NLSO Report - OATI€¦ · Valley with the Happy Valley gas turbine in operation for 25 MW. In its Order No. P.U. 43(2017) ... PUB staff, Hydro and interested parties, and final comments,

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.


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.


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.



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.


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:








line 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.


Document #: TP-R-011 Table of Contents

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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


Document #: TP-R-011 Table of Contents

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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


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.


Document #: TP-R-011 INTRODUCTION

2

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.


Document #: TP-R-011 INTRODUCTION

3

Figure 1 –Newfoundland and Labrador Interconnected System


Document #: TP-R-011 DEFINITIONS

4

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.



8

• 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.


Document #: TP-R-011 TRANSMISSION PLANNING CRITERIA

9

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.


Document #: TP-R-011 TRANSMISSION PLANNING CRITERIA

10

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.


Document #: TP-R-011 SELECTION OF STUDY CASES

11

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


Document #: TP-R-011 SELECTION OF STUDY CASES

12

• 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.


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


Document #: TP-R-011 SPECIAL CONSIDERATIONS

14

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).


Document #: TP-R-011 LOAD FORECAST

15

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.


Document #: TP-R-011 STEADY STATE ANALYSIS

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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%



20

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.



21

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.



22

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.



23

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



24

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.



25

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



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 TL245 Deer Lake to Howley results in high line end voltages at Howley




26

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.



27

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


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%


Massey Drive7


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%


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.



28

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


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


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.



29

• 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.



30

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%


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%


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.



31

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



32

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



33

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.



34

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.


Document #: TP-R-011 SHORT CIRCUIT ANALYSIS

35

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.


Document #: TP-R-011 STABILITY ANALYSIS

36

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.



37

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



38

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:




• 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.


Document #: TP-R-011 CONCLUSIONS

39

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:



40

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.


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.


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.


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



41

• 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.



42

• 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.



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.


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.



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.


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.



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:








line at Holyrood.





o For the addition of the Maritime Link and Soldiers Pond Synchronous Condensers:








line 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:






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.


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


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.


Document #: TP-R-011 Appendix A

47

APPENDIX A

Load Flow Plots Primary Transmission System Year Two (2019)



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



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



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



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


Document #: TP-R-011 Appendix B

52

APPENDIX B

Load Flow Plots Primary Transmission System Year Five (2022)


Document #: TP-R-011 Appendix C

53


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



54


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



55


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



56


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


Document #: TP-R-011 Appendix D

57

APPENDIX C

Load Flow Plots Primary Transmission System Year Ten (2027)



58


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



59


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



60


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



61


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

Documents

NLSO Report - OATI€¦ · Valley with the Happy Valley gas turbine in operation for 25 MW. In its Order No. P.U. 43(2017) ... PUB staff, Hydro and interested parties, and final comments,