LONG-TERM DEVELOPMENT PLAN—2016 for Hydro's Electrical Transmission System ManitobaManitoba Hydro’s Hydro’s Existing Existing Generating Generating Stations Stations andand Transmission Transmission System System

ii LONG-TERM DEVELOPMENT PLAN—2016 for 's Electrical Transmission System 2 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System Executive Summary Manitoba Hydro’s electrical transmission system, consists of a network of alternating current (ac) transmission lines and terminal stations plus high voltage direct current (HVDC) transmission lines and converter stations that collectively deliver the power from Manitoba Hydro’s generating stations to customers across the province and beyond provincial boundaries. This report describes the current long term development Plan for Manitoba Hydro’s electrical transmission system covering the period from 2016 to 2035. The Plan describes the proposed additions, enhancements, replacements, and refurbishments that are needed to ensure the transmission system continues to meet Manitoba Hydro’s mandate of serving the province with a reliable supply of as well as meeting the regulated performance requirements of Manitoba Hydro and its interconnected utilities in and the . A basic performance requirement is that the transmission system be able to continue to serve firm load during an outage of a system element such as a transmission line, transformer, circuit breaker, or other auxiliary device (also known as N-1 contingency planning). The transmission system must also be designed and operated such that an outage to one part of the network will not cascade or cause stress to other parts of the transmission system or interconnected utilities outside the province. Achieving these goals requires the timely implementation of additions, enhancements and replacements in order to avoid load shed, rotating blackouts or loss of export capacity. The bulk of Manitoba’s power is transmitted from remote generating stations in the north to customers in southern Manitoba over the HVDC transmission system. The HVDC system is a critical component for meeting the electricity needs of the province. The two Nelson River HVDC transmission lines are located in the same corridor, and both HVDC southern converters are located at Dorsey which makes the current HVDC system vulnerable to a common outage. This plan includes overview of Bipole III project which increases the robustness of the HVDC system by providing an alternate transmission corridor and terminus. This Plan describes projects that span two main investment types and eight drivers of need for transmission capital investments. The two investment types are growth and sustainment, while the eight drivers are safety, load growth, reliability, transmission service, new generation, new customer connections, efficiency and aging infrastructure. The Plan also identifies which region of the province is being addressed by each capital investment. The map on the following page provides a visual for the more significant growth and sustainment projects to be implemented during the first ten years (fiscal years 2016/17 to 2025/26) of the current Capital Expenditure Forecast CEF16. A summary table follows, listing the approved and proposed capital investments covered by the Plan, grouped by region and investment type, with a mapping to the drivers that apply to each. A total of $6.15 billion of transmission-related project expenditures has been identified in the 20-year CEF16. The large majority of these expenditures are associated with growth, at $4.65 billion or 76%, while $1.50 billion or 24% are investments for sustainment. The long-term development plan is reviewed and adjusted annually to reflect revised load forecasts, updated system performance and asset condition assessments, and new requests for transmission service, bulk load connections and generation connections. Not all of the projects identified in this Plan will necessarily be built; while some are approved and either underway or ready for execution, others represent proposed investments that are in the early planning stage and hence are subject to change. The new station sites and transmission lines associated with the projects described in this Plan are shown for illustrative purposes only. Manitoba Hydro follows a Site Selection and Environmental Assessment Process, which includes public consultation on the preferred location of new stations and routing of new transmission lines, and obtaining the regulatory licenses necessary for construction of facilities.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System iii Transmission Business Unit - Heat Map for Major + Base Capital Under CEF16 (Fiscal years 2017-2026)

iv LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System Major Transmission System Projects and Drivers Drivers of Need Drivers Improve Safety Improve Growth Load Serve Local Reliability or Improve Maintain Service Transmission Provide Connect New Generation Connections Customer Efficiency Increase Aging Infrastructure Address ISD INTERCONNECTION PROJECTS Manitoba- Transmission Project 2020 05 Manitoba- Transmission Interface Project 2021 06 Keeyask Generation Outlet Transmission Facilities 2021 08 INTER-REGIONAL Sustainment Bipole II Thyristor Valve Replacement 2027 03(**) Bipole I & II Major Refurbishment (*) 2036 03 HVDC Transformer Sustainment Program 2037 03(**) Dorsey Synchronous Condenser Refurbishment (extended) 2031 03 (**) Bipole I & II DC Disconnects 2029 03 HVDC Transformer Sustainment (extended) 2030 03 (**) Transmission Line Upgrades for Improved Clearance (NERC) 2023 03 (**) Dorsey Synchronous Condenser Refurbishment 2026 03(**) Transmission Transformers Sustainment Capital Program 2032 09 (**) Transmission Line Footing Sustainment Program 2030 03 (**) HVDC Smoothing Reactor Replacements 2023 10 (**) Station Battery Bank Replacement Program 2022 03 Transmission Line Protection & Teleprotection Replacement 2018 05 (**) Bipole I & II Space Dampers Project (Phase 2) 2017 12 (**) Transmission Line Wood Pole Sustainment Capital Program 2026 03 (**) Mobile Radio System Modernization 2017 06 Bipole I & II Communications Upgrade 2024 03 115 kV Protection Upgrades 2023 03 (**) Telecommunications 48VDC Upgrades 2036 (**) HVDC BP2 Valve Hall Wall Bushing Replace 2024 10 (**) PCB Bushing Elimination Program 2024 03 (**) HVDC Gapped Arrester Replacement 2021 11 (**) Transmission Breaker Sustainment Capital Program 2033 03 (**) HVDC Circuit Breaker Opp. Mechanical Replacement 2019 03 (**) 13.2 kV Shunt Reactor Replacement Program 2018 11 (**) HVDC BP2 Refrigerant Condenser Replacement 2025 11 (**)

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System v Drivers of Need Drivers Improve Safety Improve Growth Load Serve Local Reliability or Improve Maintain Service Transmission Provide Connect New Generation Connections Customer Efficiency Increase Aging Infrastructure Address ISD HVDC BP1 DCCT Transductor Replacement 2028 10 (**) HVDC System Transformer & Reactor Fire Protection 2017 06 Bipole I & II DC Filter Protection 2025 03 Growth Bipole III Reliability Project 2018 07 Southern AC System Breaker Replacements 2017 06 (**) Area Capacitor Bank Additions (Phase 1) 2019 11 Winnipeg Area Capacitor Bank Additions (Phase 2) 2026 10 REGIONAL Northern Region Sustainment Diesel Generating Station Upgrades 2020 03 Mile 13 Station Salvage 2028 03 Western Region Sustainment Brandon Area Transmission Improvements 2016 07 Growth Southwestern Manitoba Capacity Enhancement 2030 10 Winnipeg to Brandon System Improvements 2025 04 Brandon-Victoria 115-66 kV Capacity Addition 2022 10 Souris East Transformer Capacity Enhancement 2019 10 Dauphin/Vermillion 230 kV Station Capacity Increase 2022 10 Region Growth Bank Addition 2023 09 Rosser Station 115-66 kV Transformer Addition 2019 10 Eastern Region Sustainment Pointe du Bois Transmission Refurbishment/Redevelopment (Phase 1) 2016 12 Growth Steinbach Area 230-66 kV Capacity Enhancement 2020 10 (**) East System Improvements 2017 09 Letellier - St. Vital 230 kV Transmission Line 2020 07 Pointe du Bois Transmission Refurbishment/Redevelopment (Phase 2) 2024 04

vi LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System Drivers of Need Drivers Improve Safety Improve Growth Load Serve Local Reliability or Improve Maintain Service Transmission Provide Connect New Generation Connections Customer Efficiency Increase Aging Infrastructure Address ISD Whiteshell Area 115-33/66 kV Station 2028 10 Stanley Station 230-66 kV Transformer Additions 2018 10 Portage Area 230-66 kV Capacity Upgrade 2029 10 Winnipeg Region Growth Rockwood East 230-115 kV Station & Line Sectionalization 2016 02 (**) SW Winnipeg 115 kV Transmission System Improvements 2021 10 (**) La Verendrye to St. Vital 230 kV Transmission Line and Breakers 2020 10 (**) Northeast Winnipeg Capacity Enhancement 2031 10 La Verendrye Station 230-66 kV Bank Addition 2023 10 (*) Projects indicated in red are currently in the Early Planning Stage and subject to change. (**) Multiple years Table does not include projects under $10 million.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System vii Contents Manitoba Hydro’s Existing Generating Stations and Transmission System...... ii Executive Summary...... iii Major Transmission System Projects and Drivers...... v 1. Introduction...... 1 2. Drivers and Process for Transmission Capital Investments...... 3 2.1 Drivers...... 3 2.1.1 Improve Safety...... 3 2.1.2 Serve Local Load Growth...... 3 2.1.3 Maintain and Improve Reliability...... 4 2.1.4 Provide Transmission Service...... 4 2.1.5 Connect New Generation...... 4 2.1.6 Customer Connections...... 5 2.1.7 Increase Efficiency...... 5 2.1.8 Address Aging Infrastructure...... 5 2.2 Planning Process...... 6 3. Transmission System Projects...... 9 3.1 Interconnections Projects...... 9 3.1.1 Manitoba - Minnesota Transmission Project (MMTP)...... 9 3.1.2 Manitoba-Saskatchewan Transmission Interface Project (MH-SPC)...... 11 3.1.3 Keeyask Generation Outlet Transmission Facilities...... 13 3.2 Inter-Regional Projects...... 15 3.2.1 Growth...... 17 3.2.1.1 Bipole III Reliability Project...... 17 3.2.1.2 Winnipeg Area Capacitor Bank Additions...... 19 3.2.2 Sustainment...... 19 3.2.2.1 Transmission Line Upgrades for Improved Clearance...... 19 3.2.2.2 Bipole I & II Spacer Damper Replacement...... 20 3.2.2.3 Bipole II Thyristor Valve Replacement...... 20 3.2.2.4 HVDC Transformer Replacement Program...... 20 3.2.2.5 Dorsey Synchronous Condenser Refurbishment...... 21 3.2.2.6 Circuit Breaker Replacements...... 21

viii LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 3.3 Regional Issues/Solutions...... 22 3.3.1 Regional Load Growth...... 22 Summer Load Growth Projections...... 24 Winter Load Growth Projections...... 25 3.3.2 Northern Region...... 26 3.3.2.1 Diesel Plant Upgrades...... 27 3.3.2.2 Mile 13 Station Salvage...... 27 3.3.3 Western Region...... 28 3.3.3.2 Souris East Capacity Enhancement...... 31 3.3.3.3 Brandon-Victoria 115 kV Breaker Replacement...... 31 3.3.3.4 Reston Station New 230 kV Ring Breaker...... 31 3.3.3.5 Virden West Capacitor Bank Installation...... 31 3.3.3.6 Dauphin/Vermilion 230 kV Capacity Increase...... 31 3.3.3.7 Brandon-Victoria Station Capacity Increase...... 32 3.3.3.8 Southwestern Manitoba Capacity Enhancement...... 32 3.3.4 ...... 33 3.3.4.1 Ashern Bank Addition...... 34 3.3.4.2 Rosser Station 115–66 kV Transformer Addition ...... 34 3.3.5 Eastern Region...... 35 3.3.5.1 Steinbach Area Capacity Enhancement...... 36 3.3.5.2 Stanley Station 230-66 kV Station Expansion...... 37 3.3.5.3 Pointe du Bois Transmission Refurbishment/Redevelopment...... 38 3.3.5.4 Lake Winnipeg East System Improvements...... 39 3.3.5.6 Letellier - St. Vital 230 kV Transmission Line...... 41 3.3.5.7 Whiteshell Station Bank 1 Replacement...... 42 3.3.5.8 Whiteshell Area 115–33/66 kV Station...... 42 3.3.6 Winnipeg Region...... 43 3.3.6.1 Improvements of 115 kV Southwest Winnipeg Transmission System...... 45 3.3.6.2 La Verendrye to St. Vital 230 kV Transmission Line...... 47 3.3.6.3 La Verendrye 3rd Bank Addition...... 48

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System ix 4. Future Capital Requirements for Transmission...... 49 4.1 Future Transmission Interconnections...... 49 4.2 Access to Electricity Markets - Transmission Service...... 49 4.3 Future Generation Interconnection...... 50 4.4 Wind Generation Interconnection...... 51 4.5 Northern Exploratory Study...... 53 4.6 Major Customer Interconnection and Load Addition...... 53 4.7 Addressing Aging Infrastructure...... 53 4.8 Northern Damping (Low Frequency Oscillations)...... 54 4.9 Future Transmission Corridors...... 55 4.10 Resource Adequacy...... 56 Appendix 1...... 57 Appendix 2 — Glossary...... 63

x LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 1. Introduction The Long Term Development Plan - for Manitoba Hydro’s Electrical Transmission System - 2016 addresses future transmission system developments. This 2016 plan reflects planned projects that have been approved in the 2016 Manitoba Hydro Capital Expenditure Forecast (CEF16). Manitoba Hydro is a provincial Crown Corporation providing electricity to 567,634 customers throughout Manitoba and service to 276,858 customers in various communities throughout southern Manitoba (Manitoba Hydro-Electric Board 65th Annual Report). Manitoba Hydro also has formal electricity export sale agreements with a number of electric utilities and marketers in the Midwestern U.S., , and Saskatchewan. Nearly all electricity generated is from clean renewable water power. On average, about 33.1 billion kilowatt-hours of electricity are generated annually. Seventy-five percent is produced by five hydroelectric generating stations on the Nelson River; the remainder is generated at ten hydroelectric stations on the Winnipeg, Saskatchewan, Burntwood and Laurie rivers; two thermal stations; two independently owned wind farms and four diesel sites. The electricity is transmitted over nearly 100,000 kilometres of transmission and distribution lines. Manitoba Hydro has 5,690 MW of generation connected to its network. In addition, 116 MW of wind generation at St. Leon and 138 MW of wind generation at St. Joseph are available to Manitoba Hydro under power purchase agreements. Roughly 3.7% of Manitoba’s annual energy generation is supplied by wind turbines. In 2015/16, the corporation supplied a provincial gross total peak of 4,479 MW (weather adjusted 4,634 MW). The provincial peak load is growing at an average rate of about 1.4% per year (energy 1.4% per year) over the next 10 years. The length of transmission lines connected to Manitoba Hydro’s transmission network include the following: • 1840 km of 500 kV transmission (HVDC) • 210 km of 500 kV transmission (AC) • 5000 km of 230 kV transmission (AC) • 1400 km of 138 kV transmission (AC) • 2900 km of 115 kV transmission (AC) Manitoba Hydro plans additions and enhancements to its transmission and distribution systems to ensure that the systems will continue to operate acceptably in the future, as the requirements change. Manitoba Hydro expects its transmission system to meet performance requirements set out in the following: • North American Electric Reliability Corporation (NERC) Reliability Standards • Manitoba Hydro’s own Transmission System Interconnection Requirements (TSIR), which defines standards for system adequacy, reliability, and security.

These standards and criteria are used to develop system addition and enhancement plans. Numerous transmission system developments comprise this plan.

Each of the developments discussed has one or more drivers of need, which are described in detail in Chapter 2. This chapter also includes the planning process followed to develop and prioritize projects.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 1 Transmission regional issues and solutions are introduced in Chapter 3. Project developments are also highlighted in this chapter with brief descriptions, expected in-service dates, and estimated cost estimates.

Currently, there are no independent generator developments in the queue. For the sake of completeness, the major proposed utility transmission and generation developments, although not finalized, are also briefly reviewed in Chapter 4. Section 4.7 of this plan provides insight into a long- term (10 years) strategy to replace aging transformers, circuit breakers and wood pole transmission structures.

Manitoba Hydro’s existing transmission facilities are outlined in Appendix 1. Abbreviations and some utility terms are listed in Appendix 2.

This document is the current Long Term Development Plan for Manitoba Hydro’s electrical transmission system. Subsequent development plans will be issued annually to reflect changing circumstances such as changes in customer demand, the need for reliability enhancements, request for transmission service, or the addition of new generator connections, addressing aging infrastructure or regulatory requirements.

The Long Term Development Plan will be posted on Manitoba Hydro Open Access Same Time Information System (OASIS) website, which can be found on the Manitoba Hydro web page (http:// www.hydro.mb.ca), then by clicking on Transmission Tariffs for Energy Supplies and Power Producers, under Your Business tab, and then selecting either the Transmission Tariff Link or Interconnection Tariff Link to get to the Manitoba Hydro OASIS page (http://www.oasis.oati.com/MHEB/index.html). The Long Term Transmission Plan is located under the System Information tab.

From Generating Stations to Customers The major transmission system is a network Voltage Ranges: of high voltage transmission lines used to move electrical power over long distances, • Generating Stations: 4 kV to 15 kV from generating stations to terminal stations. • HVDC ± 463.5 kV, ± 500 kV At terminal stations, electrical power is • Northern Transmission: 138 kV, transformed down to mid-range voltages and 230 kV sent over a network of distribution system lines to groups of distribution stations. • Southern Transmission: 115 kV, 230 kV, 500 kV At each distribution station power is transformed to lower voltages and distributed • Distribution: 4 kV to 66 kV over the distribution system feeder lines (either overhead pole lines or underground Note: 1 kV is 1,000 volts cables) to distribution transformers. Each distribution transformer transforms the voltage to lower user voltages, to directly feed a customer or a cluster of customers.

2 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 2. Drivers and Process for Transmission Capital Investments Manitoba Hydro’s transmission planning process identifies plans to connect new generating resources and new customers and assesses the adequacy of the existing and planned transmission network to provide a reliable and economic supply of electricity to Manitoba customers and external customers. Conceptual plans are developed, based on generation and load forecasts over a 10-20 year period, to ensure that the Manitoba load and contractual firm exports can be served. Manitoba Hydro plans transmission facilities in compliance with all applicable local, regional and international reliability standards and requirements. Planning studies and assessments follow established methodologies and must meet standards and criteria established by Manitoba Hydro and other regulating entities such as the Midwest Reliability Organization (MRO) and NERC. 2.1 Drivers There are eight drivers of need in determining additions, enhancements, repairs and replacements required to the transmission and HVDC systems. 1. Improve safety 2. Serve local load growth 3. Maintain or improve reliability 4. Provide transmission service 5. Connect new generation 6. Customer connections 7. Increase efficiency 8. Address aging infrastructure Each of the projects highlighted in this plan reflects one or more of these drivers, but not necessarily all eight of the drivers.

2.1.1 Improve Safety Safety is Manitoba Hydro’s first priority and most important goal. One of the important components of Manitoba Hydro’s vision is to be recognized as a leading utility in North America with respect to safety. Manitoba Hydro is committed to protecting the public and its employees from personal injury by maintaining and operating the transmission system in a safe manner. This commitment involves modifying existing circuit protection schemes, implementing new protection schemes, and periodically replacing or upgrading aging infrastructure to meet changing conditions. Circuit protection schemes are installed to minimize the probability of equipment failure and personal injury. Transmission lines are upgraded to ensure adequate clearance between the energized conductors and ground level.

2.1.2 Serve Local Load Growth Forecasted provincial load growth is used to determine the need for transmission system additions and enhancements. Expected provincial load growth is detailed in a corporate “2016 Electric Load Forecast”. Developed annually, the Electric Load Forecast predicts provincial electric load growth for the next 20 years in various load sectors, including residential, general service, area and roadway , construction power, and station service. Electric load forecast predictions are based on historical billing data and the current economic and energy price outlook and planned corporate demand side management targets.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 3 2.1.3 Maintain and Improve Reliability To fulfill its vision to be recognized as a leading utility in North America with respect to reliability, Manitoba Hydro endeavors to continue to serve firm load for an outage of a transmission system element such as transmission line, transformer, circuit breaker, or any other auxiliary device. If a system element fails to function to its design specification for any reason, the network can be re-configured so that affected area can be served from an alternate supply in most of cases. The transmission system is designed such that outages in one part of the network should not cascade or spread to neighboring areas of the transmission system causing stress on other system elements. Achieving these goals often requires transmission system additions, replacements and enhancements. If these improvements are not completed in a timely manner, service to firm load customers would be greatly compromised. Manitoba Hydro regularly conducts system simulation studies to assess the performance of the existing and future projected systems against reliability standards and to determine what transmission system improvements are required to maintain system reliability. Manitoba Hydro expects its transmission system to meet the provincially legislated performance requirements of the North American Electric Reliability Corporation (NERC) standards, and its own Transmission System Interconnection Requirements.

2.1.4 Provide Transmission Service Transmission system improvements may be required to provide or maintain transmission service under Manitoba Hydro’s Open Access Transmission Tariff (OATT). In addition Manitoba Hydro receives numerous requests for seasonal firm service and short term non-firm service, all of which are posted on the Manitoba Hydro website. (see section 4.2)

Export Sales: Manitoba Hydro currently has long term firm export sales agreements with utilities in Minnesota, Wisconsin and Saskatchewan.

Import Purchases: Manitoba Hydro plans its generation resources based on hydraulic generation availability during the lowest river flows on record. The hydraulic generation is augmented by Manitoba Hydro thermal generation and imports.

Manitoba Hydro secures imported power during the winter season. The Corporation’s predominantly hydraulic generation system usually produces surplus energy during the summer season, when river flows are generally normal or above normal. Peak Manitoba loads occur in winter.

Import purchase agreements are also used to provide energy during periods of sustained drought.

2.1.5 Connect New Generation Generation within the province may be connected to the Manitoba Hydro transmission or distribution system, in accordance with the terms and conditions of the Manitoba Hydro’s Open Access Interconnection Tariff (OAIT), posted on the Manitoba Hydro website (see section 4.2).

Manitoba Hydro conducts system studies to determine what enhancements or additions to the network will be required to connect new generation. Major generation can be connected to the transmission system with minor transmission additions only if the generation is close to major load centres or if the generation results in reversed or reduced flow on the existing transmission network.

4 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 2.1.6 Customer Connections New major customer loads requiring up to 5000 kW of power can generally be supplied by the distribution system, whereas new major loads requiring more than 5000 kW of power will likely need to be supplied by the high voltage distribution system or network transmission system. Technical requirements for connecting generators and loads to the high voltage distribution or network transmission systems are defined in Manitoba Hydro’s “Transmission System Interconnection Requirements”, also available on Manitoba Hydro’s website which can be found on the Manitoba Hydro web page (http://www.hydro.mb.ca), then by clicking on Transmission Tariffs for Energy Supplies and Power Producers, under Your Business tab, then selecting either the Transmission Tariff link or Interconnection Tariff link to get to the Manitoba Hydro OASIS page (http://oasis.midwestiso.org/oasis/mheb).

2.1.7 Increase Efficiency The responsibility of the Transmission is to provide a reliable and safe transmission system for the delivery of electricity to domestic and out-of-province customers at the lowest possible cost. In order to achieve this objective, Manitoba Hydro conducts system simulation studies to determine feasible transmission system improvements for efficient energy transmission and reduced power losses. Bipole III will provide increased efficiency by means of reducing HVDC transmission losses in Manitoba’s three HVDC bipoles. Transmission voltage upgrades have also been implemented to reduce losses.

2.1.8 Address Aging Infrastructure Replacement or repair of aging infrastructure is often required to attain a reliable transmission system. Refurbishment of aging transmission lines, the reconstruction of high voltage transmission circuits and the replacement of circuit breakers that have reached their end-of-life are examples. Re-construction of Scotland Station, Pointe du Bois line upgrades, and replacement of St. James station, are further examples. Manitoba Hydro’s Transmission business unit has also started a condition assessment program for its major assets and, based on initial results, has established sustainment programs for its transformer, circuit breaker and transmission line wood pole structure assets as part of its capital plan to fund proactive replacements and refurbishments.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 5 2.2 Planning Process Planning of the Manitoba Hydro transmission system is performed by the System Planning Department. The primary objective of the planning process is to ensure the transmission system can economically meet the current and future energy needs of the province in compliance with all applicable local, regional and international reliability standards and requirements. The North American Electric Reliability Corporation (NERC)1 Planning Standards require that a transmission system performs in a reliable manner not only under normal system operating conditions but also following a range of system disturbances using year 1 and year 5 models for the present and near-term assessment and year 10 model for long-term assessment. As a member of the Midwest Reliability Organization (MRO)2 , Manitoba Hydro complies with the NERC Transmission Planning Standards by completing an annual Transmission System Performance Assessment and submitting to the MRO a study report and documentation of any planned transmission system upgrades. Manitoba Hydro also coordinates planning activities with other neigbouring utilities and jurisdictions. Planning begins with concepts that are developed in response to the annual long term provincial load forecast, the annual Transmission System Performance Assessment, requests for generation interconnections, transmission usage requests, and bulk load connection requests. These concepts are studied and refined into alternatives in consultation with various stakeholders, and the alternative that represents the best overall value to the customer is chosen for implementation as a capital investment project. Public consultation and regulatory approvals are required to implement the selected plan if it involves development of a new station site, a new transmission corridor, and/or a new international or inter- provincial connection. Manitoba Hydro follows a Site Selection and Environmental Assessment process which includes public consultations to select locations for stations and routes from transmission lines and obtain the regulatory licenses necessary for construction of new facilities. Manitoba Hydro also conducts Environmental Impact Assessment and develops a comprehensive Environment Protection Plan for each facility proposed. The newly identified capital investments are added to the list of active and future capital investments, and this portfolio of projects is prioritized over the ten-year forecast window. The goal of the prioritization process is to optimize the scheduling of capital investments to achieve the best net value possible with the resources available. The factors that are considered during prioritization are as follows: a) a project’s matrix score under the Capital Budget Ranking Tool, b) a project’s risk profile determined via the System Reliability Risk Model (i.e., the∆ EUE), c) a project’s readiness to execute, d) the options available to mitigate the risks associated with deferral of an investment. Each of these is explained in the following paragraphs: a) The Capital Budget Ranking Tool was developed in 2006 as a means of ranking the relative importance of Transmission’s capital investments using common criteria that are linked to business unit goals. The tool provides a matrix framework for scoring projects based on the degree to which they contribute to the goals of safety, service and reliability, transfer capacity, a positive financial impact, and/or a positive environmental impact. The more goals to which

1 The North American Electric Reliability Corporation is a not-for-profit international regulatory authority whose mission is to assure the reliability of the bulk power system in North America.

2 Midwest Reliability Organization (MRO) is a non-profit organization dedicated to ensuring the reliability and security of the bulk power system in the north central region of North America, including parts of both the United States and Canada. MRO is one of eight regional entities in North America operating under authority from regulators in the United States through a delegation agreement with the North American Electric Reliability Corporation and in Canada through arrangements with provincial regulators. The primary purpose of MRO is to ensure compliance with reliability standards and perform regional assessments of the grid’s ability to meet the demands for electricity.

6 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System a project may be linked, and the greater degree to which a project is likely to contribute to a goal, the higher the score it will achieve. Projects with high matrix scores should receive funding allocations ahead of those with lower scores. b) The System Reliability Risk Model is a sophisticated tool developed in 2015 by System Planning with the aim of quantifying the risk associated with a capital project or group of projects in terms of potential impacts to the reliability of the transmission system. The tool models the operation of the transmission system with and without the additional or replacement assets for a given project or group of projects, and compares the expected unserved energy (EUE) for various potential failures on the related system network. The model factors in the system topology, load data, equipment reliability data, and network- specific conditions (e.g., tapped lines, special protection schemes, common-mode outages, etc), and averages the results over a five-year window. The difference between the EUE without the new assets and the EUE with the new assets is referred to as the delta EUE (or ∆EUE). The ∆EUE represents the risk to the reliable operation of the system that would be mitigated with the implementation of the project. Projects with high ∆EUEs should receive funding allocations ahead of those with lower ∆EUEs. c) A project’s readiness to execute is based on such elements as the availability of labour resources, the status of licensing and property requirements, and the status of material delivery and construction contracts. A project may have a high matrix score and/or a large ∆EUE but yet may still have a later in-service date under CEF16 than it did under CEF15, due to one or more of these elements causing a delay to the schedule. In such cases the change to the project’s in-service date is recorded as a delay rather than a deferral, since it is an outcome of project logistics rather than a decision by management. Knowledge about these delays will play a part in determining whether a project’s funding needs to be protected in the near-term portfolio plans or may be released to some other project. d) The options available to mitigate the risks associated with a project deferral has to do with the number of ways and ease with which operators can make real-time adjustments to the system in order to avoid dropping load or causing voltage issues. In some cases the options are very limited, are complex to implement, or would introduce problems elsewhere on the system, such that they would be the option of last resort. A project that addresses a problem area that has little to no operating flexibility should receive funding ahead of those that may be mitigated more easily. Once all approvals and corporate funding are in place, detailed engineering, material procurement, construction and commissioning will take place. The project implementation phase for new facilities can take several months to several years, depending on the scope and complexity of the project.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 7 Transmission Planning Process

Provincial Transmission Asset Load System Performance Condition Forecast Assessment Assessments

Transmission Bulk Load Generation Service Connection Connection Request Request Request

IDENTIFY REQUIREMENTS FOR CAPITAL INVESTMENT

PROJECT DEFINITION & APPROVAL

PORTFOLIOPORTFOLIO PRIORITISATIONOPTIMISATION MITIGATION IF DEFERRED

20 YEAR CAPITAL EXPENDITURE FORECAST

Transmission Planning Process

8 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 3. Transmission System Projects The following projects reported in the 2015 plan have been completed: • 230/66 kV Station. • Rockwood East 230/115 kV Station • Keeyask Construction Power The following transmission system developments presented in this chapter, approved in Manitoba Hydro’s Capital Expenditure Forecast, are required to keep the transmission system operating reliably. While these represent the bulk of projects, numerous smaller enhancement projects are also included in the Capital Plan.

The project diagrams included with the project descriptions in this chapter are conceptual diagrams. As such, these diagrams do not illustrate transmission facility siting or routing. Manitoba Hydro follows a Site Selection and Environmental Assessment process to select locations for new stations and routes for new transmission lines as discussed in Chapter 4.

3.1 Interconnections Projects 3.1.1 Manitoba - Minnesota Transmission Project (MMTP) Studies have been completed with the Midcontinent Independent System Operator (MISO) to determine the necessary transmission facilities needed to increase the firm Canada to U.S. transmission export and import capability. Facilities study concluded that new facilities will increase the MH-US export capability by 883 MW and the MH-US import capability by 698 MW.

MMTP project has the following components: 1. Development of a 500 kV AC Transmission Tie Line from Dorsey-U.S. border (approximately 215 km in length). The 500 kV AC transmission link to connect Dorsey Station to the U.S. border will be located within the south loop corridor that currently is located to the south of Winnipeg. 2. Addition of a second 500/230 kV transformer bank at Riel Station. 3. Addition of a phase shifting transformer at 230 kV Station on Glenboro – Rugby (U.S.) 230 kV Line (G82R). This device is being added to mitigate loop flow issues on the Manitoba to U.S. interface. MMTP connects to the Great Northern Transmission line (GNTL) project at the U.S. border. GNTL is being constructed by Minnesota Power and consists of a 500 kV line between the border and Iron Range (A new substation northwest of Duluth, Minnesota), a 500/230 kV transformer bank at Iron Range as well as a series compensation station near Warroad, Minnesota. The final preferred route of MMTP is shown in the figure below [https://www.hydro.mb.ca/projects/mb_mn_transmission/]. This project is being constructed under the OATT.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 9 TheThe project project is plannedis planned to be to in-service be in-service by May by 2020 May 2020and is expectedand the Manitobato cost approximately portion of $450 the project is million. expected to cost approximately $450 million.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 21

10 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 500kV Dorsey Riel 345kV 230kV NEW FACILITIES G82R MANITOBA

MINNESOTA Glenboro Phase Shifter 300 M602F 60% MVA +/- 80 degrees New Tie Transfer Level: 570 kms 883 MW South D604I 698 MW North

Forbes Ironrange 1200MVA

Chisago Arrowhead

Stone Lake King

Eau Claire Arpin Gardiner Park

3.1.2 Manitoba-Saskatchewan Transmission Interface Project (MH-SPC) Facility Studies are currently being finalized which will determine the necessary transmission facilities needed to facilitate a 100 MW increase in Power exports from Manitoba to Saskatchewan. MH-SPC Interface project has the following components: 1. Addition of a new 91 km, 230 kV transmission line between Birtle South 230 kV (Manitoba) and Tantallon 230 kV (Saskatchewan) stations. MH portion of the new line is approximately 61 km (67%) at an estimated cost of $47.3 million. 2. Birtle South 230 kV Station (Manitoba) modifications/additions, including facility additions associated with the termination of the 230 kV new transmission line and the replacement of the 230 kV line B69R current transformer (CT) at an estimated cost of $7.7 million. 3. Upgrade of the MH section of the 230 kV line P52E to 100°C design rating including wave- trap and riser replacement at -Ralls Island 230 kV Station (Manitoba) at an estimated cost of $3.0 million. The total cost for the required Network Upgrades in Manitoba is estimated to be approximately $58.0 million dollars. It should be noted that this project also requires the conversion and utilization of existing Brandon Unit #5 as a synchronous condenser. The in service date of the project is June 2021. This project is being evaluated under the Manitoba Hydro Open Access Transmission Tariff. It becomes an official Manitoba Hydro Transmission project once a facility construction agreement has been signed under the tariff, which is expected to happen in 2017.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 11 Manitoba-Saskatchewan Interconnection Lines

12 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 3.1.3 Keeyask Generation Outlet Transmission Facilities The new 695 MW Keeyask Generating Station (net 630 MW) consists of 7 units. The new outlet transmission facilities (named Keeyask Transmission Project) are needed to integrate the Keeyask generating station to the Manitoba Hydro grid at Radisson Converter station. A new Keeyask Switching Station will be established to terminate seven new 138 kV lines including four unit lines (approximately 3 km each) to receive the power from Keeyask Generating Station, and three 138 kV transmission lines (approximately 38 km each) to convey the power to Manitoba Hydro’s existing Radisson Converter Station. A construction power station has been completed and fed primarily from a 138 kV transmission line with an approximate length of 22 km tapped from existing line KN36. One of the Radisson- Keeyask lines will be constructed earlier than the other two, in order to serve as a back-up source of construction power. Station upgrades at the Radisson station will also be required including a new bay to terminate new 138 kV lines and upgrades of 31 breakers. In addition to connecting new generation to the system, the new facilities will improve the reliability of the overall transmission system. Keeyask transmission is being constructed pursuant to the terms of the Open Access Interconnection Tariff (OAIT), and construction has started after the Keeyask Hydropower Limited Partnership signed an Interconnection and Operating Agreement (IOA) in May 2015. All of the transmission facilities will be completed by August 2021 with an estimated cost of $247 million.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 13 Simplified single line diagram of Keeyask Generation Outlet Transmission

KEEWATI- NOHK 230 kV

LEGEND PROPOSED EXISTING

Simplified conceptual diagram of Keeyask Generation Connection to Northern Collector System

14 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 3.2 Inter-Regional Projects

Inter-Regional Projects

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 15 Inter-Regional Projects Project Name I.S.D. Estimated Cost (millions) Sustainment Related Projects 1 Bipole II Thyristor Valve Replacements 2027/03 (multi) $236 2 Bipole I & II Major Refurbishment 2036/03 (multi) $198 * HVDC Transformer Sustainment Program 2037/03 (multi) $189 3 Dorsey Synchronous Condenser Refurbishment (extended) Annual/March (multi) $99 4 Bipole I & II DC Disconnects 2029/03 (multi) $89 * HVDC Transformer Sustainment (extended) 2036/03 (multi) $88 * Transmission Line Upgrades for Improved Clearance (NERC) 2023/03 $75 5 Dorsey Synchronous Condenser Refurbishment 2026/03 (multi) $74 * Transmission Transformers Sustainment Capital Program 2032/09 (multi) $64 * Transmission Line Footing Sustainment Program 2030/03 (multi) $50 * HVDC Smoothing Reactor Replacements 2023/10 (multi) $47 * Station Battery Bank Replacement Program 2022/03 (multi) $46 * Transmission Line Protection & Teleprotection Replacement 2018/05 (multi) $26 6 Bipole I & II Spacer Dampers Project (Phase 2) 2017/12 (multi) $24 * Transmission Line Wood Pole Sustainment Capital Program 2026/03 (multi) $24 * Mobile Radio System Modernization 2017/06 $24 7 Bipole I & II Communications Upgrade 2024/03 $21 * 115 kV Protection Upgrades 2023/03 (multi) $20 * Telecommunications 48VDC Upgrades 2036/03 (multi) $19 8 HVDC BP2 Valve Hall Wall Bushing Replace 2024/10 (multi) $19 * PCB Bushing Elimination Program 2024/03 (multi) $19 * HVDC Gapped Arrester Replacement 2021/11 (multi) $16 * Transmission Breaker Sustainment Capital Program 2033/03 (multi) $14 * HVDC Circuit Breaker Opp. Mechanical Replacement 2019/03 (multi) $14 * 13.2 kV Shunt Reactor Replacement Program 2018/11 (multi) $14 9 HVDC BP2 Refrigerant Condenser Replacement 2025/11 (multi) $13 10 HVDC BP1 DCCT Transductor Replacement 2028/10 (multi) $12 * HVDC System Transformer & Reactor Fire Protection 2017/06 $11 11 Bipole I & II DC Filter Protection 2025/03 $10 Growth Related Projects 12 Bipole III Reliability Project 2018/07 $5,042 • Bipole III - Converter Stations 2018/07 (multi) $2,781 • Bipole III - Transmission Line 2018/07 (multi) $1,958 • Bipole III - Collector Lines 2018/07 (multi) $247 • Bipole III - Community Development Initiative (CDI) 2018/07 (multi) $57 * Southern AC System Breaker Replacements 2017/06 (multi) $14 13 Winnipeg Area Capacitor Bank Additions (Phase 1) 2019/11 $11 14 Winnipeg Area Capacitor Bank Additions (Phase 2) 2026/10 $10

Items marked with * encompass multi-areas and are not indicated on map. NOTE: Table does not include projects under $10 million. Projects indicated in red are currently in the Early Planning Stage and subject to change.

16 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 3.2.1 Growth

3.2.1.1 Bipole III Reliability Project Enhancement of the reliability and security of the existing Nelson River HVDC transmission system has been under investigation for some time. The existing Bipole I & II transmission lines carry 70 percent of Manitoba Hydro's generating capacity and are located on a common corridor, 895 km in length. The southern converters of Bipole I and II are both terminated at the Dorsey Converter Station. The Bipole I & II corridor and the Dorsey Station are vulnerable to low probability, but severe events such as fire, wind bursts, tornadoes and ice storms; that could cause extended outages creating severe hardship to Manitoba Hydro customers and Manitoba. One such event occurred on September 6, 1996 when straight line winds associated with a micro- burst resulted in the collapse of 19 HVDC transmission towers immediately north of the Dorsey Converter Station taking both the Bipole I and II out of service. Manitoba Hydro has evaluated various alternatives for enhancing the reliability of the HVDC transmission, namely the addition of gas turbines in southern Manitoba, the purchase of U.S. generation via a new 500 kV import line and a 2000 MW Bipole III HVDC system. Manitoba Hydro selected the Bipole III HVDC system as the preferred reliability enhancement project. The 2000 MW Bipole III HVDC system currently includes: • a ±500 kV 2000 MW HVDC overhead transmission line (west of Lake Winnipegois and Lake Manitoba), about 1384 km long, from new Keewatinohk Converter Station to Riel Converter Station • a 2000 MW converter station in the north (new Keewatinohk Converter Station); • One 52 km 230 kV transmission line from Long Spruce to Keewatinohk and associated upgrades at Long Spruce Station

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 17 • Four 27 km 230 kV transmission lines from Henday to Keewatinohk and associated upgrades at Henday Converter Station • A 2000 MW converter station in the south (Riel Converter Station) • Sectionalizing of the Ridgeway-Richer 230 kV line R49R into the Riel Converter Station, creating a Ridgeway-Riel 230 kV line M49R and a Riel-Richer 230 kV line M88R. • Four 250 MVar Synchronous Condensers at Riel Station • Breaker replacement at Ridgeway, Rosser and McPhillips stations due to the increased fault levels The 2000 MW converters use classical line commutated technology with a 15% overload capability to provide spare capacity to cover the loss of a converter valve on the future three bipole system. The environmental impact assessment for the project, including a program of community/ public consultation and the identification of potential impacts and mitigative measures, has been documented in an Environmental Impact Statement (EIS). The project EIS was filed with Manitoba Conservation in the fall of 2011 as application for the Environment Act License. The Clean Environment Commission (CEC) began public hearings on Manitoba Hydro’s Bipole III transmission project on October 1, 2012. The hearings provided participants with an opportunity to review and comment on the project and its environmental impacts. The hearings were completed in March 2013. An Environmental Act License was received in August 2013. The construction of Bipole III has since started. The project is planned to be in-service by July 2018 and is expected to cost approximately $5.04 billion.

KETTLE LONG SPRUCE

138kV LIMESTONE RADISSON 230kV KEEWATINOHK 230kV 31 31 3 1 2 2 52km 27km 230kV 230kv 1384km HENDAY 230kV 500kV HVDC line Bipole I 1850MW Bipole III Bipole II 2000 MW 2000MW

To To Dorsey Forbes (D603M) (M602F)

DORSEY 230kV 500kV 9 RIEL 230kV

1 1 To 2 2 Various Existing Stations Proposed To To To To Richer S. Ridgeway Ridgeway St. Vital (M88R) (M49R) (M86V & (M86V & BIPOLE III RELIABILITY PROJECT M87V) M87V) Bipole Reliability Project

18 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 3.2.1.2 Winnipeg Area Capacitor Bank Additions Export levels are at risk of curtailment during certain operating conditions due to insufficient reactive power at Dorsey Station. The solution is to install 150.3 Mvar of reactive power compensation in the Winnipeg Area (108 Mvar at La Verendrye, 24.3 Mvar at Stafford and 18 Mvar at Harrow). There are three major consumers of reactive power in the Manitoba Hydro system: the HVDC system, exports (particularly to the United States), and AC loading. The addition of capacitor banks at La Verendrye, Stafford and Harrow stations will boost the reactive power in the Winnipeg Area and help to protect the Mvar margin needed at Dorsey as the AC loading continues to grow. The in service date for the project is November 2019. Total cost of the project is estimated to be $10 million.

3.2.2 Sustainment

3.2.2.1 Transmission Line Upgrades for Improved Clearance Manitoba Hydro owns 183 transmission lines consisting of 85-115 kV, 26- 38 kV, 69-230 kV, 1-500 kV line and 2 HVDC lines which total 11,350 km in length or 40,649 line spans. When transmission line conductors carry more current, they run hotter, expand, and sag closer to the ground. In an effort to ensure compliance with applicable transmission line clearance requirements, Manitoba Hydro has been implementing a Transmission Line Rating Verification and Mitigation Program since 1988. In 2000, the program began employing aerial surveys with LiDAR technology and advanced transmission modeling programs with approximately 500 km of transmission lines assessed per year. Since the beginning of the program, Manitoba Hydro has prioritized its assessment efforts based on the facilities with the greatest impact on the reliability of the bulk electric system. The current status of the transmission line assessment program is summarized below: • Spans assessed (rating status established): 35,639 (87.7%, 10,449 circuit kilometers) • Spans requiring assessment (field survey required): 1,975 (4.9%, 510 circuit kilometers) • Spans currently under assessment (2009 & 2011 LiDAR Program): 828 (2.0%, 148 circuit kilometers) • Spans not included in scope of work due to future plans or remoteness of the transmission system: 2,207 (5.4%, 570 circuit kilometers) A preliminary evaluation that has indicated that an estimated 1455 line spans at various voltage levels will require upgrades to mitigate deficiencies in their field ratings relative to their design ratings. The mitigation cost for these spans is estimated to be $127 million (in 2013 $) based upon historical work of similar scope. The North American Electric Reliability Corporation (NERC) has become aware of discrepancies between the design ratings and actual field ratings of transmission lines. As a consequence, NERC issued an Alert on October 7, 2010 to the electrical industry with a recommendation that transmission owners conduct a field assessment of all transmission lines 100 kV and above to determine the conductor clearances relative to the assumed design clearances and develop a plan to upgrade deficient lines. The Alert requires transmission owners to develop a three year plan describing how (LiDAR, manual surveys, etc.) and when field verification of the ratings of its unverified lines will be carried out for any lines whose ratings have not been verified by field measurement. Manitoba Hydro submitted a plan to assess the remaining 18% of the transmission system on January 18, 2011, NERC’s deadline for these plans. Manitoba Hydro’s long standing Transmission Line Rating Verification and Mitigation Program has positioned Manitoba Hydro to respond to the NERC Alert. During the following nine years (2015 - 2023) Manitoba Hydro plans to upgrade the remaining deficient spans.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 19 Future remediation work required as a result of assessments will be continued under the new transmission line upgrade NERC Alert program. This work was started in April 2014.

3.2.2.2 Bipole I & II Spacer Damper Replacement The spacer dampers have reached their end-of-life and must be replaced. Solution is to replace all 56,562 spacer dampers on Bipoles I & II. Maintenance inspections have found loose steel members on the Bipole I & II towers, loose clamping arms on spacer-dampers, dampers hanging in abnormal positions, and broken conductor strands under the suspension shoes. All of these findings indicate some form of deficiency in the damping system. Replacement of the damping system is necessary in order to mitigate the effects of wind-induced vibration on the conductors and towers. The in service date for the project is December 2017. Total cost of this project is estimated to be $24 million.

3.2.2.3 Bipole II Thyristor Valve Replacement The thyristor valves at the Dorsey and Henday Converter Stations are nearing their end of life and require a long-term plan for replacement. The solution is to Replace valve groups 31, 32, 41 and 42 plus their controls at Dorsey and Henday Converter Stations. The Bipole II thyristor valves at Dorsey and Henday are the oldest of their kind still in service in the world. They range in age from 38-45 years, compared with a life expectancy of 30 years. Performance of these valve groups started to noticeably degrade in 1993. Since that time there have been many failures, including 16 fires. Failure rates have gone down in more recent years through completion of some life extension work, but our HVDC experts are not confident this respite will continue given the overall age and performance history. The complexity of work, the significant expenditures it entails, and the long time-lines needed, warrant a long-term view of their replacement. The timing of replacement is currently under review by the HVDC Engineering, System Planning and System Performance departments. Risk of failure is mitigated once Bipole III is in service. In service date for this project is March 2027 and the expected cost of the project is $236 million.

3.2.2.4 HVDC Transformer Replacement Program There is a need for pro-active condition-based replacement of identified critical converter transformers and an inventory of spare converter transformers. The solution is Maintain an inventory of spare converter transformers for use at Dorsey, Henday and Radisson, and purchase additional transformers to replace critical units. Converter transformers are very large, high value, long lead time components of the HVDC system. Of all the transformers in our system, converter transformers see the heaviest duty by far, which contributes to higher rates of degradation and aging. In 1999 Manitoba Hydro recognized the need for spare transformers due to the increasing failure rate, high outage costs, and long delivery times (up to three years) to receive replacement units. One spare is required for each type (Star or Delta) and position of converter transformer used at the Dorsey, Henday and Radisson Converter Stations. The in service date for this project is March 2037 and total cost of the project is estimated to be $189 million.

20 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 3.2.2.5 Dorsey Synchronous Condenser Refurbishment A refurbishment program is needed to extend the life of the synchronous condensers at Dorsey Station in order to avoid catastrophic failures. Three units have failed while in service and maintenance testing of other units has revealed various operational problems. The solution is completing a major inspection and overhaul of all nine synchronous condensers at Dorsey Converter Station. Synchronous condensers are needed for proper operation of the HVDC system, voltage regulation of the southern AC system, and to provide reactive power for power export to the United States. Synchronous Condenser SC12Y failed in 1987 and SC11Y failed in 1988. In 1995 maintenance testing on SC8Y revealed a defect in the A-Phase stator winding. From 2001 to 2003 maintenance inspections on SC7Y, SC8Y and SC9Y revealed fretting corrosion. And in 2001, SC11Y had an AC transfer failure, putting the synchronous condenser out of service. A major inspection and overhaul of each machine will extend life, prevent catastrophic failures, and allow for the deferral of the more costly option of full-scale replacements. System Planning is due to revisit the requirements for the Pole 1 synchronous condensers in consideration of the units being installed at Riel as part of the Bipole III project; therefore, the plan for these refurbishments has been deferred under CEF16. The risks associated with deferral will be mitigated by repair if and when a failure occurs. In service date for this project is March 2026 and the total cost of this project is estimated to be $74 million.

3.2.2.6 Circuit Breaker Replacements Circuit breakers in the southern AC system have become heavily loaded due to network growth, such that they’re at or near their safe current interrupting limit. Solution is to replace 18 breakers in the Southern AC system and to replace 15 breakers at La Verendrye Station. Of the 33 breakers identified for replacement, all but one already exceed the 95% threshold for fault levels which on its own would trigger the need for replacement. In addition, the in-service of Bipole III and Keeyask transmission will elevate short circuit levels even further, taking these breakers well beyond their interrupting capability. The potential for harm to both employees and the public in the event of a catastrophic failure of an overloaded circuit breaker is a real possibility that must be nullified as soon as possible. A catastrophic failure could also cause damage to nearby infrastructure, which could result in outages as well the need for expensive repairs. In service date for replacement of southern AC system breakers is November 2016 and for replacement of La Verendrye breakers is September 2017. Total cost of the project is estimated to be $26 million.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 21 3.3 Regional Issues/Solutions 3.3.1 Regional Load Growth Manitoba’s annual electrical energy forecast includes all electrical energy required yearly to meet the gross firm energy requirements of customers in the province. It is predicted to increase from 24,673 GW.h in 2015/2016 to 34,193 GW.h in 2035/36, for an average annual growth rate of 1.45%. The province’s yearly gross peak power requirement is the maximum power produced during the year to meet the power requirements of customers in Manitoba. It is predicted to increase from 4,479 MW in 2015/2016 to 6,250 MW in 2035/36, for an average annual growth rate of 1.45%. The raw data presented for the load growth heat maps is non-coincident peak data obtained from many different metering sources connected throughout the Manitoba Hydro electrical system. This load data is adjusted for each seasonal planning model, and is derived using the latest Corporate Load Forecast (CLF) and varied to account for forecasted corporate Demand Side Management (DSM) initiatives. The province has been divided into five different regions based on geography, characteristics of the load and proximity to major transmission routes and lines. These regions are: Northern region, Western region, Eastern region, Interlake region and Winnipeg region.

22 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System Transmission Regions

Transmission Regions Regions: Northern Region Western Region Winnipeg Region Interlake Region Eastern Region

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 23

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 15 Summer Load Growth Projections Northern Western Interlake Eastern Winnipeg Totals 2017 MW Loads 448.93 727.75 197.14 493.16 1455.68 3322.67 2026 MW Loads 431.03 802.08 212.78 603.06 1652.97 3701.90 Annual Growth -0.44% 1.13% 0.88% 2.48% 1.51% 1.27% Rate The above summer load projections are based on an average per year growth, between the years 2017 and 2026. These projections are based on non-coincident peak station loads. The largest growth region appears to be the Eastern region showing a per year average summer seasonal growth of approximately 2.5%. The Northern region shows a small decline in growth of approximately -0.4%. Total provincial load projections show an average summer seasonal per year growth of approximately 1.3%.

Heat map displays load growth using Inverse Distance Weighted interpolation. Where load transfers occur, aggregate load growth is shown at each station.

24 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System Winter Load Growth Projections Northern Western Interlake Eastern Winnipeg Totals 2017 MW Loads 815.20 1073.58 346.04 754.44 1511.22 4500.47 2026 MW Loads 849.40 1165.31 427.32 1053.07 1657.22 5152.32 Annual Growth 0.47% 0.95% 2.61% 4.40% 1.07% 1.61% Rate The above winter load projections are based on an average per year growth, between the years 2017 and 2026. These projections are based on non-coincident peak station loads. The largest growth region appears to be the Eastern region showing a per year average winter seasonal growth of approximately 4,4%. The Northern region shows the smallest growth of approximately 0.5%. Total provincial load projections show an average winter seasonal per year growth of approximately 1.6%.

Heat map displays load growth using Inverse Distance Weighted interpolation. Where load transfers occur, aggregate load growth is shown at each station.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 25 3.3.2 Northern Region The Northern Region encompasses the entire province north of 51.5° latitude. Electrical Demand has been fairly steady in recent years with load growth below the provincial average of approximately 1.4%.

Northern Region (North of 51.5° latitude)

Cities , Thompson

Municipalities Kelsey, -, Mountain, Swan Valley West

North-Portion Ethelbert, Hillsburg-Roblin- Shell River, Lakeshore, Mossey River

26 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System Northern Region Projects Project Name I.S.D. Estimated Cost (millions) Sustainment Related Projects 1 Diesel Generating Station Upgrades 2020/30 $13 • Lac Brochet Diesel Generating Station Rebuild 2020/03 (multi) $8 • Brochet Diesel Generating Station Upgrades 2020/03 $4 • Shamattawa Diesel Generating Station Upgrade 2020/03 $1 • Diesel Generating Station Upgrade 2020/03 $1 2 Mile 13 Station Salvage 2028/03 $11 Growth Related Projects 3 Shamattawa Capacity Increase 2014/11 (multi) $1 NOTE: Projects indicated in red are currently in the Early Planning Stage and subject to change.

3.3.2.1 Diesel Plant Upgrades The remote diesel generating stations (DGS) at Brochet, Lac Brochet, Shamattawa and Tadoule Lake have had minimal work performed over the last ten years, either to address deficiencies in their infrastructure or their ability to meet the growing electrical demand within the surrounding communities. To address these issues, a long-term program has been developed to upgrade these Diesel sites, providing increased electrical supply to each area while ensuring each location meets Provincial Petroleum Storage Regulations and Safety Standards. SNC Lavalin was hired to perform a condition assessment and facilities planning study for all four of Manitoba Hydro’s remaining diesel generating stations. Their 2013 report identified the work that should be completed over the next five to ten years to meet the growing load, reduce unplanned outages, and improve the reliability of the control systems. Additionally, the tank farms at Brochet, Lac Brochet and Tadoule Lake need upgrading or replacement in order to maintain a Manitoba Conservation Operating Licence. The five-year program calls for a total of $67 million in expenditures consisting of either upgrades to the existing diesel plant and tank farms (at Brochet, Shamattawa and Tadoule Lake) or installation of new diesel plant and tank farm (at Lac Brochet). The five-year window is based on current arrangements with Indigenous & Northern Affairs Canada (INAC) for cost-sharing at each site (anticipated to total $53.7 million in contributions). The upgrades at Brochet, Shamattawa and Tadoule Lake are due to be completed by March 2020, while Lac Brochet is scheduled for completion by March 2021. The total net budget for all four sites is $13 million.

3.3.2.2 Mile 13 Station Salvage This project recommends the salvage of Mile 13 station and 65kms of 115 kV transmission line HS15 between Mile 13 Station and Station. These recommendations are based on the condition of the station combined with reliability and safety concerns. The Station is more than 50 years old and at the end of its useful service life. Mile 13 Station is located in Saskatchewan, 13 miles north of Flin Flon and was originally built by Hudson’s Bay Mining & Smelting (HBM&S) to feed power to Snow Lake and Sherridon from the Island Falls (Sask) Generating Station. More recently, the Station was utilized to supply power to Sherridon Station via line HS15 as a second (redundant) supply to the source from Herblet Lake. The current completion date for this project is March 2028 and carries an estimated cost of $11.1 million.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 27 3.3.3 Western Region The Western Region encompasses the south western part of the province and is separated from the Northern Region by 51.5° latitude and follows municipal boundaries down the west side of Lake Manitoba to the Canada – US border. The most Eastern Municipalities included within the region are; The Municipality of Westlake-Gladstone, The Municipality of North Norfolk, The Municipality of Norfolk Treherne, The and The .

Western Region (South of 51.5° latitude)

Cities Brandon, Dauphin

Municipalities Alonsa, Argyle, Boissevain- Morton, Brenda-, Cartwright-Roblin, Clanwilliam-Erickson, Cornwallis, Dauphin, Deloraine-Winchester, Ellice-Archie, Elton, , Glenboro- South Cypress, Glenella- Lansdowne, Grandview, Grassland, Hamiota, Harrison Park, Killarney- Turtle Mountain, Lorne, Louise, McCreary, Minto- Odanah, Norfolk Treherne, North Cypress-Langford, North Norfolk, Oakland- Wawanesa, Oakview, Pembina, Pipestone, Prairie Lakes, Prairie View, Riding Mountain West, Riverdale, Rosedale, , Russell-, Sifton, Souris-Glenwood, Ste. Rose, Two Borders, Victoria, Wallace-Woodworth, Westlake-Gladstone, Whitehead, Yellowhead

28 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System This region represents a significant challenge to Manitoba Hydro in terms of providing adequate system strength to keep pace with the increasing electrical demand in this area. Electrical demand has grown to the point where both the 115 and 230 kV Transmission Systems are near their present capability and it is anticipated that significant improvements will be required within a ten year planning horizon. The increasing (potential or confirmed) Electrical demand within the Region stems from multiple sources. The region includes the city of Brandon which continues to see significant increases in residential construction and commercial development as well as periodic but sizable industrial load additions. The transmission system within the region also serves the Oil and Natural Gas sector, providing supply for major Pipeline and drilling operations which continue to place increasing electrical demand on the System. Since the fall in oil prices in 2014, oil drilling in the south-west part of the province has fallen off sharply. It is anticipated that oil prices will eventually rebound and oil drilling will resume in the area. This will result in higher load growth within this Region. Detailed Distribution studies of particular areas will be made over the next 10 years based on monitoring actual load growth and periodic review. A new interconnection transmission line is being studied which would allow an additional 100 MW firm exports to Saskatchewan (total firm exports of 365 MW). While this line is expected to provide some needed voltage support for the Western region, the additional power exports will place additional demand on the 115 kV & 230 kV transmission systems.

Western Region Projects Project Name I.S.D. Estimated Cost (millions) Sustainment Related Projects 1 Brandon Area Transmission Improvements 2016/07 $12 2 Reston Station New 230 kV Ring Breaker 2020/06 $3 3 V38R 230 kV Transmission Line ROW in RMNP 2017/06 (multi) $2 Growth Related Projects 4 Southwestern Manitoba Capacity Enhancement 2030/10 $100 5 Winnipeg-Brandon Transmission System 2025/04 (multi) $43 Improvements 6 Brandon-Victoria 115-66 kV Capacity Addition 2022/10 $13 7 Souris East Transformer Capacity Enhancement 2019/10 $11 8 Dauphin/Vermillion 230 kV Station Capacity 2022/10 $10 Increase 9 Brandon-Victoria 115 kV Breaker Replacements 2019/10 $4 10 Virden West Capacitor Bank Installation 2022/03 $4 NOTE: Projects indicated in red are currently in the Early Planning Stage and subject to change.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 29 3.3.3.1 Winnipeg to Brandon System Improvements Improvements to the Winnipeg to Brandon transmission system include: the addition of three 10 MVAr 66 kV capacitor banks at Portage South Station, a fourth 54 MVAr 115 kV capacitor bank at Brandon Generating Station, a fourth 230/115 kV transformer bank at Cornwallis and the construction of a 70 km Dorsey to Portage South 230 kV transmission line. The capacitor banks have been installed and are currently in-service. These improvements are necessary to alleviate low voltage levels at Portage-South. Simulation studies using load growth forecast indicate that the loss of the Dorsey to Portage South (D12P) 230 kV line during the winter peak loading will cause voltage levels in the Portage South area to drop below acceptable limits within the next few years. The Winnipeg to Brandon system improvements will provide the needed voltage support to increase system reliability and is one of several components required to remove the need to run generation at Brandon over the winter period. The total project cost is currently estimated at $42.9 million. In-service dates are as follows: • Three 10 MVAr, 66 kV capacitor banks at Portage South Station were placed into service in 2009. • A fourth 54 MVAr, 115 kV capacitor bank was installed at Brandon Generating Station in November 2012. A fourth 230/115 kV transformer bank at Cornwallis was installed in December 2013. • Construction of a new 70 km 230 kV Transmission line between Dorsey and Portage South in April 2025.

Simplified single line diagram of Winnipeg to Brandon System Improvements

30 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 3.3.3.2 Souris East Capacity Enhancement Continued Load growth in the Souris area has diminished 66 kV reserve capacity at Souris East station. Souris East station is currently equipped with a single 230-66 kV 50 MVA transformer. Stations not equipped with redundant transformers are said to have a non-firm rating which means the station can no longer supply any electrical load should a transformer failure occur. Historically, 66 kV load normally supplied from Souris East station could be transferred to Brandon Victoria 115-66 kV Station when required; however, loading has grown to the point that Brandon Victoria can no longer reliably supply the total load from Souris East station without causing voltage issues on the area’s 66 kV system. Thus, the higher electrical demand increases the risk that customers could lose supply should a station transformer failure occur. A major failure of the Souris East transformer could result in an outage lasting as long as three weeks while awaiting installation of a spare unit. Most recently a major industrial load increase has been added to the 66 kV load served by Souris East station further increasing the station demand. The recommended solution for this issue is to install a second transformer with a capacity rating of 95 MVA at Souris East Station and upgrade the existing 50 MVA unit with a new transformer rated at 95 MVA. This will result in a station equipped with two 95 MVA units with firm station capacity. The re-configured station will provide increased supply capability, one which will provide uninterrupted power supply in the event of a transformer failure. The in-service date for this project is July 2018 and carries an estimated cost of $15.2 million.

3.3.3.3 Brandon-Victoria 115 kV Breaker Replacement This project will replace nine 115 kV breakers and associated current transformers at Brandon-Victoria Station due to the age of the existing breakers and insufficient fault level ratings. The increasing station fault levels have necessitated the need for new breakers with a minimum continuous current rating of 2000 A and a minimum interrupting rating of 40 kA. This project has an in-service date of October 2019 and carries an estimated cost of $4.5 million.

3.3.3.4 Reston Station New 230 kV Ring Breaker This project will alleviate low voltage conditions at Virden-West, Birtle South, Raven Lake and Reston stations during a breaker-fail scenario by reconfiguring the existing 230 kV ring bus at Reston station and adding an additional breaker. This project is scheduled for completion by June, 2020 and carries an estimated cost of $2.6 million.

3.3.3.5 Virden West Capacitor Bank Installation This project will provide additional VAR support at Virden-West station and alleviate low voltage issues in the area arising from on-going demand increases. This project is scheduled for completion by March, 2022 and carries an estimated cost of $3.5 million.

3.3.3.6 Dauphin/Vermilion 230 kV Capacity Increase Continued Load growth in the Dauphin area has reduced the 66 kV reserve capacity at the Dauphin/ Vermilion station to the point where firm station capacity may be exceeded during winter peak demand conditions. This station is currently equipped with a two 230-66 kV transformer banks, each rated at 83 MVA and 93 MVA respectively. Due to the vast distances between adjacent 66 kV supply stations, utilizing the surrounding 66 kV network to supply localized demand is not a long-term solution. Additional capacity is required at the Dauphin/Vermilion station. A Planning study is in the final stages of completion. The study recommends replacing the existing transformers with 140 MVA units, increasing the firm station capacity by approximately 80%, thereby providing a long-term solution for the increased demand in the area. Project approval would need to be granted before this project could proceed. The estimated cost of this project is approximately $9.1 million. An in-service date has yet to be determined but it is anticipated that this capacity increase will be required by 2020.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 31 3.3.3.7 Brandon-Victoria Station Capacity Increase The city of Brandon and its immediate surroundings rely almost entirely on the Brandon–Victoria 115 – 66/33 kV station as its single 66 kV supply source with limited alternative supply options. Additionally, the station supplies the bulk of the city’s 33 kV load requirements along with Fortier station, which is equipped with a single 115 – 33 kV 50 MVA bank. The Brandon–Victoria station consists of a 115 kV main/auxiliary bus arrangement connected to five 115 kV supply lines. The station is presently equipped with two 115-66 kV 30/40 MVA transformers providing firm station capacities of 40 MVA (summer) and 47.4 MVA (winter).

Brandon-Victoria Proposed Station Expansion (Red = Recommended, Blue = Future) The city is experiencing steady growth in the residential and commercial sectors as well as periodic yet sizable load additions within the its industrial area. Demand has steadily increased over the years thus reducing the available supply at Brandon-Victoria station where station expansion and increased capacity is now required. A Planning study is in the final stages of completion which recommends replacing the two existing 40 MVA transformers with 60 MVA units with provision for a third transformer when electrical demand warrants. Ultimately, the station will be expanded to the East and be equipped with three 115-66 kV transformers having a firm station capacity of 126 MVA (summer) and 142 MVA (winter). The project would be divided into two stages, stage one being replacement of the two existing transformer banks and stage two involving station expansion to the East and installation of a third bank. The estimated cost of phase one of this project is approximately $9.0 million with phase two estimated at $6.2 million for a total of $15.2 million. Project approval would need to be granted before this project could proceed. An in-service date has yet to be determined but it is anticipated that the phase one capacity increase will be required by 2019.

3.3.3.8 Southwestern Manitoba Capacity Enhancement This proposed project would involve a 230kV transmission line approximately 120km in length from Portage South to Cornwallis stations, to provide long-term voltage support to the southwest portion of the province. This study is not yet underway. Project approval would need to be granted before this project could proceed. An in-service date has yet to be determined but it is anticipated that the phase one capacity increase will be required by 2030.

32 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 3.3.4 Interlake Region The Interlake Region encompasses the central part of the province and is separated from the Northern Region by 51.5° latitude and follows municipal boundaries between Lake Manitoba and lake Winnipeg. The most municipalities included Armstrong, Bifrost- Riverton, Coldwell, East St. Paul, Fisher, Gimli, Grahamdale, Rockwood, Rosser, St. Andrews, St. Laurent, West Interlake, West St. Paul, Woodlands.

Interlake Region (South of 51.5° latitude)

Cities Selkirk

Municipalities Armstrong, Bifrost- Riverton, Coldwell, East St. Paul, Fisher, Gimli, Grahamdale, Rockwood, Rosser, St. Andrews, St. Laurent, West Interlake, West St. Paul, Woodlands

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 33 Interlake Region Projects Project Name I.S.D. Estimated Cost (millions) Sustainment Related Projects None Growth Related Projects 1 Rosser Station 115-66 kV Transformer Addition 2022/10 $16 2 Ashern Bank Addition 2023/09 $12 NOTE: Projects indicated in red are currently in the Early Planning Stage and subject to change.

3.3.4.1 Ashern Bank Addition A 2009 Planning study identified that the area surrounding Ashern has grown to the point where the firm capacity at Ashern Station is being exceeded. There is presently insufficient existing 66 kV tie line capability with nearby stations to alleviate the Ashern firm winter overload. Ashern Station currently has two 230-66 kV 44 MVA transformer banks feeding a radial bus with four 66 kV feeders. The Ashern Bank Addition will install a third transformer bank rated at 95 MVA and will include re- configuring the 66 kV radial bus to a ring bus arrangement. The bank addition will double the existing winter firm peak limit from 57 MVA to 114 MVA providing sufficient firm winter capacity beyond 2028. This in-service date for this project is September 2023 and is estimated at $11.7 million.

3.3.4.2 Rosser Station 115–66 kV Transformer Addition Presently, the 66 kV system at Rosser Station has a non-firm rating and is supplied from a single bank designated as Bank 13. If Bank 13 is out-of-service, the 66 kV lines must be transferred to adjacent Parkdale and Ridgeway Stations. According to Distribution Engineering, the load supplied from Bank 13 cannot be transferred to the adjacent stations since this will result in low voltage conditions. In addition, Bank 13 is expected to be overloaded according to the load forecast from Distribution Engineering. Based on technical studies it is recommended that the installation of a 115-66 kV, 95 MVA transformer at Rosser Station and the replacement of the existing 115-66 kV Bank 13 rated at 40 MVA with a 115-66 kV transformer rated at 95 MVA. The installation requires 115 kV and 66 kV breakers and associated bus work. These improvements will increase the summer and winter firm ratings to 100 MVA and 128 MVA respectively. This will allow the Rosser station to supply some load currently supplied by Ridgeway Station since it is operating near firm capacity. These improvements are projected to provide adequate capacity to 2045 based on current growth trends. This project is estimates to cost approximately $16 million with an in-service date of October 2022.

34 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 3.3.5 Eastern Region The Eastern Region encompasses the south eastern part of the province and is separated from the Northern Region by 51.5° latitude and follows municipal boundaries down the east side of Lake Winnipeg to the Canada – US border. The most western Municipalities included within the region are , Reynolds, Rhineland, Ritchot, Roland, Springfield, St. Clements, St. François Xavier.

Eastern Region (South of 51.5° latitude)

Cities Morden, Portage La Prairie, Steinbach, Winkler

Municipalities Alexander, Brokenhead, Cartier, De Salaberry, Dufferin, Emerson- Franklin, Grey, Hanover, Headingley, La Broquerie, Lac du Bonnet, Macdonald, Montcalm, Morris, Piney, Portage La Prairie, Reynolds, Rhineland, Ritchot, Roland, Springfield, St. Clements, St. François Xavier, Stanley, Ste. Anne, Stuartburn, Taché, Thompson, Victoria Beach, Whitemouth

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 35 Eastern Region Projects Project Name I.S.D. Estimated Cost (millions) Sustainment Related Projects 1 Pointe du Bois Transmission Refurbishment/ 2016/12 $81 Redevelopment (Phase 1) 2 Portage-Saskatchewan Station 115-66 kV Capacity 2032/03 $4 & Buswork Upgrade 3 Portage-Saskatchewan Area 115 kV Improvements 2021/03 $4 4 Pointe du Bois - Communications 2014/11 (multi) $2 Growth Related Projects 5 Steinbach Area 230-66 kV Capacity Enhancement 2020/10 (multi) $84 6 Lake Winnipeg East System Improvements 2017/09 $76 7 Letellier-St. Vital New 230 kV Line 2020/07 $59 8 Pointe du Bois Transmission Refurbishment/ 2024/04 $51 Redevelopment (Phase 2) 9 Whiteshell Area 115-33/66 kV Station 2028/10 $35 10 Stanley Area 115 kV to 230 kV Migration (Phase 3) 2024/03 (multi) $26 11 Stanley Bank 1 & 2 Permanent Installation (Phase 2) 2018/10 $16 12 Portage Area 230-66 kV Capacity Upgrade 2029/10 $15 13 Stanley Capacitor Bank Addition 2023/03 $5 14 Whiteshell Station Bank 1 Replacement 2017/11 $3 NOTE: Projects indicated in red are currently in the Early Planning Stage and subject to change.

3.3.5.1 Steinbach Area Capacity Enhancement Above average load growth within the Steinbach area has resulted in both capacity and voltage issues. This has lead to increased operational difficulties in preventing customer outages. The geographical size of the area needing to be served and the amount of load in the area has made it increasingly difficult to transfer load to other stations. The Long-term solution is to develop a new 230-66 kV station to serve the area (Stoneybrook Station) which will be served by sectionalizing the 230 kV line V95L (Letellier to St. Vital) and constructing 150 km of new 66 kV lines. This is one of Manitoba Hydro’s highest load growth areas in the system, affecting southeast Manitoba including Steinbach and Richer as well as south Winnipeg. Without additional capacity, equipment outages could lead to load shed and rotating blackouts within these areas during cold winter peak conditions. The project has the highest ΔEUE by far of all projects evaluated to date. In service date for this project is October 2020 and the total cost of the project is estimated to be $85 million.

36 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System Overview of Steinbach Area

3.3.5.2 Stanley Station 230-66 kV Station Expansion Higher than average load growth in south central Manitoba (Winkler /Morden Area) have resulted in low voltage issues with potential NERC violations and rotating blackouts. To solve this issue, the 230–66 kV Stanley Station will under-go expansion with the addition of a 2nd and 3rd transformer bank (140 MVA each) and associated bus upgrades. Stanley and Letellier Stations, which are supplied from the 230 kV system, will ultimately supply the entire Morden/Winkler/Rosenfeld areas. This will then allow de-commissioning of the 115 kV lines YM31 and YF11 which are in need of upgrades estimated at multiple millions. Once all electrical load has been transferred to Letellier and Stanley 230 kV Stations, the 115 kV Morden Corner and Rosenfeld Stations may be salvaged. The installation of a second 230-66 kV transformer was completed in 2010. Since the permanent installation of this transformer could not be completed at that time, a temporary solution was required. A 140 MVA transformer was delivered to the station and the transformer was installed as a “Hot Stand-by” with minimum installation. This bank is installed and energized but is not supplying load. In the event of a primary transformer failure the “Hot Stand-by” can be “cut over” to re-establish electrical supply in a timely manner. Since that time, the roles of these two transformer banks has been reversed, utilizing the 140 MVA unit to supply load while the 93 MVA unit was placed into “Hot Stand-by” mode in fall of 2014. This allowed greater flexibility in transferring load between the 115 and 230 kV systems providing an option to maintain voltage levels during peak winter periods. In order to supply the entire Winkler/Morden area, Stanley Station requires the completion of project phases two and three as listed:

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 37 Phase 1 Functional interchange of Existing and Hot Standby October 2014 - Transformers Completed Phase 2 Permanent Installation of Hot Standby Transformer and October 2018 Sectionalize Line S60L Phase 3 Installation of Third Transformer, Bus Upgrades October 2018 Phase 4 Salvage Work March 2021

Stanley Station Simplified Diagram These upgrades will ensure adequate and reliable supply of electricity to meet growing demand in the Morden and Winkler area, ultimately providing a winter firm station capacity of 275 MVA. This is projected to provide adequate station supply to 2040 and beyond based on current load forecasts and will supply the entire load currently supported by the 115-66 kV Morden Corner station. The in- service date for phases two and three of this project is October 2018 with a cost for project phases two through four inclusive estimated at $42.9 million.

3.3.5.3 Pointe du Bois Transmission Refurbishment/Redevelopment The existing Pointe du Bois to Rover Station 66 kV Transmission lines consist of four lines on two parallel sets of steel towers covering a distance of 124 km (see Diagram below). The lines were first installed in 1910 and have reached “end of life” and need to be replaced. The recommended solution will salvage the existing Pointe du Bois lines and replace them with a new 115 kV line that will run from Pointe du Bois to Whiteshell Station. The proposed transmission line from Pointe du Bois to Whiteshell station would utilize the existing Slave Falls to Stafford lines to accommodate the existing 76MW generation capability of Pointe du Bois. Several other system modifications are required to accommodate this including: • Installing a new 66 kV line from Ridgeway to Rover including terminations at both stations. • Salvaging two 115-66 kV banks at Transcona Station • Installing a new 115-66 kV bank at Pointe du Bois The salvage of P1 and P2 lines was completed in the spring of 2014. The in-service date of the new 115 kV line and other modifications is spring of 2019 allowing for the salvage of the remaining P3 and P4 by April 2024. The estimated cost of these improvements is $51.1 million.

38 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System Pointe du Bois Transmission Line Replacement - Simplified Diagram

3.3.5.4 Lake Winnipeg East System Improvements Higher than average load growth is currently exceeding firm station capacity at Pine Falls Station with potential for rotating black outs in this difficult to serve region. The load served from Pine Falls Station has been increasing each year due to load growth in communities north of Manigotagan. Similar load growth has been experienced at both the Grand Beach and Victoria Beach Stations with an estimated 4-5% annual load growth (greater than three times the provincial average), not including industrial activity. To alleviate the loading issue at Pine Falls station, a temporary overload of 80% on one bank was deemed allowable effective 2013. This 80% transformer overload may reduce the expected life span of the bank, however, it was deemed necessary to adequately supply the electrical demand. This overload is allowable only under strict conditions and presently is being exceeded. By 2018 the load will exceed the normal capacity of both banks. The recommended solution to address the lack of Transmission supply in the area is to construct a new Manigotagan Corner 115-66 kV Station and a 75 km 115 kV Line (PQ95) from Pine Falls to Manigotagan Corner (see simplified Diagram). The station will be off the Bissett Highway close to the corner of Highway 304. The project has a high ∆EUE since load shed and rotating blackouts are the only remaining mitigation strategy available during a forced outage event. Furthermore, rotating blackouts are very difficult to manage in these remote areas due to long line lengths, limited access, long travel distances from service centers and the large number of stations (eight) supplied from a single supply point. Presently this project is in the construction phase with the new Manigotagan Station well underway. This project has the third highest ∆EUE of all the projects evaluated to date. The projected in service date for this project is currently September 2017 with an expected cost of $76 million.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 39 Simplified Manigotagan Interconnection Diagram

Construction Crew at work on Manigotagan Station

40 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 3.3.5.6 Letellier - St. Vital 230 kV Transmission Line Higher than average load growth in south central Manitoba will result in low voltage issues with potential NERC violations, possible rotating blackouts and export curtailment unless system improvements are performed on the 230 kV Transmission system. A study of these loading issues deemed that the best solution is to build a new 230 kV line from St. Vital Station to Letellier Station. This line would be 119 kilometers in length and would address the contingency loading and low voltage concerns in the South Central area of Manitoba. Lidar survey analysis indicated that extensive degradation and consequential de-rating of the 115 kV line YF11 (La Verendrye - Rosenfeld) has occurred. The poor physical state of YF11 has a strong impact on the loading of parallel 115 kV line YM31 (La Verendrye - Morden Corner/Rosenfeld). The costs to refurbish these two 115 kV lines to current standards is not cost effective and is one of the key drivers in migrating the south-central 115 kV load onto the 230 kV system. The addition of the proposed St. Vital-Letellier 230 kV line would provide the added 230 kV system strength to allow the full migration of 115 kV load from Rosenfeld and Morden Corner stations to the 230 kV system while maintaining export levels without the possibility of curtailment during periods of peak demand. This would be achieved by transferring all load off of these 115 kV stations to the 230- 66 kV stations at Letellier, Stanley and the proposed Stoneybrook. This migration would ensure that the south-central area of the province could continue to grow unabated by being supplied from the 230 kV system. The new 230 kV St. Vital to Letellier line would also allow the retirement of 115 kV lines YF11 and YM31 as well as the salvage of 115 kV stations at Rosenfeld and Morden Corner. The scheduled in- service date is July 2020 and carries an estimated cost of $59 million.

Proposed St. Vital to Letellier 230 kV Line

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 41 3.3.5.7 Whiteshell Station Bank 1 Replacement Load growth in the Whiteshell area was first identified having exceeded the station firm capacity in 2009/10. A Station capacity increase is required to supply existing and requested load increases. Whiteshell station presently has two 115-33 kV transformer banks rated at 20 MVA and 30 MVA and supplies the surrounding area at a 33 kV voltage level. Bank 1, rated at 20 MVA, has a separate voltage regulator and has already passed its design life. Analysis confirms the need for replacing the existing transformer Bank 1 with a new 115-66/33 kV 30 MVA unit to match the existing Bank 2. The proposed Bank replacement would be equipped with dual voltage secondary windings and would be capable of supplying either a 66 kV or 33 kV secondary network. This will support any long-term plans to convert the area to a 66 kV network. The current cost of replacing Bank 1 is estimated at $3.0M with an ISD of November 2017.

3.3.5.8 Whiteshell Area 115–33/66 kV Station A study has commenced which examines the lack of 33kV capacity in the area supplied by Whiteshell station. The new 30 MVA 115-66/33 kV transformer is scheduled to replace an existing 20 MVA unit, but recent history has shown that Whiteshell 115-33 kV load growth rate has accelerated over the past few years, necessitating the need to study this area. Once a study is finalized, recommendations will determine what solution will best address the lack of capacity in the area. Project approval would need to be granted before funding is approved for this project.

42 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 3.3.6 Winnipeg Region The Transmission systems supplying the Winnipeg region largely follow the periphery of the city limits. As indicated in the map on the next page, there is a 115 kV (orange) and 230 kV supply network (green) which surround the city load center. These are the supply “backbones” for the Distribution stations which, in turn, further step these voltage levels down to useful voltages that can be supplied directly to the residential, commercial and industrial customers.

Winnipeg Region City Winnipeg

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 43 Winnipeg 115 and 230 kV Supply Rings (115 kV = Orange, 230 kV = Green) The Winnipeg region 230 kV supply network is supplied by the major Transmission stations of La Verendrye, St. Vital, Riel, Ridgeway and Rosser stations. These 230 kV stations are supplied by the Northern Collector System through Bipole I and II. Bipole III will provide additional supply once construction has been finalized. The 115 kV supply network (orange) is supplied directly from the 230 kV system through step-down transformers at La Verendrye, Rosser, Ridgeway and St. Vital stations. This 230 kV network is the heart of the major transmission network in southern Manitoba and its reliability poses a significant impact on the City of Winnipeg, provincial economy and successful operation of the Manitoba Hydro power system. This Winnipeg region is experiencing significant growth particularly in the residential construction sector. Adequate Transmission supply capabilities must be maintained to keep pace with the on-going increase in electrical demand.

44 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System Winnipeg Region Projects Project Name I.S.D. Estimated Cost (millions) Sustainment Related Projects None Growth Related Projects 1 Rockwood East 230-115 kV Station & Line 2016/02 (multi) $50 Sectionalizion 2 SW Winnipeg 115 kV Transmission Improvements 2021/10 (multi) $40 3 La Verendrye to St. Vital 230 kV Transmission Line 2020/10 (multi) $33 and Breakers 4 Northeast Winnipeg Capacity Enhancement 2031/10 $15 5 La Verendrye Station 230-66 kV Bank Addition 2023/10 $13 6 Riel-St. Vital Transmission Upgrades 2025/10 $2 NOTE: Projects indicated in red are currently in the Early Planning Stage and subject to change.

3.3.6.1 Improvements of 115 kV Southwest Winnipeg Transmission System Load growth in southwest Winnipeg will cause single contingency overloads on 115 kV transmission lines YS33 (La Verendrye to Stafford), VS27 (St. Vital to Stafford), XV39 (Mohawk to St. Vital) and VH1 (St. Vital to Harrow). This is the result of load growth at Mohawk, Dakota, Harrow, and Stafford stations. System improvements are required in order to prevent overload of the 115 kV network in the event of a single 115 kV line outage, and to avoid potential NERC violations. The original planning study, which was approved in 2011, identified that by the summer of 2017, during peak loading an outage to 115 kV line YS33 will cause 115 kV line VS27 to be overloaded, and vice versa. In addition, it was expected that the 115 kV line XV39 would be overloaded during double circuit tower line outages by the summer of 2018, and by the summer of 2023, the 115 kV line VH1 will be overloaded during double circuit tower line outages. In 2015, Stages 1 and 2 were broken down into “a” and “b” segments when it was determined that part of Stages 1 and 2 had to be completed sooner to accommodate the City of Winnipeg Bus Rapid Transit project. This involved relocating 5kms of transmission lines YS33 and VS27 within our existing Right-of Way. This work got underway in January 2016 and was completed in July 2016. At this time, load growth projections that drove the timing and justification for the project were re-examined. It was determined that the load growth on the 115 kV system in this area had been flatter than predicted, allowing a multi-year deferral of the project. Stage 1b and 2b were rescheduled for completion by October 2019. Stage 4 (rebuild of VH1) was advanced by one year so that it will coincide with Stage 3 (October 2021) in order to realize synergies with respect to design and construction of this work. The overall project cost is estimated at $40.2 million.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 45 The required system improvements (see simplified Diagram) are broken down into four remaining project stages with in-service dates as detailed in the following table:

Project Stage Description ISD Stage 1b Rebuild 15km of 115 kV line YS33 October 2019 Stage 2b Rebuild 9 km of 115 kV line VS27 October 2019 Stage 3 Address XV39 overload by re-configuring existing 115 kV October 2021 line YV5 (La Verendrye to St. Vital) to create a La Verendrye to Wilkes radial line (YW2), and terminate former line YV5 into Mohawk station to create a Mohawk to St. Vital line (XV5) Stage 4 Replace 5 km of 115 kV line VH1 October 2021

Project Stages - Southwest Winnipeg Transmission System

Simplified Diagram of 115 kV System Improvements

46 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 3.3.6.2 La Verendrye to St. Vital 230 kV Transmission Line This project requires the construction of 37 kilometers of 230 kV transmission line between La Verendrye station and St. Vital station. The new line not only enables the 230 kV network in the Winnipeg area to withstand various severe outages, such as loss of Dorsey Converter Station, but also improves its performance during normal operation and promotes the reliability of the power system in southern Manitoba. Since the 230 kV network is currently not configured as a complete 230 kV ring surrounding the city of Winnipeg, the potential exists where the 230 kV network could be broken into segments during severe outages or equipment failure. This would cause isolation of major supply stations for the city of Winnipeg making it difficult to maintain adequate supply. The end result may be area blackouts until the system can be restored. This project will overcome these possibilities. The construction of a new 230 kV line between La Verendrye and St. Vital would complete the 230 kV ring around the city thus preventing any station isolation during equipment failure. Preliminary stages of this project have been initiated. The current in-service date for this project is October 2021 with an estimated project cost of $33.3 million.

230 kV Line between La Verendrye & St. Vital

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 47 3.3.6.3 La Verendrye 3rd Bank Addition Load on the southwest side of Winnipeg is growing at a substantial rate resulting in capacity issues. The recommended solution will add a 3rd 230-66 kV 140 MVA transformer bank at La Verendrye Station. The bank addition at La Verendrye 230-66 kV Station is needed to supply the growing load from developments such as Waverley West, Whyte Ridge and Seasons of Tuxedo. The 2012 planning study found that, based on the current load growth only, the firm rating at La Verendrye would be exceeded by the winter of 2017/18. In addition, the stations surrounding La Verendrye are at or above firm, meaning there is no spare 66 kV capacity in the area to relieve the loading at La Verendrye should it go above firm. Further development at CentrePort and/or TCPL Energy East could advance the need for this project. The in service date for this project is October 2023 and total cost of the project is estimated to be $13.3 million.

48 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 4. Future Capital Requirements for Transmission Traditional system planning challenges have primarily been related to a mandate to deliver electricity to load centers in a reliable and cost-effective manner. The development of electricity markets has provided additional challenges associated with the requirements to provide non-discriminatory generator interconnection and transmission service. 4.1 Future Transmission Interconnections As detailed in Appendix 1, the transmission system in Manitoba is interconnected to the transmission systems in the provinces of Saskatchewan and Ontario and the states of and Minnesota by 12 tie lines. Of these, three 230 kV lines and one 500 kV line interconnect the Manitoba system to the United States, three 230 kV and two 115 kV lines interconnect to Saskatchewan, and two 230 kV lines and one 115 kV line interconnect to Ontario. These interconnections allow for economic exchange of electricity as well as provide support during electric system emergencies. The interconnections are especially beneficial to Manitoba due to the characteristics of Manitoba Hydro’s predominantly hydraulic generation system. As well as exporting electricity surplus to Manitoba’s needs the interconnections allow Manitoba Hydro to import energy when economic or when river flows are low. Planned upgrades are developed to mitigate any performance deficiencies identified in the annual assessment. The past development of its hydroelectric generating plants on the Nelson River in has allowed Manitobans to enjoy some of the lowest electricity rates in North America. Manitoba Hydro is exploring the feasibility of developing new northern hydroelectric generation sites to meet future domestic load growth. New interconnections and new contracts are also evaluated to export surplus energy. Manitoba Hydro has a firm contract with Minnesota Power (MP) to provide 250 MW over 15 years starting in 2020 and a firm sale of 108 MW to Wisconsin Public Service (WPS). Manitoba Hydro has also signed a sale contract with WPS to provide up to additional 308 MW over 15 years starting in 2027. The proposed power sales agreements will facilitate new hydroelectric development in northern Manitoba (Keeyask and possibly Conawapa) and a new transmission line between Canada and the United States. A new 500 kV interconnection to the US is planned for 2020. A 20-year power purchase agreement for 100 MW was signed with SaskPower on January 29, 2016. The sale will require construction of the facilities identified in section 3.1.2 of this document. A new 230 kV interconnection to Saskatchewan is required for delivery of the service. 4.2 Access to Electricity Markets - Transmission Service Manitoba Hydro offers access to its transmission system in accordance with its Open Access Transmission Tariff (OATT). The OATT has added new challenges, as Manitoba Hydro transmission planners must respond to requests from transmission customers to use the transmission system for market transactions into, out of, or across Manitoba, and for delivery of generator output to load. To respond to a request for transmission service, planners must assess the capability of the existing infrastructure to accommodate the transaction. If the existing system cannot accommodate the desired transaction, plans for system upgrades are developed. The cost of construction of system upgrades required to accommodate a transmission service request are the responsibility of the transmission customer. Requests for transmission service are processed in the order in which they are received. The details of the OATT and the Transmission Service request process can be found on the Manitoba Hydro OASIS website, which can be found at the Manitoba Hydro website (http://www.hydro.mb.ca), then by clicking on Transmission Tariffs for Energy for Suppliers and Power Producers, under Your Business tab, and then selecting either the Transmission Tariff Link or Interconnection Tariff Link to get to the Manitoba Hydro OASIS page. (http://www.oasis.oati.com/MHEB/index.htm) OATT and Transmission Service request can be found under open Access Transmission Tariff heading.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 49 Ontario Interface Transmission Services Studies were completed in 2013 that identified facilities needed to maintain the current Manitoba to Ontario export capability of 200 MW and increase the Ontario to Manitoba import capability up to 100 MW. It was found that no new transmission is required and only upgrades to existing transmission lines such as Whiteshell-Transcona (WT34) re-conductoring and station facilities are needed. There have been minimal changes to the network in this area of the province so this study still provides conceptual solutions. However, given that it is more than one year old it does not eliminate the need for future tariff studies. There have been no long-term transmission service requests associated with Manitoba- Ontario interface since this study was completed.

Saskatchewan Interface Transmission Services On January 29, 2016 Manitoba Hydro signed a 20-year agreement to sell 100 MW of power to SaskPower, starting June 1, 2020. The 100 MW sale requires an additional 100 MW of transmission service on the Manitoba Saskatchewan interface. The service will require the construction of a new 91 km 230 kV transmission line between Birtle, MB, and Tantallon, SK, and several upgrades to existing facilities.

4.3 Future Generation Interconnection As stated earlier, one driver of transmission development is generator connection. Historically, Manitoba Hydro has been the sole generation developer in Manitoba, with the exception of some “behind the meter” generation in major customer plants. An integrated resource/transmission planning process was used to connect new generation to the transmission system. The development of electricity markets in North America has changed the process for connection of generators in Manitoba. Transmission providers are required to connect non-utility generators to the system as part of the requirement to participate in the market. Generation interconnection service is to be provided on a non-discriminatory basis, comparable to that provided to Manitoba Hydro’s own generators. To meet this requirement, Manitoba Hydro has developed an Open Access Interconnection Tariff (OAIT), which provides for connection of all generators to Manitoba Hydro’s transmission system. Manitoba Hydro provides this interconnection service to all generators requesting connection in Manitoba on a “first come, first served” basis. On receipt of a valid generation interconnection request, interconnection studies are conducted to evaluate the system impacts associated with the new generator and the facilities required to interconnect the generator. The cost of transmission facilities and network upgrades required to connect the new generator are the responsibility of the generator. For details on procedures used to request connection to Manitoba Hydro’s transmission system and the technical requirements for such connections, refer to Manitoba Hydro’s Open Access Interconnection Tariff. This document is posted on the Manitoba Hydro OASIS website, which can be found on the Manitoba Hydro website (http://www.hydro.mb.ca), by clicking on Transmission Tariffs for Energy Suppliers and Power Producers, under Your Business tab, and then selecting either the Transmission Tariff link or Interconnection Tariff link to get to the Manitoba Hydro OASIS page. (http://www.oasis.oati. com/MHEB/index.htm) Complete generation queue can be obtained from the above link by clicking on Generation Queue under Open Access Interconnection Tariff. Wuskwatim Generating Station in northern Manitoba and the new wind generating station at St. Joseph were processed in accordance with the terms and conditions of the OAIT. As it was described in Section 4.1, proposed export sales to Wisconsin Public Service & Minnesota Power, will require new hydraulic development in northern Manitoba namely Keeyask (695 MW). Transmission for Keeyask is described in Chapter 3.

50 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 4.4 Wind Generation Interconnection An exploratory study to define a conceptual transmission overlay able to connect up to 1200 MW of wind generation to the Manitoba Hydro system was completed in 2010. A resource adequacy assessment was also performed. 230 kV and 500 kV transmission expansion plans were developed for the wind installations. The short circuit level is found to be strong enough that no transient or voltage instability problems are evident. Some small signal oscillations are noted with Type-3 wind turbines when a two-mass model is used which aren’t present with a Type-4 turbine. The need for wind inertia was assessed. The addition of 1200 MW of wind degraded the transient frequency response but did not violate under frequency criteria; therefore special inertia controls are not required at this level of wind penetration. Three 230 kV plans and one 500 kV plan were chosen as the best options for further evaluation in the transient stability domain. High level diagrams of one of the 230 kV and 500 kV transmission plans are shown in the figure on the next page. In the 230 kV plans, the wind plants were collected into two stations, with each station having at least three 230 kV outlet lines. In the plan shown in the figure below, an existing station (known as Stanley) was assumed to be expanded to accommodate the wind generation. The 230 kV plans required around 200-230 km of new network transmission, not including the 230 kV transmission needed to connect the wind collector sites to the Points of Interconnection (POI), which required an additional 135 km of 230 kV transmission. In order to compare with a 500 kV solution, a single radial 500 kV line from the wind plants to the major load centre near Winnipeg was also assessed. The length of this 500 kV line was around 130 km. In this plan, the wind plants were collected into one 230 kV station, and were stepped up to 500 kV. Approximately 150 km of 230 kV transmission was needed to connect the new 230 kV station to the wind collector sites. The ultimate plan will be dependent on the actual location and size of specific wind plants. A 230 kV transmission plan was found to be superior to a 500 kV plan for 1200 MW as the plan was lower in cost, more reliable and more energy efficient.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 51 Simplified diagram of future wind generation integration

52 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 4.5 Northern Exploratory Study An Exploratory Study was completed in 2008 to determine solutions that address transmission congestion when up to an additional 400 MW of firm hydro generation is connected to the northern AC system. The objective of the study is to determine transmission solution(s) and associated cost estimates to connect up to 400 MW of generation to the Radisson 138 kV bus, with minimal impacts to Manitoba Hydro-Saskatchewan Power (MH-SP) loop-flow and MH system losses. The upgrades and cost estimates will be identified for generation amounts of 100 MW, 200 MW, 300 MW and 400 MW. Each case also includes an additional 85 MW of firm generation from Wuskwatim (23 MW) and Kelsey (62 MW). Based on overall connection cost estimates that take into account energy loss savings over a 30 year period, the 500 kV AC transmission solutions are the preferred alternative when compared to the 230 kV transmission solutions for connecting 400 MW or more of new generation to the northern AC system. The 500 kV options also provide some added flexibility for connecting future generation beyond 400 MW as the incremental costs to connect more generation would be lower than if a 230 kV solution were implemented. It should be noted however that as more generation would be added to make use of the 500 kV AC transmission, more generation unit tripping would be required to maintain transient stability for loss of a section of the 500 kV transmission line, or if unit tripping were not used then more upgrades would be required on the underlying 230 kV system. The study also demonstrated that 230 kV northern AC system with appropriate upgrades could deliver up to 300 MW at less cost than the 500 kV line. The exploratory study has been used to help define the transmission plan for Conawapa. 4.6 Major Customer Interconnection and Load Addition Manitoba Hydro has developed a process to connect new loads or load increases of large customers. A Load Interconnection Evaluation Study (LIES) is conducted to identify the impact of the new load on the system, the preliminary costs of direct connection facilities and system upgrades, including a preliminary time-line for construction. Studies are based on high level information provided by the customer on the nature of the load. The LIES provides information to allow the customer to decide whether or not to proceed with the interconnection. If the customer decides to proceed, a detailed Load Interconnection Facility Study (LIFS) is completed. This study provides cost estimates and time-lines required to connect the new load or accommodate the load increase. It is based on detail provided by the customer on the expected load characteristics. These studies lead to various agreements for construction and supply being signed. Manitoba Hydro has approximately 100 MW of new load connection requests from a number of customers in process that may appear on the system within the next five years. 4.7 Addressing Aging Infrastructure Starting in 2009, Manitoba Hydro’s Transmission Business Unit began an initiative to assess the risks associated with its aging transmission system infrastructure and to establish long term plans and budgets to manage these risks. The initiative started by reviewing asset age demographics and current approaches to asset management, and by identifying three critical assets types that were thought to have the largest impact on reliability, capital budgets, and operating and maintenance budgets: The assets were substation transformers, circuit breakers, and transmission lines. In 2012, the Transmission Business Unit employed a consultant to help develop asset condition assessment methodologies for these three asset types. Manitoba Hydro provided the consultant with its available asset data (e.g. age demographics, test data, inspection data, maintenance history, utilization data, etc.) and expertise on the assets under consideration. With this information the consultant developed methodologies to assess the condition of the transmission system’s transformer, circuit breaker, and wood pole transmission line structure assets.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 53 Based on these initial condition assessment results and associated forecasts provided by the consultant, Transmission has established three long-term sustainment capital programs as part of our capital plan to fund proactive replacements and refurbishments and to manage the risks associated with aging infrastructure: • Transformer Sustainment Capital Program • Circuit Breaker Sustainment Capital Program • Transmission Line Wood Pole Structure Sustainment Capital Program More recently, Transmission has continued to expand its condition assessment program to include other asset types such as transmission line conductors and steel towers, station batteries and protection relays. This type of information will be used by Transmission going forward to develop investment plans to manage the risks resulting from the impacts of aging infrastructure. Under asset sustainment investments program, there are a number of proposed HVDC upgrades proposed, a brief summary of each described below: Bipole II thyristor valves at the Dorsey and Henday Converter Stations are nearing their end of life and require long-term plan for replacement. The timing of replacement is currently under review by the HVDC Engineering, System Planning and System Performance Departments. There is also a need for pro-active condition-based replacement of identified critical HVDC converter transformers and an inventory of spare converter transformers. Three Dorsey synchronous condensers have failed while in service and maintenance testing has revealed various operational problems. Hence a synchronous condenser refurbishment program is needed to extend the life of the synchronous condensers in order to avoid catastrophic failures. A major inspection and overhaul of each machine will extend life, prevent catastrophic failures, and allow for the deferral of the more costly option of full-scale replacement. Recent inspections have found loose steel members on Bipole I and II towers, loose clamping arms on spacer-dampers, dampers hanging in abnormal positions and broken conductor strands under suspension shoes. Hence Bipole I and II spacer dampers have reached their end of life and must be replaced. 4.8 Northern Damping (Low Frequency Oscillations) The power system consists of generators interconnected by transmission lines. Under some operating conditions, such as after faults, power swings (Low Frequency Oscillations) can occur between generators. These power swings are not problematic as long as they are well damped. Power systems stabilizers applied to generators, SVCs and HVDC controls ensure sufficient damping for both local and inter-area power swings. Damping criterion for power system oscillations is specified in the Manitoba Hydro Transmission System Interconnection Requirements. Several Phasor Measurement Units (PMUs) have recently been installed, which will allow Manitoba Hydro to have a real-time wide area view of its power system to help identify and mitigate potential causes of instabilities in its electric grid before they develop into significant disturbances and possible failures. This technology was used to verify settings of existing power system stabilizers as well as future planned additions. This tool was used to commission the power system stabilizer on the 165 MVAr static var compensator at Birchtree. The tool allowed for rapid confirmation of setting performance as well as assurance of no adverse interaction between the various plants.

54 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 4.9 Future Transmission Corridors Manitoba Hydro currently has in excess of 4000 MW generation capacity developed in northern Manitoba. A small segment of this power is consumed in northern Manitoba, but the majority is transmitted to load centers and export markets in the south. The potential exists for many more thousands of MW of new hydraulic generation in the north, with much of that power likely to be required in the south. The geography of Manitoba essentially forms three corridors between northern and southern Manitoba: east of Lake Winnipeg, the Interlake region and west of Lakes Manitoba and (see figure left). Potential for a forth corridor involving DC submarine cable was studied by the Concepts Review Panel and detailed in the report titled “Potential Use of Submarine or Underground cables for Long Distance Electricity Transmission in Manitoba – A Post Bipole III Concepts Review” (http://electricalline.com/ node/2299 or http:// www.hydro.mb.ca/corporate/ research_and_ development/post_bipoleIII_ concepts_review. pdf) To date, as generation was developed, there has been extensive use of the Interlake corridor. As new generation is developed, routing decisions within Future transmission corridors North-South these three corridors will be required to effectively deliver new power to southern Manitoba, while respecting risks inherent with concentration of power within a single corridor. With the establishment of Riel Station in the southeastern periphery of the City of Winnipeg, there is a need to complete a loop of transmission corridor around the city. The northern portion of this loop corridor has been established for some time and the existing 500 kV line from Dorsey to Forbes uses this corridor already as well as several 230 kV lines between Dorsey, Rosser, Ridgeway and St. Vital. The possible future development around the city of Winnipeg of the south loop corridor from Dorsey to Riel could include up to two 500 kV transmission circuits. This corridor would also include up to three 230 kV transmission lines from St. Vital (or Riel) to La Verendrye. Another possibility for 230 kV transmission in this corridor is to connect new generation to Riel, St. Vital or La Verendrye stations (see figure on next page).

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 55 Riel Location & Proximity to other Urban Stations

4.10 Resource Adequacy Demands for highly reliable have increased tremendously in the past few decades. It is expected that the requirement for reliable power supply will continue to increase in the future especially in today’s changing environment. The reliable supply of electric services depends on adequate and dependable generation and transmission facilities. Over the years, deterministic criteria were used in virtually all practical power system applications to determine the system adequacy levels and some of them are still in use today. The essential weakness of deterministic criteria is that they do not respond to the random nature of component failures, customer demands and system behaviour. Since a power system behaves stochastically, probabilistic methods should be used in power system planning to determine the amount of resources and corresponding transmission to ensure an acceptable level of service reliability. Manitoba Hydro uses a probabilistic adequacy criterion of 0.1 day/year or 1 day in 10 year loss of load expectation (LOLE) in resource adequacy planning. This LOLE reliability level is currently industrially accepted. Compliance with this criterion is evaluated annually.

56 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System Appendix 1 To the Long-Term Development Plan - 2016 for Manitoba Hydro’s Electrical Transmission System Overview of Manitoba Hydro’s Transmission Facilities

Manitoba Hydro’s transmission and distribution facilities deliver electrical energy from the generating stations to consumers. Transmission and distribution facilities can be broken down into six categories: • Generation Outlet Transmission Facilities • High voltage DC (HVDC) Transmission Facilities • Interconnection Transmission Facilities • Network Transmission Facilities • Distribution Facilities

Generation Outlet Transmission Facilities Manitoba Hydro’s generation outlet transmission facilities transfer electrical energy from the generating stations to the transmission system using short, low-voltage bus work, voltage step-up transformers, high-voltage transmission lines that connect to the grid, and associated equipment. About 90% of Manitoba Hydro’s hydraulic generating capacity is supplied by generating stations in the northern part of the province. A small portion of this generation (19%) is fed directly to the northern AC transmission system, which serves northern areas. The rest (81%) is connected to an isolated 138/230 kV transmission system known as the northern collector system via facilities consisting of 13.8 kV transmission lines and 13.8/138 kV or 13.8/230 kV step-up transformers. The collector system connects ac to the dc converter stations at Radisson (138 kV) and Henday (230 kV). Two high-voltage direct current (HVDC) lines connect to the Radisson and Henday Converter Stations to Dorsey Converter Station, on the outskirts of Winnipeg. From there, the electricity is distributed to much of southern Manitoba through the southern AC transmission system. The remaining 10% of hydraulic generation is supplied by generating stations in the southern part of the province, including the plants. Generation outlet transmission facilities for the Winnipeg River plants consist of 6.9 kV, 11 kV, and 13.8 kV transmission stepped up to 69 kV and 115 kV transmission lines. Voltage step-up transformers integrate the supplied energy into the Manitoba Hydro southern AC transmission system. A privately owned 99 MW wind farm near the town of St. Leon is connected to Manitoba Hydro’s network via a direct connection to the 230 kV at St. Leon station. Also a privately owned 138 MW wind farm near the town of St. Joseph is connected to Manitoba Hydro’s network via a direct connection to the 230 kV at Letellier station. The rest of the power generated by Manitoba Hydro is from thermal generating stations in southern Manitoba. Selkirk Generating Station is fueled by natural gas, while Brandon Generating Station contains two units fueled by natural gas and one fueled by . Generation outlet transmission facilities for Selkirk and Brandon consist of 13.8 kV transmission, stepped up to 115 kV.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 57 High Voltage DC (HVDC) Transmission Facilities The tremendous hydroelectric potential of the Nelson River in northern Manitoba has been appreciated by power planners since the turn of the last century. It was not until the 1960s, however, when the high voltage direct current (HVDC) technology became available for the long-distance transmission of electricity, that it became feasible to develop the Nelson. Manitoba Hydro has since become world renowned for its research and development in HVDC transmission. DC is used for long distance transmission because it offers certain advantages over AC. Although DC transmission requires converter stations at either ends, per length cost of the associated transmission line (construction and energy losses) are considerably lower.

58 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System Manitoba Hydro’s Generating Stations and Transmission System

Manitoba Hydro's generation outlet, HVDC, network, and above 66 kV transmission facilities. These lines and facilities form the backbone of the Corporation’s provincial electrical system.

Missi Falls

Henday Laurie River #2 Limestone Long Spruce Kettle Laurie River #1 Radisson Kelsey Shamattawa Notigi

Wuskwatim

Herblet Lake

Jenpeg

Legend Grand Rapids hydro generating Poplar River thermal generating diesel generating converter stations control structures diversion channels points of interchange hvdc transmission 500 kV transmission 230 kV transmission 138 kV transmission 115 kV transmission 66 kV distribution Pine Falls Great Falls wind generation McAr thur Pointe du Bois Selkirk Slave Falls Seven Sisters Brandon Dorse y

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 59 Bipoles 1 & 2

- + + - Pole I Pole 4 Pole 2 Pole 3

Manitoba Hydro’s HVDC transmission facilities consist of two bipolar transmission systems called Bipole I and Bipole II. The term “bipole” refers to a positive (+) pole and a negative (-) pole. Each pole consists of two conductors, 4 cm in diameter, that are supported by steel transmission towers. Bipole I is rated to transmit 1854 MW of electricity at a voltage of ±463.5 kV. Bipole II is rated at 2000 MW at ±500 kV. Manitoba Hydro’s two bipolar transmission lines consist of steel towers that follow a 900 km route from Gillam southward through the Interlake region. The southern terminus of both transmission lines is Dorsey Converter Station at Rosser, northwest of Winnipeg. Bipole I has its northern terminus at Radisson Converter Station near Gillam; Bipole II extends another 42 km northeast to the Henday Converter Station. The DC power is converted back to AC power at Dorsey for transmission via Manitoba Hydro’s southern AC network. This network feeds Manitoba’s major load centres as well as most of the interconnection transmission facilities that supply neighbouring provinces and the U.S.

Interconnection Transmission Facilities Manitoba Hydro’s interconnection transmission facilities allow for the economic exchange of electricity between neighbouring electrical systems. Manitoba Hydro’s primarily hydraulic generation system usually produces surplus energy. Interconnection transmission facilities make it possible to export power surplus to Manitoba load. Interconnection transmission facilities also allow Manitoba Hydro to import power during periods of drought and supply shortages in Manitoba, thereby strengthening the provincial electric system and lowering the required investment in generation facilities. US Connections The Manitoba electric system is connected to the United States electric system via three 230 kV transmission lines and one 500 kV transmission line; namely: • Letellier to Drayton, ND 230 kV line (62 km), • Richer to Moranville, MN 230 kV line (124 km), • Glenboro to Rugby, ND 230 kV line (190 km), • Dorsey to Forbes, MN 500 kV line (537 km)

60 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System The maximum design power transfer capability from Manitoba to the U.S. is 2100 MW, excluding a Transmission Reliability Margin (TRM) of 75 MW. The maximum design power transfer capability from the U.S. to Manitoba is 700 MW. The maximum flow in the southern direction is considerably higher than the northern direction. Critical contingency used in establishing the transfer level is the loss of the Dorsey to Forbes 500 kV line. For the loss of the line when exporting, the Manitoba Hydro HVDC system power is rapidly reduced by a special protection system to prevent cascade tripping of the remaining 230 kV lines. This feature allows the export capability to be much higher than the import capability, where this feature is not available. Saskatchewan Connections The Manitoba electric system is connected to the Saskatchewan electric system via three 230 kV interconnection transmission lines and two 115 kV interconnection transmission lines, namely: • Reston to Boundary Dam, SK 230 kV line (169 km), • Roblin South to Yorkton, SK 230 kV line (80 km) • Ralls Island to E.B. Campbell, SK 230 kV line (169 km) • Border to Island Falls, SK 115 kV lines (61 km) The maximum design power transfer level between Manitoba and Saskatchewan is 105 MW, excluding a TRM of 75 MW. Ontario Connections Manitoba’s electric system is interconnected to Ontario’s via two phase-shifted 230 kV transmission lines and one non-synchronous 115 kV transmission line. The 230 kV interconnections join the Whiteshell and Kenora (129 km) and have a design power transfer level from Manitoba to Ontario of 200 MW, excluding a TRM of 25 MW. The phase-shifting transformers have a ±180-degree control range for optimum control of power transfer between Manitoba and Ontario. The 115 kV connection, 141 km long, join Seven Sisters and Kenora. This line can be used only to send up to 75 MW of power to Ontario by connecting Seven Sisters Falls generating units to the line. Normally, it is operated open at the border. The Manitoba Hydro portion is connected to the 115 kV system and serves Manitoba loads at Brereton and Star Lake.

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 61 SASKATCHEWAN

Gillam

Flin Flon Manitoba Hydro's 12 interconnection Island Falls transmission lines, which connect our system with Ontario, Saskatchewan, The Pas and the United States. These “tie” lines, E.B. Campbell like mammoth extension cords, provide access to export markets for selling surplus electricity. They also provide a means of receiving backup power for the province during droughts, emergencies, ONTARIO and periods of high demand or economic Yorkton opportunities. Dauphin

Brandon Winnipeg Boundary Dam Kenora

U.S.A. Duluth Rugby Grand Forks Minneapolis

Network Transmission Facilities A bulk AC transmission network of power lines extends across the province, operating at 115 kV, 138 kV and 230 kV. 115 kV: Manitoba Hydro operates 2,900 km of 115 kV transmission lines, most of them in the southern part of the province. The lines feed distribution facilities, as well as some major loads, including Winnipeg, Flin Flon (in north-west Manitoba), Portage la Prairie (in south-central Manitoba), Morden (in south-central Manitoba) and communities in south-east Manitoba. 138 kV: Nearly 1400 km of 138 kV transmission lines serve the province’s small northern communities and feed Manitoba Hydro’s HVDC transmission facilities. The 138 kV network branches out from Kelsey Generating Station on the Nelson River and stretches north to Churchill South Station on the shore of , west to station near the Saskatchewan-Manitoba border, and east to Wasagamack station near the Manitoba-Ontario border. 230 kV: Most of Manitoba Hydro’s electric transmission capacity is provided by 5,000 km of 230 kV transmission system, a relatively new network. Major 230 kV transmission lines are supplied from Dorsey Converter Station. From Dorsey, eight 230 kV transmission lines transmit power to Rosser, Ridgeway, La Verendrye and St. Vital stations in Winnipeg. Four other 230 kV transmission lines transmit power from Dorsey to Cornwallis station in Brandon, St. Leon station in southern Manitoba and Ashern station in the Interlake area. At these stations, power is either stepped down from 230 kV to 115 kV or 66 kV or further transmitted at 230 kV.

62 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System Appendix 2 — Glossary

AC ...... Alternating Current Bipole...... Two conductor system BP I...... Bipole One BP II...... Bipole Two BP III...... Bipole Three CEC...... Clean Environment Commission CEF...... Capital Expenditure Forecast CLF...... Corporate Load Forecast CT...... Current Transformer DC...... Direct Current DM...... Demand Side Management ∆EUE...... Incremental Expected Unreserved Energy EIS...... Environmental Impact Statement EUE...... Expected Unreserved Energy GNTL...... Great Northern Transmission Line GW.h...... Gega Watt hours HBM&S...... Hudson' Bay Mining & Smelting HVDC...... High Voltage Direct Current INAC...... Indigenous & Northern Affairs Canada IOA...... Interconnection and Operating Agreement ISD...... In Service Date kA...... kilo Ampere kV...... kilo Volt LiDar...... Light Detection and Ranging LIES...... Load Interconnection Evaluation Study LIFS...... Load Interconnection Facility Study LOLE...... Loss of Load Expectation LP...... Limited Partnership MH...... Manitoba Hydro MHEB...... Manitoba Hydro Electric Board

LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 63 MISO...... Midcontinent Independent System Operator MMTP...... Manitoba Minnesota Transmission Project MN...... Minnesota MP...... Minnesota Power MRO...... Midwest Reliability Organization MVA...... Mega Volt Ampere Mvar ...... Mega var MW...... Mega Watt ND...... North Dakota NERC...... North American Electric Reliability Corporation OAIT...... Open Access Interconnection Tariff OASIS...... Open Access Same Time Information System OATT...... Open Access Transmission Tariff PMU...... Phasor Measurement Unit POI...... Points of Interconnection PST...... Phase Shifting Transformer Sask...... Saskatchewan SC...... Synchronous Condenser SK...... Saskatchewan SP...... Saskatchewan Power Sask Power...... Saskatchewan Power SUVC...... System Under Voltage Controller SVC...... Static Var Compensator TCPL...... Trans Canada Pipe Lines TRM...... Transmission Reliability Margin TSIR...... Transmission System Interconnection Requirements U.S...... United States WPS...... Wisconsin Public Service

64 LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System LONG-TERM DEVELOPMENT PLAN—2016 for Manitoba Hydro's Electrical Transmission System 65 For More Information

Please contact: Manager, System Planning Department 204.360.3113

Manitoba Hydro 820 Taylor Ave. Winnipeg, Manitoba, Canada R3C 0J1

April 2017 Printed in Canada