1.5
CH
UR
CH
ILL
FA
LLS
= 5
61
0.0
MW
1.0
35
23
8.0
ASSUMED ADDITION
LAB
RA
DO
R I
SLA
ND
LIN
K =
71
1.4
MW
MF
CO
NS
TR
UC
TIO
N =
0.0
MW
HA
PP
Y V
ALL
EY
= 9
0.8
MW
EX
PO
RT
S
HY
DR
O Q
UE
BE
C @
BO
RD
ER
= 5
10
4.5
MW
LAB
RA
DO
R S
UM
MA
RY
LAB
RA
DO
R E
AS
T T
OT
AL
= 9
0.8
MW
EX
PO
RT
S T
OT
AL
= 5
81
6.0
MW
TO
TA
L E
XP
OR
TS
= 5
81
6.0
MW
TO
TA
L LA
BR
AD
OR
= 6
37
4.0
MW
IND
US
TR
IAL
LAB
RA
DO
R W
ES
T
LAB
RA
DO
R E
AS
T
UT
ILIT
Y
UT
ILIT
Y
LAB
-HQ
T I
NT
ER
FA
CE
LIM
ITS
EX
PO
RT
= 5
20
0.0
MW
IMP
OR
T =
0.0
MW
LAB
RA
DO
R I
SLA
ND
LIN
K L
IMIT
S
BIP
OLE
EX
PO
RT
= 9
00
.0 M
W
MO
NO
PO
LE C
ON
T E
XP
OR
T =
67
5.0
MW
IOC
C =
2
44
.4 M
W
WA
BU
SH
MIN
ES
=
0.0
MW
TO
TA
L IN
DU
ST
RIA
L =
2
44
.4 M
W
LAB
RA
DO
R C
ITY
= 6
0.1
MW
WA
BU
SH
= 2
2.7
MW
HQ
FE
RM
ON
T =
0.0
MW
TO
TA
L U
TIL
ITY
= 8
2.8
MW
LAB
RA
DO
R W
ES
T T
OT
AL
=
32
7.3
MW
TO
TA
L IN
TE
RN
AL
LOA
D =
41
8.1
MW
TO
TA
L LO
AD
= 6
23
4.0
MW
TO
TA
L LO
SS
ES
= 1
40
.0 M
W
20
27
CA
SE
, P
EA
K L
OA
DS
MO
N,
MA
R 2
6 2
01
8 1
5:1
8
19
53
20
CH
F 3
15
1.0
10
31
8.2
12.5
37.0
12
.4
71
.6
12.5
37.0
SW
11.9
70.5
1
11.8
70.3
1
71
.6
12
.5
1.0
28
14
1.8
0.0
0.0
1
0.0
0.0
1 0.9
51
13
1.2
71.2
2.6
0.9
51
13
1.2
72
.1
0.3
72.1
0.3
0.9
51
13
1.2
72
.2
22
.0
82.3
7.1
1.0
25
1.0
10
13
9.3
82.1
1.9
72.3
21.9
0.9
44
21
7.0
115.7
18.3
110.6
26.2
115.7
18.3
110.6
26.2
115.7
18.3
110.6
26.2
SW
23
.2
1713.5
380.4
1701.5
233.5
1713.5
380.4
1701.5
233.5
1713.5
380.4
1701.5
233.5
SW
163.4
SW
163.4
SW
163.4
1698.7
208.4
1.0
18
74
8.2
1 5096.1
713.3R
SW
513.0
1698.7
208.4
1698.7
208.4
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 Appendix C
60
2027 Island Light Load Case
12.8
1.3
TL2
03
0.0SW
4.8
7.2
6.6
12
.8
VA
LE
41
.0
37
.4
13
.0
29
.6
13
.1
26
.0
48
.7
11
.8
8.8
34
.73
4.9
15
.1
G1
G2
153.0
26.9
41.9 42.0
41.4
22.2
41.5
23.9
14
.9
14
.3
8.3
19.7
0.9
0.8
60
.3 0.0
0.0
56
.3
10
.0
6.8
41
.2
8.1
24.2
0.0
60
.4
0.9
65
13
.3
19
.6 0
.8
57
.8T
L23
35
2.0
1.0
23
23
5.4
1.0
14
14
.0
48
.4
1.0
05
23
1.1
47
.7
15
.2
57
.5
0.8
TL208
0.0
0.0
1.0
00
23
0.0
1.0
00
34
5.0
144.1
46.8
1.0
34
32
5.7
GT
G3
14.4
ST
ON
Y B
RO
OK
1.0
25
14
.1
82.2
26
.5
1.0
05
23
1.1
0.9
75
13
.5
0.9
75
13
.5
1.0
07
13
.9
19.5
1.1
SW
0.9
94
22
8.6
0.0
82.1
HA
RD
WO
OD
S
SC
1
SC
2
1.0
23
23
5.3
76.5
79.1
5.4
76.4
HO
LYR
OO
D
TL2
01
79.3
2.5 4.4TL242
TL265
36.5
15.4
1.0
08
23
1.8
140.6
59.1
140.6
1.1050
15.08 20.50
0.9450
20.50
0.9450
15.08
1.1050
144.1
46.8
LO
AD
S:
GE
NE
RA
TIO
N:
SW
SO
LDIE
RS
PO
ND
1.0
10
23
2.2
WE
ST
ER
N A
VA
LON
26.2
21.5
15.0
1.0
08
23
1.7
47
.5
4.6
TL2
32
5.4
51
.8
BU
CH
AN
S
0.0
TL2
63
TL2
17
1.0
16
23
3.6
1.0
15
23
3.4
1.0
00
13
.81
.00
01
6.0
1.0
06
23
1.5
SC
3
59.1
TL2
69
58
.4
46.8
32.047.0
32.1
TL204
44.7
12.6
6.6
44.8
6.3TL218
TL2
36
TL268
TL266
2
110.0
50.4
59.2
18.1
0.9
75
13
.50
.95
01
3.1
0.9
75
13
.5
0.9
50
13
.1
0.9
50
13
.1
21.5
17.2
21
.0
1.0
15
23
3.4
0.0
1.0
00
13
.8
1.0
49
4.4
51.2
18.5R
1.0
23
23
5.2
OX
EN
PO
ND
0.9
98
22
9.6
0.9
97
22
9.3
TL207
TL2
37
TL2
05
27
.5
TL231
TL234
22.4
TL202
TL206
46.5
2.7
47.0
24.9
46.5
2.7
46.9
24.9
NO
RT
H A
TLA
NT
IC =
29
.2 M
W
KR
UG
ER
60
Hz
TO
TA
L =
9
5.1
MW
VA
LE +
PR
AX
AIR
=
5
6.2
MW
HV
DC
:
R
AT
TLE
BR
OO
K =
0
.0 M
W
FE
RM
EU
SE
=
0
.0 M
W
TO
TA
L IN
DU
ST
RIA
L =
18
0.5
MW
CO
RN
ER
BR
OO
K C
OG
EN
=
8.0
MW
ST
AR
LA
KE
- E
XP
LOIT
S =
81
.0 M
W
ISL
AN
D S
YS
TE
M O
VE
RV
IEW
ST
LA
WR
EN
CE
=
-0.0
MW
LIL
IMP
OR
T A
T S
OP
23
0 k
V =
28
1.1
MW
NLH
GE
NE
RA
TIO
N =
35
0.6
MW
H
YD
RO
RU
RA
L =
2
9.7
MW
GR
OS
S A
VA
LON
LO
AD
= 3
80
.5 M
W
10.0
30.0
1.0
00
12
0.0
1 76.9
1.4R
1 76.9
1.4R
1.0
00
12
0.0
3.8
1.5
10
.0
60
.0
0.9
77
11
7.3
1 7
9.0
29
.3R
0.9
77
11
7.3
1 7
9.0
29
.3R
0.9
97
22
9.3
51.3
11.2
51
.0
0.0
23.0
8.3
23
.0
8.3
TL270
72
.6
1.4
74
.0
23
.3
SW
14
.9
TL267 38.7
25.0
ST
AT
ION
SE
RV
ICE
+ L
OS
SE
S:
HR
D S
TA
TIO
N S
ER
VIC
E =
7.4
MW
BB
K C
ON
VE
RT
ER
LO
SS
ES
= 0
.8 M
W
TR
AN
SM
ISS
ION
LO
SS
ES
= 1
1.9
MW
G2
G3
G4
G5
G6
G1
G7
1.0
00
16
.0
1
1.0
00
16
.0
1
G1
G2
1.0
18
14
.1
1
0.9
50
13
.1
1.0
18
13
.4
1
1.0
17
4.2
0.9
90
13
.71
18
.0
2.7
RS
TA
R L
AK
E
GR
AN
ITE
CA
NA
L
1.0
00
6.9
15
.0
3.7
R
1.0
14
4.3
1
PA
RA
DIS
E
RIV
ER
SW
153.9
SW
152.3
TE
CK
=
0
.0 M
W
MA
SS
EY
DR
IVE
CA
T A
RM
DE
ER
LA
KE
TL2
48
TL2
47
WO
OD
BIN
E,
NS
ML
PO
LE 2
ML
PO
LE 1
RO
SE
BLA
NC
HE
ST
EP
HE
NV
ILLE
TL2
09
FIL
TE
RS
BO
TT
OM
BR
OO
K
CB
P&
P G
2
CB
F F
RC
TL2
11
28
.6
RA
TT
LE B
RO
OK
HIN
DS
LA
KE
1.0
08
13
.9
1.0
00
6.6
TL2
28
DE
ER
LA
KE
PO
WE
R 1.0
20
6.1
HA
WK
E'S
BA
Y =
0.0
MW
0.0
Mv
ar
ST
. A
NT
HO
NY
= 0
.0 M
W0
.0 M
va
r
NP
ST
AN
DB
Y T
HE
RM
AL
GR
EE
NH
ILL
GT
WE
SLE
YV
ILLE
GT
MO
BIL
E G
T
BA
Y d
'ES
PO
IR
23.0
6.3
GR
AN
ITE
TA
P
UP
PE
R
SA
LMO
N
3.05
8.1
1.0
26
23
5.9
0.0
44.1
12
.4
MU
SK
RA
T F
ALL
S
5.5
SU
NN
YS
IDE
1.0
17
23
3.9
8.0
2.4
CO
ME
BY
CH
AN
CE
38.3
73.0
27.2
46.7
15.1
46.6
15.0
GR
AN
D F
ALL
S1
.02
62
35
.9
TL235
17
.0
0.0
HY
DR
O P
UR
CH
AS
ES
:
CB
P&
P N
LH S
UP
PLI
ED
= -
4.0
MW
CU
ST
OM
ER
GE
NE
RA
TIO
N:
NL
PO
WE
R G
EN
ER
AT
ION
=
76
.4 M
W
VA
LE D
IES
ELS
=
0.0
MW
DLP
60
Hz
GE
NE
RA
TIO
N =
8
1.1
MW
DLP
FR
C 6
0 H
z =
1
8.0
MW
NL
PO
WE
R I
NC
GE
NE
RA
TIO
N =
50
1.8
MW
TO
TA
L U
TIL
ITY
= 5
31
.6 M
W
SO
P S
TA
TIO
N S
ER
VIC
E =
6.9
MW
TO
TA
L IS
LAN
D 6
0 H
z G
EN
ER
AT
ION
= 6
15
.1 M
W
ISLA
ND
60
Hz
GE
NE
RA
TIO
N +
LIL
= 8
96
.2 M
W
ML
EX
PO
RT
AT
BB
K =
15
8.0
MW
ML
IMP
OR
T A
T B
BK
= -
15
8.0
MW
20
27
CA
SE
, LI
GH
T L
OA
DS
WE
D,
MA
R 0
7 2
01
8 1
4:4
2
18
.0
2.6
R
13
5.0
28
.1R
18
1.1
3.5
R
11
8.0
1.4
R
62
.4
7.5
NLSO REPORT – 2018 Annual Planning Assessment
Document #: TP-R-011 Appendix C
61
2027 Labrador Light Load Case
4
1
1
144.1
47.1
1.0
08
23
1.8
140.6
59.1
140.6144.1
47.1
1.0
20
15
.3
59.1
1
1.0
20
15
.31
.02
01
5.3
3
MO
NT
AG
NA
IS S
UB
ST
AT
ION
GE
NE
RA
TIO
N:
LOA
DS
:
SY
ST
EM
OV
ER
VIE
W
HA
PP
Y V
ALL
EY
0.9
60
13
2.5
1.0
20
15
.3
0.9
79
13
.5
2
72.8
28.5R
154.1
SW
1.0
34
32
5.9
MU
SK
RA
T F
ALL
S
152.3
SW
SO
LDIE
RS
PO
ND
20.50
0.9450
0.9450
20.5015.20
1.1050
15.20
1.1050
0.9
05
12
.50
.93
31
2.9
1
WA
BU
SH
72.8
72.8
28.5R
28.5R
SW
0.0
1.1
15.5R
1.1
30.3R
72.8
28.5R
1.0
17
15
.30
.99
01
4.9
0.9
90
14
.9 1.0
45
24
0.4
23
1
0.9
90
14
.90
.99
01
4.9 1.0
45
24
0.3
54
0.9
90
14
.90
.99
01
4.9
11
1.0
45
24
0.3
0.9
90
14
.90
.99
01
4.9
98
0.9
90
14
.90
.99
01
4.9 1.0
45
24
0.3
76
XL1
XL2
XL3
LAB
HQ
T
L2303
L2304
SC
1S
C2
SW
SW
1.0
13
46
.6
1.0
13
46
.6
C1
C2
MU
SK
RA
T F
ALL
S =
29
1.0
MW
HA
PP
Y V
ALL
EY
GT
=
0.0
MW
LAB
RA
OR
IS
LAN
D L
INK
= 2
88
.2 M
W
1.0
60
24
3.8
GU
LL
MF
AT
S1
L13
01
L1302
MF
AT
S3
L31
01
L31
02
MF
AT
S2
CH
UR
CH
ILL
FA
LLS
L7051
L7052
L7053
25.9
25.9
500.0
101.4R
35.6R
475.0
37.4R
500.0
38.5R
499.7
38.5R
500.0
39.8R
503.5
39.1R
500.0
38.3R
499.7
37.9R
500.0
42.6R
475.0
42.7R
475.0
0.9
99
73
4.2
CH
UR
CH
ILL
FA
LLS
= 5
42
7.9
MW
1.0
44
24
0.0
ASSUMED ADDITION
LAB
RA
DO
R I
SLA
ND
LIN
K =
28
8.2
MW
MF
CO
NS
TR
UC
TIO
N =
0.0
MW
HA
PP
Y V
ALL
EY
= 3
0.8
MW
EX
PO
RT
S
HY
DR
O Q
UE
BE
C @
BO
RD
ER
= 5
00
7.8
MW
LAB
RA
DO
R S
UM
MA
RY
LAB
RA
DO
R E
AS
T T
OT
AL
= 3
0.8
MW
EX
PO
RT
S T
OT
AL
= 5
29
6.0
MW
TO
TA
L E
XP
OR
TS
= 5
29
6.0
MW
TO
TA
L LA
BR
AD
OR
= 5
71
8.9
MW
IND
US
TR
IAL
LAB
RA
DO
R W
ES
T
LAB
RA
DO
R E
AS
T
UT
ILIT
Y
UT
ILIT
Y
LAB
-HQ
T I
NT
ER
FA
CE
LIM
ITS
EX
PO
RT
= 5
20
0.0
MW
IMP
OR
T =
0.0
MW
LAB
RA
DO
R I
SLA
ND
LIN
K L
IMIT
S
BIP
OLE
EX
PO
RT
= 9
00
.0 M
W
MO
NO
PO
LE C
ON
T E
XP
OR
T =
67
5.0
MW
IOC
C =
2
44
.4 M
W
WA
BU
SH
MIN
ES
=
0.0
MW
TO
TA
L IN
DU
ST
RIA
L =
2
44
.4 M
W
LAB
RA
DO
R C
ITY
= 2
0.1
MW
WA
BU
SH
= 7
.7 M
W
HQ
FE
RM
ON
T =
0.0
MW
TO
TA
L U
TIL
ITY
= 2
7.8
MW
LAB
RA
DO
R W
ES
T T
OT
AL
=
27
2.2
MW
TO
TA
L IN
TE
RN
AL
LOA
D =
30
3.1
MW
TO
TA
L LO
AD
= 5
59
9.1
MW
TO
TA
L LO
SS
ES
= 1
19
.8 M
W
20
27
CA
SE
, LI
GH
T L
OA
DS
MO
N,
MA
R 2
6 2
01
8 1
5:2
0
19
53
20
CH
F 3
15
1.0
15
31
9.6
1.7
34.2
1.8
75
.6
1.7
34.1
SW
2.4
74.5
1
2.4
74.3
1
75
.6
1.8
1.0
34
14
2.7
0.0
0.0
1
0.0
0.0
1 0.9
69
13
3.8
30.9
5.0
0.9
69
13
3.8
31
.1
4.0
31.1
4.0
0.9
69
13
3.8
31
.1
4.0
32.7
5.2
1.0
5
1.0
13
13
9.8
32.7
6.0
31.1
4.0
0.9
51
21
8.7
95.3
18.3
91.8
35.3
95.3
18.3
91.8
35.3
95.3
18.3
91.8
35.3
SW 0.0
1680.6
337.3
1669.3
173.5
1680.6
337.3
1669.3
173.5
1680.6
337.3
1669.3
173.5
SW
164.6
SW
164.6
SW
164.6
1666.6
147.0
1.0
18
74
8.2
1 4999.7
545.6R
SW
513.0
1666.6
147.0
1666.6
147.0