Nova Scotia Utility and Review Board

IN THE MATTER OF The Public Utilities Act, R.S.N.S. 1989, c.380, as amended

Nova Scotia Power 10-Year System Outlook

2018 Report

REVISED

Date Revised: July 12, 2018

1 TABLE OF CONTENTS 2 3 1.0 INTRODUCTION ...... 5 4 2.0 LOAD FORECAST ...... 7 5 3.0 GENERATION RESOURCES ...... 10 6 3.1 Existing Generation Resources ...... 10 7 3.1.1 Maximum Unit Capacity Rating Adjustments ...... 12 8 3.2 Changes in Capacity...... 12 9 3.2.1 Burnside Combustion Turbine Unit #4 ...... 13 10 3.2.2 Mersey Hydro ...... 13 11 3.2.3 Firm Capacity of Distributed Generation ...... 14 12 3.3 Unit Utilization & Investment Strategy ...... 14 13 3.3.1 Evolution of the Energy Mix In Nova Scotia ...... 15 14 3.3.2 Projections of Unit Utilization ...... 16 15 3.3.3 Projections of Unit Sustaining Investment ...... 18 16 3.3.4 Steam Fleet Retirement Outlook ...... 25 17 4.0 NEW SUPPLY SIDE FACILITIES ...... 27 18 4.1 Potential New Facilities ...... 27 19 5.0 Queued system impact studies ...... 28 20 5.1 OATT Transmission Service Queue ...... 29 21 6.0 ENVIRONMENTAL AND EMISSIONS REGULATORY REQUIREMENTS ...... 30 22 6.1 Renewable Electricity Requirements ...... 30 23 6.2 Environmental Regulatory Requirements ...... 33 24 6.3 Upcoming Policy Changes ...... 37 25 7.0 RESOURCE ADEQUACY ...... 39 26 7.1 Operating Reserve Criteria ...... 39 27 7.2 Planning Reserve Criteria ...... 40 28 7.3 Capacity Contribution of Renewable Resources in Nova Scotia ...... 41 29 7.3.1 Wind Capacity Contribution ...... 41 30 7.3.2 Storage Capacity Contribution ...... 44 31 7.4 Load and Resources Review ...... 45 32 8.0 TRANSMISSION PLANNING ...... 50

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1 8.1 System Description ...... 50 2 8.2 Transmission Design Criteria ...... 51 3 8.2.1 Bulk Power System (BPS) ...... 52 4 8.2.2 Bulk Electric System (BES) ...... 52 5 8.2.3 Special Protection Systems (SPS) ...... 53 6 8.2.4 NPCC A-10 Standard Update ...... 53 7 8.3 Transmission Life Extension ...... 55 8 8.4 Transmission Project Approval ...... 56 9 9.0 REGIONAL DEVELOPMENT ...... 57 10 9.1 Maritime Link ...... 57 11 9.2 Nova Scotia – New Brunswick Intertie Overview ...... 58 12 9.3 Co-operative Dispatch...... 61 13 10.0 TRANSMISSION DEVELOPMENT 2017 TO 2026 ...... 62 14 10.1 Transmission Development Plans ...... 62 15 10.2 Bulk Electricity System ...... 64 16 10.3 Western Valley Transmission System – Phase II Study ...... 66 17 11.0 CONCLUSION ...... 69 18

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1 TABLE OF FIGURES 2 3 Figure 1: Net System Requirement with Future DSM Program Effects ...... 7 4 Figure 2: Coincident Peak Demand with Future DSM Program Effects ...... 9 5 Figure 3: 2018 Firm Generating Capability for NS Power and IPPs ...... 11 6 Figure 4: Firm Capacity Changes & DSM ...... 13 7 Figure 5: 2005, 2017 Actual, 2021 Forecasted Energy Mix ...... 15 8 Figure 6: Peak System Demand Trend ...... 16 9 Figure 7: NS Power Steam Fleet Unit Utilization Forecast ...... 18 10 Figure 8: Utilization Factor ...... 19 11 Figure 9: Unit Utilization Factors ...... 22 12 Figure 10: Forecasted Annual Investment (in 2018$) by Unit ...... 23 13 Figure 11: Forecasted Annual Investment (in 2018$) by Asset Class ...... 24 14 Figure 12: Combined Transmission & Distribution Advanced Stage Interconnection Queue of June 29, 15 2018 ...... 28 16 Figure 13: Generation Projects Currently in the Combined T/D Advanced Stage Interconnection Request 17 Queue ...... 29 18 Figure 14: Requests in the OATT Transmission Queue ...... 29 19 Figure 15: RES 2019 and 2020 Compliance Forecast (Full Year Maritime Link) ...... 31 20 Figure 16: RES 2019 and 2020 Compliance Forecast (Part Year Maritime Link) ...... 33

21 Figure 17: Compliance CO2 Emission Caps ...... 34

22 Figure 18: Emissions Multi-Year Caps (SO2, NOX) ...... 35

23 Figure 19: Emissions Annual Maximums (SO2, NOX) ...... 35

24 Figure 20: Individual Unit Limits (SO2) ...... 35 25 Figure 21: Mercury Emissions Caps ...... 36 26 Figure 22: NS Power 10 Year Load and Resources Outlook ...... 47 27 Figure 23: Firm Capacity and Peak Demand Analysis ...... 48 28 Figure 24: 18 Month Load and Capacity Assessment ...... 49 29 Figure 25: NS Power Major Facilities in Service 2018 ...... 50 30 Figure 26: Conditions Determining Limits ...... 59 31 32 LIST OF APPENDICES 33 Appendix A: 2014 IRP Action Plan 34 Appendix B: 2017 NRIS Wind Study Report 062-2017TSMG-R0 35

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1 1.0 INTRODUCTION 2 3 In accordance with the 3.4.2.11 Market Rule requirements this report provides NS 4 Power’s 10-Year System Outlook on behalf of the NS Power System Operator (NSPSO) 5 for 2018. 6 7 The 2018 10-Year System Outlook report contains the following information: 8 9 • A summary of the NS Power load forecast and update on the Demand Side 10 Management (DSM) forecast in Section 2. 11 12 • A summary of generation expansion anticipated for facilities owned by NS Power 13 and others in Sections 3 through 5, including an updated Unit Utilization and 14 Investment Strategy in Section 3.3. 15 16 • A summary of environmental and emissions regulatory requirements, as well as 17 forecast compliance in Section 6. This section also includes projections of the 18 level of renewable energy available. 19

20 • A Resource Adequacy Assessment in Section 7, including an update regarding the 21 annual wind capacity value study in Section 8 and evaluation of the contribution 22 of Energy Resource Interconnection Service connected resources in Appendix B. 23 24 • A discussion of transmission planning considerations in Section 8. 25

1 The NSPSO system plan will address: (a) transmission investment planning; (b) DSM programs operated by EfficiencyOne or others; (c) NS Power generation planning for existing Facilities, including retirements as well as investments in upgrades, refurbishment or life extension; (d) new Generating Facilities committed in accordance with previous approved NSPSO system plans; (e) new Generating Facilities planned by Market Participants or Connection Applicants other than NS Power; and (f) requirements for additional DSM programs and / or generating capability (for energy or ancillary services).

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1 • Identification of transmission related capital projects currently in the 2 Transmission Development Plan in Sections 9 and 10. 3 4 • IRP Action Plan Update Table in Appendix A.

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1 2.0 LOAD FORECAST 2 3 The NS Power load forecast provides an outlook on the energy and peak demand 4 requirements of in-province customers. The load forecast forms the basis for fuel supply 5 planning, investment planning, and overall operating activities of NS Power. The figures 6 presented in this report are the same as those filed with the UARB in the 2018 Load 7 Forecast Report on April 30, 2018 and were developed using NS Power’s Statistically 8 Adjusted End-Use (SAE) model to forecast the residential and commercial rate classes. 9 The residential and commercial SAE models are combined with an econometric based 10 industrial forecast and customer specific forecasts for NS Power’s large customers to 11 develop an energy forecast for the province, also referred to as a Net System 12 Requirement (NSR). 13 14 Figure 1 shows historical and forecasted net system requirements (NSR) which includes 15 in-province energy sales plus system losses. Anticipated growth in energy sales is 16 expected to be offset by Demand Side Management (DSM) initiatives and energy 17 efficiency improvements outside of structured DSM programs. For the 2018 forecast, 18 distributed solar generation was also included in the forecast, further reducing future 19 energy sales growth. The result of these inputs is an average annual decline in NSR of 20 0.3 percent. 21 22 Figure 1: Net System Requirement with Future DSM Program Effects

NSR Growth Year (GWh) (%) 2008 12,539 -0.8% 2009 12,073 -3.7% 2010 12,158 0.7% 2011 11,907 -2.1% 2012 10,475 -12.0% 2013 11,194 6.9% 2014 11,037 -1.4% 2015 11,098 0.5% 2016 10,809 -2.6% 2017 10,873 0.6%

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NSR Growth Year (GWh) (%) 2018* 10,960 0.8% 2019* 11,000 0.4% 2020* 11,003 0.0% 2021* 10,916 -0.8% 2022* 10,881 -0.3% 2023* 10,835 -0.4% 2024* 10,802 -0.3% 2025* 10,740 -0.6% 2026* 10,705 -0.3% 2027* 10,670 -0.3% 2028* 10,659 -0.1% 1 *Forecasted value 2 3 NS Power also forecasts the peak hourly demand for future years. The total system peak 4 is defined as the highest single hourly average demand experienced in a year. It includes 5 both firm and interruptible loads. Due to the weather-sensitive load component in Nova 6 Scotia, the total system peak occurs in the period from December through February. 7 8 The peak demand forecast is developed using end-use energy forecasts combined with 9 peak-day weather conditions to generate monthly peak demand forecasts through an 10 estimated monthly peak demand regression model. The peak contribution from large 11 customer classes is calculated from historical coincident load factors for each of the rate 12 classes. After accounting for the effects of DSM savings, system peak is expected to 13 increase 0.2 percent on average annually over the forecast period, and is being driven by 14 increasing firm peak requirements. 15 16 Figure 2 shows the historical and forecast net system peak.

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1 Figure 2: Coincident Peak Demand with Future DSM Program Effects Interruptible Firm Contribution Contribution to Peak to Peak System Peak Growth Year (MW) (MW) (MW) (%) 2008 352 1,840 2,192 1.7% 2009 268 1,824 2,092 -4.5% 2010 295 1,820 2,114 1.0% 2011 265 1,903 2,168 2.5% 2012 141 1,740 1,882 -13.2% 2013 136 1,897 2,033 8.0% 2014 83 2,036 2,118 4.2% 2015 141 1,874 2,015 -4.9% 2016 98 2,013 2,111 4.8% 2017 67 1,951 2,018 -4.4% 2018* 154 1,985 2,139 6.0% 2019* 156 2,001 2,157 0.9% 2020* 158 2,015 2,172 0.7% 2021* 157 2,016 2,174 0.1% 2022* 157 2,021 2,178 0.2% 2023* 157 2,028 2,184 0.3% 2024* 156 2,034 2,191 0.3% 2025* 156 2,030 2,187 -0.2% 2026* 156 2,027 2,183 -0.2% 2027* 156 2,022 2,177 -0.3% 2028* 155 2,017 2,172 -0.2% 2 *Forecasted value

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1 3.0 GENERATION RESOURCES 2 3 3.1 Existing Generation Resources 4 5 Nova Scotia’s generation portfolio is composed of a mix of fuel and technology types 6 that includes coal, petroleum coke, light and heavy oil, natural gas, biomass, wind, tidal 7 and hydro. In addition, NS Power purchases energy from Independent Power Producers 8 (IPPs) located in the province and imports power across the NS Power/NB Power intertie 9 and the Maritime Link. Since the implementation of the Renewable Electricity Standard 10 (RES) discussed in Section 6.1, an increased percentage of total energy is produced by 11 variable renewable resources such as wind. However, due to their intermittent nature, 12 variable resources provide less firm capacity than conventional generation resources. 13 Therefore, the majority of the system requirement for firm capacity is met with NS 14 Power’s conventional units (e.g. coal, gas) while their energy output is being displaced by 15 renewable resources when they are producing energy. This is discussed further in Section 16 3.3. 17 18 Figure 3 lists NS Power’s and IPPs’ verified and forecasted firm generating capability 19 for generating stations/systems along with their fuel types. It has been updated to include 20 changes and additions to the IPPs and renewables effective up to the filing date of this 21 report.

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1 Figure 3: 2018 Firm Generating Capability for NS Power and IPPs Winter Net Facility Fuel Type Capacity (MW) Avon Hydro 6.8 Black River Hydro 22.5 Lequille System Hydro 24.2 Bear River System Hydro 37.4 Roseway2 Hydro 0.0 Tusket Hydro 2.4 Mersey System Hydro 42.5 St. Margaret’s Bay Hydro 10.8 Sheet Harbour Hydro 10.8 Dickie Brook Hydro 3.8 Wreck Cove Hydro 212.0 Annapolis Tidal3 Hydro 3.5 Fall River Hydro 0.5 Total Hydro 377.1

Tufts Cove 1, 2 & 3 Heavy Fuel Oil/Natural Gas 318 Trenton Coal/Pet Coke/Heavy Fuel Oil 304 Point Tupper Coal/Pet Coke/Heavy Fuel Oil 150 Lingan Coal/Pet Coke/Heavy Fuel Oil 612 Coal/Pet Coke & Limestone Sorbent Point Aconi 168 (CFB) Total Steam 1552

Tufts Cove Units 4,5 & 6 Natural Gas 144 Total Combined Cycle 144

Burnside Units 1, 2 & 34 Light Fuel Oil 99 Tusket Light Fuel Oil 33 Victoria Junction Light Fuel Oil 66

2This asset is not used and useful in accordance with recent direction of the UARB. NS Power is assessing the requirements for decommissioning of these assets. 3 The firm capacity of the Annapolis Tidal unit is based on average performance level at peak time. Nameplate capacity (achieved at low tide) is 19.5 MW. 4 Burnside Unit #4 (winter capacity of 33 MW) is presently unavailable but is planned to be returned to service by the end of Q2 2018 – please refer to Section 4.2.1.

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Winter Net Facility Fuel Type Capacity (MW) Total Combustion Turbine 198 Pre-2001 Renewables Independent Power Producers (IPPs) 25.8 Post-2001Renewables (firm)5 IPPs 64.0 NS Power wind (firm)5 Wind 13.7 Community-Feed-in-Tariff IPPs 30.5 (firm)5 Total IPPs & Renewables 133.9 Total Capacity 2405

1 2 3.1.1 Maximum Unit Capacity Rating Adjustments 3 4 As a member of the Maritimes Area of the Northeast Power Coordinating Council 5 (NPCC), NS Power meets the requirement for generator capacity verification as outlined 6 in NPCC Regional Reliability Reference Directory #9, Generator Real Power 7 Verification.6 These Criteria are reviewed and adjusted periodically by NPCC and 8 subject to approval by the UARB. 9 10 The Net Operating Capacity of the thermal units and large hydro units covered by the 11 NPCC criteria do not require adjustments at this point in time. NS Power will continue to 12 refresh unit maximum capacities in the 10-Year System Outlook each year as operational 13 conditions change. 14 15 3.2 Changes in Capacity 16 17 Figure 4 provides the firm Supply and DSM capacity changes in accordance with the 18 assumption set developed for the 2017-2019 Base Cost of Fuel forecast and the 2018 19 Load Forecast.

5 Energy Resource Interconnection Service (ERIS) and Network Resource Interconnection Service (NRIS) wind projects are assumed to have a firm capacity contribution of 17% as detailed in Section 8.3.1. 6 https://www.npcc.org/Standards/Directories/Forms/Public%20List.aspx

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1 Figure 4: Firm Capacity Changes & DSM New Resources 2018-2027 Net MW DSM firm peak reduction7 179 Total Demand Side MW Change 179 Projected Over Planning Period

Community and Tidal Feed-in 18 Tariffs (Firm capacity) Biomass8 43 Maritime Link Import - Base Block 153 Burnside #4 (return to service) 33 Assumed Unit Retirements/Lay-ups9 -153 Total Firm Supply MW Change 94 Projected Over Planning Period 2 3 3.2.1 Burnside Combustion Turbine Unit #4 4 5 Burnside Unit #4 is a 33 MW combustion turbine located in the Burnside Industrial Park 6 in Dartmouth that provides black start capability, 10-minute reserve, dynamic reactive 7 reserve, reactive power support and firm capacity to the NS Power electrical system. 8 Unit #4 was originally commissioned in 1972 but has been out of service since 2008. 9 10 NS Power is currently forecasting an expected full return to service for Burnside Unit #4 11 by the end of Q2, 2018. 12 13 3.2.2 Mersey Hydro 14 15 NS Power is in the final stages of assessing options to address current concerns on the 16 Mersey Hydro System. Degradation of the powerhouse and water control structures after

7 DSM Firm Peak Reduction is calculated from the 2018 NS Power 10 Year Energy and Demand Forecast, M08670, Exhibit N-1, Table A-3 and A-4, April 30, 2018. 8 The transmission upgrades being completed for the Maritime Link will allow 45MW of the PH Biomass unit to be counted as firm; however, tests for operating capacity completed have resulted in 43MW of available firm capacity able to be credited. 9 Retirement of Lingan 2 unit once Maritime Link Base Block provides firm capacity service.

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1 nearly a century of service for some hydro assets has necessitated the need for significant 2 redevelopment work. The Mersey Hydro System is an important part of NS Power’s 3 hydro assets and is responsible for approximately 25 percent of annual hydroelectric 4 production. The Company is preparing the Mersey Redevelopment Project Application 5 for filing with the UARB. 6 7 3.2.3 Firm Capacity of Distributed Generation 8 9 A portion of distributed generation has been denoted as firm – these sources are listed in 10 Figure 3 and Figure 4 above. Ongoing evaluation of the firm capacity contribution of 11 these facilities continues in order to further understand the impact and reliability of this 12 designation. Existing and future solar installations are not included as firm generating 13 capacity as they will not contribute generation during system peak, which occurs in 14 winter after sunset. 15 16 3.3 Unit Utilization & Investment Strategy 17 18 The following sub-sections provide an updated Unit Utilization and Investment Strategy 19 (UUIS). The Company forecasts 10 years of utilization and investment projections in this 20 report. These projections are based on NS Power’s currently available assumptions; 21 forecasts will continuously change as assumptions are adjusted based on regulatory or 22 policy changes, operational experience and market information. The upcoming policy 23 changes discussed in Section 6.3, such as the implementation of a Nova Scotia Cap and 24 Trade program and an Equivalency Agreement regarding the federal Coal-Fired 25 Generation of Electricity Regulations, could potentially trigger a significant shift in the 26 utilization forecast. 27 28 This UUIS is a product of generation planning and engineering integrating the latest in 29 Asset Management methodology and Generation Planning techniques in the service of a 30 complex generation operation. It provides an outlook for how NS Power will operate and

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1 invest in generation assets recognizing the trend towards lower utilization along with 2 demands for flexible operation arising from renewables integration, and will continue to 3 be updated annually in the 10-Year System Outlook Report. 4 5 3.3.1 Evolution of the Energy Mix In Nova Scotia

6 NS Power’s energy production mix has undergone significant changes over the last 7 decade. Since the implementation of the Renewable Electricity Standard (RES), an 8 increased percentage of energy sales is produced by variable renewable resources such as 9 wind. However, due to their intermittent nature, variable resources provide less firm 10 capacity than conventional generation resources. Therefore, the majority of the system 11 requirement for firm capacity and other ancillary services is met with NS Power’s 12 conventional units (e.g. coal, gas) as shown in Sections 3.1 and 3.2, while the energy 13 output of conventional units is being displaced by renewable resources. 14 Figure 5 below illustrates this change with the actual energy mix from 2005 and 2017 15 and the forecasted energy mix for 2021. 16 17 Figure 510: 2005, 2017 Actual, 2021 Forecasted Energy Mix

10 Consistent with the provisions of the Renewable Electricity Regulations, in 2021 the category of Imports includes ML Surplus energy while the category of Hydro includes ML NS Base Block and Supplemental Energy from the Muskrat Falls hydro project.

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1 As illustrated in 2 Figure 6 below, NS Power’s firm peak demand has been increasing at a trend of 3 approximately one percent per year. While energy is increasingly being produced by new 4 renewable sources, the capacity required to serve system demand will continue to be 5 served by dispatchable conventional resources together with imports. The steam units 6 also provide other critical services to the system such as load-following. 7 8 Figure 6: Peak System Demand Trend

9 10 11 3.3.2 Projections of Unit Utilization 12 13 NS Power prepares a 10 year forecast of projected unit utilization parameters annually in 14 in this report using the Plexos modeling tool and the current assumptions regarding fuel 15 and market prices, load forecast, system constraints, and generating parameters; these 16 assumptions change year-over-year and the Company adjusts its utilization strategy 17 accordingly. As the Plexos model optimizes dispatch against this set of input 18 assumptions, the forecasted utilization of the generating units can be expected to vary as 19 inputs such as fuel pricing shift. 20

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1 Figure 7 below provides the current forecasted unit utilization of NS Power’s steam fleet. 2 The Company notes that the outcome of the carbon policy changes discussed in Section 3 6.3 could alter the near term of this utilization forecast, particularly if carbon emission 4 limits change due to a Cap and Trade program. As policy outcomes become clear the 5 forecast model will be updated and the updated results will be provided in future 10 Year 6 System Outlook reports.

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1 Figure 7: NS Power Steam Fleet Unit Utilization Forecast

2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Lingan 1 Capacity Factor (%) 32 24 30 30 26 29 25 27 32 28 Unit Cycles (Ranges) 10 - 25 < 10 10 - 25 10 - 25 10 - 25 10 - 25 10 - 25 10 - 25 10 - 25 10 - 25 Service Hours 4048 2851 4147 3914 3421 4029 3622 3722 4451 4065 Lingan 2 Capacity Factor (%) 30 63 0 0 0 0 0 0 0 0 Unit Cycles (Ranges) < 10 < 10 0 0 0 0 0 0 0 0 Service Hours 3533 4362 0 0 0 0 0 0 0 0 Lingan 3 Capacity Factor (%) 48 37 47 45 46 41 37 28 29 39 Unit Cycles (Ranges) 25 - 50 25 - 50 25 - 50 10 - 25 10 - 25 25 - 50 25 - 50 10 - 25 10 - 25 25 - 50 Service Hours 6320 5089 6976 6813 7099 6285 5747 3922 4223 5682 Lingan 4 Capacity Factor (%) 42 27 37 33 34 34 32 31 33 25 Unit Cycles (Ranges) 10 - 25 10 - 25 10 - 25 10 - 25 10 - 25 25 - 50 10 - 25 10 - 25 10 - 25 10 - 25 Service Hours 5513 3565 5252 4655 4705 4736 4869 4738 4793 3381 Point Aconi Capacity Factor (%) 83 83 73 81 81 81 70 76 71 73 Unit Cycles (Ranges) < 10 < 10 < 10 < 10 < 10 < 10 < 10 < 10 < 10 < 10 Service Hours 7634 7731 6869 7666 7666 7690 6848 7437 6906 7144 Point Tupper Capacity Factor (%) 66 35 27 27 30 29 18 29 26 28 Unit Cycles (Ranges) < 10 10 - 25 10 - 25 10 - 25 10 - 25 25 - 50 10 - 25 10 - 25 10 - 25 10 - 25 Service Hours 6424 4494 3556 3504 3986 4284 2588 3626 3220 3739 Trenton 5 Capacity Factor (%) 53 29 34 41 47 43 33 19 29 30 Unit Cycles (Ranges) < 10 < 10 < 10 10 - 25 < 10 10 - 25 10 - 25 10 - 25 10 - 25 10 - 25 Service Hours 5580 4071 4971 6189 6970 6634 5152 2852 4537 4613 Trenton 6 Capacity Factor (%) 60 39 30 23 18 19 24 39 28 27 Unit Cycles (Ranges) 10 - 25 < 10 < 10 < 10 < 10 < 10 < 10 10 - 25 10 - 25 10 - 25 Service Hours 6177 5700 4509 3214 2484 2750 3898 6039 4411 4360 Tufts Cove 1 Capacity Factor (%) 28 50 15 12 11 16 22 18 21 19 Unit Cycles (Ranges) 10 - 25 10 - 25 25 - 50 10 - 25 10 - 25 10 - 25 10 - 25 10 - 25 25 - 50 25 - 50 Service Hours 2668 4833 1717 1413 1267 1787 2338 1787 2195 1962 Tufts Cove 2 Capacity Factor (%) 24 41 10 9 9 10 16 14 13 14 Unit Cycles (Ranges) 10 - 25 10 - 25 10 - 25 25 - 50 10 - 25 10 - 25 10 - 25 10 - 25 10 - 25 10 - 25 Service Hours 2662 4603 1400 1318 1298 1363 1764 1558 1413 1697 Tufts Cove 3 Capacity Factor (%) 45 67 33 32 25 25 48 31 30 27 Unit Cycles (Ranges) 10 - 25 25 - 50 50 - 100 50 - 100 25 - 50 25 - 50 25 - 50 25 - 50 25 - 50 25 - 50 Service Hours 4760 6850 4399 4316 3177 3111 5595 3536 3378 3157 Tufts Cove 4 Capacity Factor (%) 64 71 51 52 54 52 61 60 57 58 Unit Cycles (Ranges) 50 - 100 50 - 100 > 100 > 100 > 100 > 100 50 - 100 50 - 100 > 100 50 - 100 Service Hours 5995 6851 5371 5485 5512 5322 6170 5709 5533 5522 Tufts Cove 5 Capacity Factor (%) 62 67 52 52 51 50 59 62 58 59 Unit Cycles (Ranges) 50 - 100 25 - 50 > 100 > 100 > 100 > 100 50 - 100 50 - 100 50 - 100 50 - 100 Service Hours 5802 6450 5456 5436 5217 5117 5963 5940 5544 5633 Tufts Cove 6 Capacity Factor (%) 43 49 28 31 32 29 39 37 36 35 Unit Cycles (Ranges) 25 - 50 25 - 50 50 - 100 50 - 100 > 100 50 - 100 50 - 100 50 - 100 50 - 100 50 - 100 2 Service Hours 5178 5729 4180 4612 4377 4092 4965 5026 4714 4581 3 4 3.3.3 Projections of Unit Sustaining Investment 5 6 Unit utilization and reliability objectives have long been the drivers for generator 7 investment planning. Traditionally, in a predominantly base loaded generation fleet, it 8 was sufficient to consider capacity factor as the source for utilization forecasts for any

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1 given unit. This is no longer the case; integration of variable renewable resources on the 2 NS Power system has imposed revised operating and flexibility demands to integrate 3 wind generation on previously base-loaded steam units. Therefore, it is necessary to also 4 consider the effects of unit starts, operating hours, flexible operating modes (e.g. ramping 5 and two-shifting) and the latest understanding of asset health along with the forecasted 6 unit capacity factors. 7 8 NS Power has created the concept of utilization factor (UF) for the purpose of 9 communicating the operation strategy for a particular generator. The essence of this 10 approach is to better express the demands placed upon NS Power’s generating units given 11 the planned utilization. The UF for each unit is evaluated by considering the forecasted 12 capacity factor, annual operating hours, unit starts, expected two-shifting, and a 13 qualitative evaluation of asset health. By accounting for these operational capabilities, 14 the value brought to the power system by these units is more clearly reflected. Refer to 15 Figure 8 below. 16 17 Figure 8: Utilization Factor

18 19 The UF parameters are assessed to more completely describe the operational outlook for 20 the steam fleet and direct investment planning, and include: 21 22 • Capacity factor reflects the energy production contribution of a generating unit 23 and is a necessary constituent of unit utilization. It is a part of the utilization 24 factor determination rather than the only consideration as it would have been in 25 the past. 26 27 • Service hours have become a more important factor to consider with increased 28 penetration of variable-intermittent generation, as units are frequently running

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1 below their full capacity while providing load following and other essential 2 reliability services for wind integration. For example, if a unit operates at 50 3 percent of its capacity for every hour of the year, then the capacity factor would 4 be 50 percent. In a traditional model, this would suggest a reduced level of 5 investment required, commensurate with decreased capacity factor. However, 6 many failure mechanisms are a function of operating hours (e.g. turbines, some 7 boiler failure mechanisms, and high energy piping) and the number of service 8 hours (which in this example is every hour of the year) is not reflected by the 9 unit’s capacity factor. Additionally, some failure mechanisms can actually be 10 exacerbated by reducing load operation (e.g. valves, some pumps, throttling 11 devices). 12

13 • Unit cycles (downward and upward ramping of generating units) can stress many 14 components (e.g. turbines, motors, breakers, and fatigue in high energy piping 15 systems) and accelerate failure mechanisms; therefore, these must also be 16 considered to properly estimate the service interval and appropriate maintenance 17 strategies. 18

19 • Asset health is a critical operating parameter to keep at the forefront of all asset 20 management decisions. For example, asset health may determine if a unit is 21 capable of two-shifting (unit shut down during low load overnight and restart to 22 serve load the next day). Although it does not necessarily play directly into the 23 UF function, it can be a dominant determinant in allowing a mode of operation; 24 therefore, it influences the UF function. 25 26 While the UF rating provides a directional understanding of the future use of each 27 generating unit, the practice of applying it has another layer of sophistication as system 28 parameters change. NS Power utilizes the Plexos dispatch optimization model to derive 29 utilization forecasts and qualitatively assess the UF of each unit by evaluating the 30 components described above.

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1 Figure 10 and Figure 11 below provide the projected sustaining investments based on 2 the anticipated utilization forecast in Section 3.3.2. Estimates of unit sustaining 3 investment are forecast by applying the UF, related life consumption and known failure 4 mechanisms. NS Power does not include unplanned failures in sustaining capital 5 estimates. These estimates are evaluated at the asset class level; some asset class 6 projections are prorated by the UF and others have additional overriding factors. For 7 example, the use of many instrument and electrical systems is a function of calendar 8 years, as they operate whether a unit is running or not. Investments for coal and ash 9 systems are a direct function of capacity factor, as they typically have material volume 10 based failure mechanisms. In contrast, the UF is directly applicable to the investment 11 associated with turbines, boilers and high energy piping. Major assets are regularly re- 12 assessed in terms of their condition and intended service as NS Power’s operational data, 13 utilization plan, asset health information, and forecasts are updated. 14 15 The overarching investment philosophy is to cost effectively maintain unit reliability 16 while minimizing undepreciated capital. Mitigating risks by using less intensive 17 investment strategies is a tactic executed throughout the thermal fleet. Major outage 18 intervals are extended where possible to reduce large investments in the thermal fleet. 19 20 Major changes in the asset management plan from the 2018 10-Year System Outlook 21 include: 22 23 • Increased cycling (output ramping or two shifting) of the thermal fleet can sustain 24 the unit utilization factors even as the capacity factors decline. For example, a 25 unit that is heavily cycled can require more sustaining investment than a base 26 loaded machine. Figure 9 shows the projected unit utilization factors. 27 28 • Lower forecasted utilization of Tuft’s Cove Unit 2 drives the major turbine 29 refurbishment interval out to 2028. 30

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1 • Higher utilization forecasts for Trenton Unit #5 advances the need for a major 2 outage into the 10-year planning window. 3 4 Figure 9: Unit Utilization Factors

Unit UF(2019-2023) UF (2024-2028 ) PH Biomass High High Lingan Unit 1 Low Low Lingan Unit 2 Low/Off Off Lingan Unit 3 High Med Lingan Unit 4 Med Med Pt. Aconi High High Pt. Tupper Med Med Trenton 5 High High Trenton 6 Med Med Tuft's Cove 1 Low Low Tuft's Cove 2 Low Low Tuft's Cove 3 Med Med Tuft's Cove 6 High High LM 6000 High High CT's Low Low 5

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1 Figure 10: Forecasted Annual Investment (in 2018$) by Unit

2 3 Note: Figure does not include escalation as it is used for asset planning.

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1 Figure 11: Forecasted Annual Investment (in 2018$) by Asset Class

2 3 Note: Figure does not include escalation as it is used for asset planning. Forecast investments are subject to change 4 arising from asset health and actual utilization. Changes in currency value can also have significant effect on actual 5 cost. 6 7 NS Power notes the large sustaining capital investment projection for the year 2028 for 8 Tufts Cove Unit #2. Consistent with Synapse’s recommendation #7 in its Generation 9 Utilization & Optimization study, to determine the capacity and unit commitment 10 requirements to assess possible Tufts Cove unit economic retirement, as part of the next 11 IRP, NS Power plans to assess replacement options for this unit as an alternative to the 12 sustaining capital investment.

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1 3.3.4 Steam Fleet Retirement Outlook

2 As stated in NS Power’s submission to the UARB dated June 7, 201811 in regard to 3 Synapse Energy Economic Inc.’s (Synapse) Generation Utilization and Optimization 4 report (M08059) filed on May 1, 2018: 5 6 Synapse’s results provide a direct answer to the Board’s question posed 7 through the approved objective in the Terms of Reference for this work; it 8 is cost‐effective for rate payers is the retention of the coal fleet through 9 2030, and possibly beyond. Synapse confirmed this interpretation of the 10 results at the Technical Conference on March 28, 2018. 11 12 NS Power understands this is not a final determination as to the long‐term 13 utilization of these generation units and recognizes that uncertainty 14 remains with respect to a major resource planning factor, the carbon 15 regime to be implemented in Nova Scotia over the next decade and 16 beyond. A long‐term view of the useful lives of these plants will not be 17 firmly established until this regime is established and understood. The 18 Company currently expects this will be resolved by the end of 2018, likely 19 enabling the undertaking of an Integrated Resource Planning (IRP) 20 exercise in 2019, subject to clarity surrounding federal and provincial 21 carbon policy.12 22 23 As set out in Section 6.3, the details of the amendments to the Reduction of Carbon 24 Dioxide Emissions from Coal-fired Generation of Electricity Regulations13 and a related 25 potential equivalency agreement are under discussion between the Province and the 26 Government of Canada, and NS Power is providing input to that process as required. The

11 M008059 NS Power comments on Synapse Final Report (May 1, 2018) June 7, 2018, 2018. 12 Ibid at page 4 of 8. 13 Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, SOR/2012/167, made under the Canadian Environmental Protection Act, 1999, SOR/2012/167, s.7.3

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1 potential outcomes of these discussions include a range of unit retention or retirement 2 possibilities. 3 4 NS Power will develop an updated retirement schedule as part of the next IRP following 5 the conclusions of these negotiations based on their outcome, the finalization of the 6 Federal Coal-fired Generation of Electricity Regulations, and the forecasted major 7 investment intervals for the units. In the interim, Lingan Unit 2 is planned for retirement 8 upon the commencement of the delivery of the Nova Scotia Block of energy and related 9 firm capacity from the Muskrat Falls, currently anticipated in 2020.

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1 4.0 NEW SUPPLY SIDE FACILITIES 2 3 4.1 Potential New Facilities 4 5 As of May 17, 2018, NS Power has four Active Transmission Connected Interconnection 6 Requests (70.1MW) and eight Active Distribution Connected Interconnection Requests 7 (17.3MW) at various stages of interconnection study. 8 9 Proponents of the transmission projects have requested Network Resource 10 Interconnection Service (NRIS) or Energy Resource Interconnection Service (ERIS). 11 Distribution projects do not receive an NRIS or ERIS designation. NRIS refers to a firm 12 transmission interconnection request with the potential requirement for transmission 13 reinforcement upon completion of the System Impact Study (SIS). ERIS refers to an 14 interconnection request for firm service only to the point where transmission 15 reinforcement would be required. Results of the interconnection studies will be 16 incorporated into future transmission plans.

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1 5.0 QUEUED SYSTEM IMPACT STUDIES 2 3 Figure 12 below provides the current combined Transmission and Distribution Advanced 4 Stage Interconnection Queue. 5 6 Figure 12: Combined Transmission & Distribution Advanced Stage Interconnection 7 Queue of June 29, 2018

Combined T/D Advanced Stage Interconnection Request Queue Publish Date: Wednesday, May 16, 2018 Request In-service Date date DD- MW DD- Queue MMM- Summ MW Interconnection MMM- Service Order IR# YY County er Winter Point Type YY Status Type 1-T 426 27-Jul-12 Richmond 45.0 45.0 47C Biomass 01-Jan-17 GIA Executed NRIS 29-Dec- 2-D 442 21-Dec-12 Hants 0.5 0.5 82V-423 Biogas 15 GIA Executed N/A 3-D 498 23-Apr-14 Antigonish 0.5 0.5 4C-441 Biogas 15-Jan-15 GIA Executed N/A 4-T 516 5-Dec-14 Cumberland 5.0 5.0 37N Tidal 01-Jul-16 GIA Executed NRIS 5-D 518 16-Dec-14 Halifax 2.0 2.0 139H-411 Biomass 1-Oct-16 GIA Executed N/A 6-T 540 28-Jul-16 Hants 14.1 14.1 17V Wind 01-Jan-18 GIA Executed NRIS 7-D 545 24-Jan-17 Halifax 1.3 1.3 82V-401 Battery 1-Dec-17 SIS Complete N/A FAC in 8-T 542 26-Sep-16 Cumberland 6.0 6.0 37N Tidal 01-Jan-19 Progress NRIS 31-Dec- 9-D 553 24-Feb-17 Digby 0.9 0.9 509V-301 Tidal 18 SIS Complete N/A 10-D 557 19-Apr-17 Halifax 5.6 5.6 CHP 01-Sep-18 SIS Complete N/A 11-D 565 26-Jan-18 Lunenburg 0.5 0.5 84W-301 Biogas 25-Feb-19 SIS in Progress N/A 12-D 548 31-Jan-17 Kings 6 6 36V-302 Tidal 01-Oct-17 SIS in Progress N/A 8 9 Active transmission and distribution requests not appearing in the Combined 10 Transmission & Distribution Advanced Stage Interconnection Request Queue are 11 considered to be at the initial queue stage, as they have not yet proceeded to the SIS stage 12 of the Generator Interconnection Procedures (GIP). Figure 13 indicates the location and 13 size of the generating facilities currently in the Combined T/D Advanced Stage 14 Interconnection Request Queue.

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1 Figure 13: Generation Projects Currently in the Combined T/D Advanced Stage 2 Interconnection Request Queue Nameplate Company/Location Capacity (MW) IR #426 NRIS Version of existing 64MW (IR 219, which was ERIS) Biomass N/A IR #516 Tidal in Cumberland County 5.0 IR #540 Wind in Hants County 14.1 IR #542 Tidal in Cumberland County 6.0 IR #545 Battery in Halifax 1.3 IR #557 CHP in Halifax 5.6 COMFIT Distribution Interconnection Request 10.4 Total 42.4 3 4 Port Hawkesbury Biomass, 63.8 MW gross / 45 MW net output, generating unit is 5 presently an ERIS classified resource which will be converted to NRIS following the 6 system upgrades associated with Transmission Service Request 400, which are expected 7 to be completed in 2018. 8 9 5.1 OATT Transmission Service Queue 10 11 There is presently one request in the OATT Transmission Queue, as shown in Figure 14. 12 13 Figure 14: Requests in the OATT Transmission Queue Number Project Date & Time Project Project Requested Project Status of Service Type Location In-Service size Request Date (MW)

4 TSR July 22, 2011 Point to NS-NB May 31, 330 Waiting for 400 Point 2018 transmission construction completion expected later this year. L6613 construction and reconfiguration of CB causeway

14

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1 6.0 ENVIRONMENTAL AND EMISSIONS REGULATORY REQUIREMENTS 2 3 6.1 Renewable Electricity Requirements 4 5 The Nova Scotia Renewable Electricity Standard (RES) includes a renewable energy 6 requirement for NS Power of 25 percent of energy sales in 2015, and 40 percent in 2020. 7 8 In addition to these requirements, Nova Scotia has a Community Feed-in-Tariff 9 (COMFIT) for projects which include community ownership that are connected to the 10 distribution system and Net Metering legislation for renewable projects.14 The current 11 Net Metering program was initiated in July 2011, and implementation of the COMFIT 12 program occurred in September 2011. 13 14 On April 8, 2016, the Province amended the Renewable Electricity Regulations to allow 15 NS Power to include COMFIT projects in its RES compliance planning. It also amended 16 the Regulations to remove the “must-run” requirement of the Port Hawkesbury biomass 17 generating facility.15 NS Power continues to have contractual obligations associated with 18 operation and maintenance of this biomass co-generation facility. 19 20 NS Power has complied with the renewable electricity requirement in all applicable 21 years. From 2015 through to 2017 the Company served 26.6 percent, 28 percent and 29 22 percent of sales, respectively, using qualifying renewable energy sources. NS Power’s 23 production tracking and forecast for the current year indicate that renewable electricity 24 compliance will also be achieved for the year 2018. 25

14 Effective December 18, 2015, the Electricity Act reduced the maximum nameplate capacity for Net Metering from 1,000 kW to 100 kW. Net metering applications submitted on or after December 18, 2015 are subject to the new 100 kW limit. The legislation also closed the COMFIT to new applications. 15 Renewable Electricity Regulations, made under Section 5 of the Electricity Act S.N.S. 2004, c. 25 O.I.C. 2010- 381 (effective October 12, 2010), N.S. Reg. 155/2010 as amended to O.I.C. 2018-133 (effective May 8, 2018), N.S. Reg. 83/2018s. 5 2A.

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1 The total annual RES-eligible energy from the Maritime Link will amount to 1.2 TWh, 2 which includes both the Nova Scotia Block and Supplemental Block (for the first five 3 years of operation). Surplus energy purchases from the Maritime Link are not RES 4 compliant in the Renewable Electricity Regulations. RES compliant electricity that will 5 be delivered on the Maritime Link in 2020 may vary depending on the start date of the 6 flow of the Nova Scotia Block and Supplemental Block. The Company has included a 7 RES forecast for 2020 assuming a full year of Nova Scotia and Supplemental Block flow 8 for simplicity and to illustrate the expected renewable energy in a year with normal 9 Maritime Link operation, as well as a second forecast with a start date of July 1, 2020 to 10 reflect the current outlook for 2020. 11 12 The RES Compliance Forecast in 13 Figure 15 below illustrates the full amount of RES-eligible energy forecasted to be 14 available to the Company if the Nova Scotia Block and Supplemental Block energy flow 15 begins on January 1, 2020 (1154 GWh), and the biomass unit is fully dispatched (290 16 GWh when Port Hawkesbury Paper (PHP) load is being supplied and 341 GWh when 17 PHP load is not being supplied). 18 19 Figure 15: RES 2019 and 2020 Compliance Forecast (Full Year Maritime Link)

RES 2019 and 2020 Compliance Forecast 2020 2020 2019 with no PHP PHP16 Energy Requirements (GWh) 17 NSR including DSM effects 11,000 11,003 9,923 Losses 767 755 755 Sales 10,233 10,248 9,168 RES (%) Requirement 25% 40% 40%

16 Port Hawkesbury Paper LP (PHP) is approved to operate under the Load Retention Tariff until the end of 2019. As such, the compliance forecast figures are shown both inclusive and exclusive of the PHP customer load. 17 NSR and Losses are from the 2018 NS Power 10 Year Energy and Demand Forecast, M08670, Exhibit N-1, Table A-1, April 30, 2018.18 The reduction in Hydro Generation in 2020 is as a result of required maintenance currently scheduled in 2020.

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RES 2019 and 2020 Compliance Forecast 2020 2020 2019 with no PHP PHP16 RES Requirement (GWh) 2,558 4,099 3,667

Renewable Energy Sources (GWh) NS Power Wind 260 260 260 Post 2001 IPPs 753 755 755 PH Biomass 290 290 341 COMFIT Wind Energy 503 503 503 COMFIT Non-Wind Energy 84 86 86 Eligible Pre 2001 IPPs 80 85 85 Eligible NSPI Legacy Hydro18 940 914 914 REA procurement (South Canoe/Sable) 355 355 355 Maritime Link 0 1,154 1,154

Forecasted Renewable Energy (GWh) 3,265 4,402 4,453 Forecasted Surplus or Deficit (GWh) 707 302 785 Forecasted RES Percentage of Sales 31.9% 43.0% 48.6% 1 2 The RES Compliance Forecast in Figure 16 below illustrates the amount of RES-eligible 3 energy currently forecasted to be available to the Company assuming a start date of July 4 1, 2020 for Nova Scotia Block and Supplemental Block energy flow (612 GWh), as well 5 as a fully dispatched biomass unit. This version of the RES forecast shows a potential 6 shortfall of renewable energy if PHP is operating, while without PHP there is a renewable 7 energy surplus. This is within the reasonable range of compliance planning as the 8 potential shortfall could be made up with the purchase of renewable imports.

18 The reduction in Hydro Generation in 2020 is as a result of required maintenance currently scheduled in 2020.

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1 Figure 16: RES 2019 and 2020 Compliance Forecast (Part Year Maritime Link)

RES 2019 and 2020 Compliance Forecast 2020 2020 2019 with no PHP PHP19 Energy Requirements (GWh) 20 NSR including DSM effects 11,000 11,003 9,923 Losses 767 755 755 Sales 10,233 10,248 9,168 RES (%) Requirement 25% 40% 40% RES Requirement (GWh) 2,558 4,099 3,667

Renewable Energy Sources (GWh) NS Power Wind 260 260 260 Post 2001 IPPs 753 755 755 PH Biomass 290 290 341 COMFIT Wind Energy 503 503 503 COMFIT Non-Wind Energy 84 86 86 Eligible Pre 2001 IPPs 80 85 85 Eligible NSPI Legacy Hydro21 940 914 914 REA procurement (South Canoe/Sable) 355 355 355 Maritime Link 0 612 612

Forecasted Renewable Energy (GWh) 3,265 3,860 3,911 Forecasted Surplus or Deficit (GWh) 707 -239 244 Forecasted RES Percentage of Sales 31.9% 37.7% 42.7% 2 3 6.2 Environmental Regulatory Requirements 4 5 The Nova Scotia Greenhouse Gas Emissions Regulations22 specify emission caps for 6 2010 – 2030, as outlined in

19 Port Hawkesbury Paper LP (PHP) is approved to operate under the Load Retention Tariff until the end of 2019. As such, the compliance forecast figures are shown both inclusive and exclusive of the PHP customer load. 20 NSR and Losses are from the 2018 NS Power 10 Year Energy and Demand Forecast, M08670, Exhibit N-1, Table A-1, April 30, 2018.21 The reduction in Hydro Generation in 2020 is as a result of required maintenance currently scheduled in 2020. 21 The reduction in Hydro Generation in 2020 is as a result of required maintenance currently scheduled in 2020.

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1 Figure 17. The net result is a hard cap reduction from 10.0 to 4.5 million tonnes over

2 that 20-year period, which represents a 55 percent reduction in CO2 release over 20 years. 3 Carbon emissions in Nova Scotia from the production of electricity in 2030 will have 4 decreased by 58 percent from 2005 levels. The primary means of meeting the caps is a 5 reduction in thermal generation from the existing coal-fired generating units, replaced by 6 renewable energy. 7

8 Figure 17: Compliance CO2 Emission Caps Emission Cap for Compliance Calendar Years All Facilities Period (million tonnes CO2eq) 1 2010, 2011 19.22 2 2012, 2013 18.50 3 2014, 2015, 2016 26.32 4 2017, 2018, 2019 24.06 5 2020 7.50 6 2021, 2022, 2023, 2024 27.50 7 2025 6.0 8 2026, 2027, 2028, 2029 21.50 9 2030 4.50 9 10 The Nova Scotia Air Quality Regulations23 specify emission caps for sulphur dioxide

11 (SO2), nitrogen oxides (NOX), and mercury (Hg). These regulations were subsequently 12 amended to extend from 2020 to 2030, effective January 1, 2015. The amended

13 regulations replaced annual limits with multi-year caps for the emissions targets for SO2

14 and NOX as outlined in Figure 18. The regulations also provide local annual maximums,

15 as well as limits on individual coal units for SO2, as provided in Figure 19 and Figure 20 16 respectively. The mercury emission caps are outlined in

22 Greenhouse Gas Emissions Regulations made under subsection 28(6) and Section 112 of the Environment Act S.N.S. 1994-95, c. 1, O.I.C. 2009-341 (August 14, 2009), N.S. Reg. 260/2009 as amended to O.I.C. 2013-332 (September 10, 2013), N.S. Reg. 305/2013. 23 Air Quality Regulations made under Sections 25 and 112 of the Environment Act S.N.S. 1994-95, c. 1 O.I.C. 2005-87 (February 25, 2005, effective March 1, 2005), N.S. Reg. 28/2005 as amended to O.I.C. 2017-255 (October 12, 2017), N.S. Reg. 150/2017.

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1 Figure 21. 2

3 Figure 18: Emissions Multi-Year Caps (SO2, NOX)

Multi-Year Caps Period SO2 (t) NOX (t) 2015 – 2019 (equal outcome) 304,500 96,140 2020 36,250 14,955 2021 – 2024 136,000 56,000 2025 28,000 11,500 2026 – 2029 104,000 44,000 2030 20,000 8,800 4 24 5 Figure 19: Emissions Annual Maximums (SO2, NOX) SO Annual NO Annual Year 2 X Maximum (t) Maximum (t) 2015 – 2019 72,500 21,365 2021 – 2024 36,250 14,955 2026 – 2029 28,000 11,500 6

7 Figure 20: Individual Unit Limits (SO2)

Year SO2 Individual Unit Limit (t)

2015 – 2019 42,775 2020 – 2024 17,760 2025 – 2029 13,720 2030 9,800 8

24 Annual maximums apply to the multi-year ranges from Figure 19 only. Please refer to Figure 20 for the caps on years that are not contained within the multi-year cap ranges.

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1 Figure 21: Mercury Emissions Caps Hg Emission Year Cap (kg) 2010 110 2011 100 2013 85 2014 65 2020 35 2030 30 2 3 By 2030, emissions of sulphur dioxide from generating electricity will have been reduced 4 by 80 percent from 2005 levels. Nitrogen oxides emissions will have decreased by 73 5 percent and mercury emissions will have decreased 71 percent from 2005 levels. 6

7 SO2 reductions are being addressed mainly by reduced thermal generation and changes to

8 fuel blends. NOX reductions are being addressed through reductions in thermal

9 generation and the previous installation of Low NOX Combustion Firing Systems. 10 Mercury reductions are being accomplished through reduced thermal generation, changed 11 fuel blends and the use of Powder Activated Carbon systems. 12 13 The amendments to the Nova Scotia Air Quality Regulations25 also provide an optional 14 program until the end of 2020, through which NS Power can obtain credits to be used to 15 make up deferred mercury emission requirements from earlier in the decade as well as for 16 compliance from 2020 through to 2029. NS Power offers a mercury recovery program, 17 such as recycling light bulbs or other mercury-containing consumer products, which 18 reduces the amount of mercury going into the environment through landfills. NS Power, 19 through its contracted service provider, Efficiency One, has collected mercury credits of 20 2.3 kg in 2015 and 19.2 kg in 2016, and 44.8 kg in 2017 as a result of this program and

25 Air Quality Regulations made under Sections 25 and 112 of the Environment Act S.N.S. 1994-95, c. 1 O.I.C. 2005-87 (February 25, 2005, effective March 1, 2005), N.S. Reg. 28/2005 as amended to O.I.C. 2017-255 (October 12, 2017), N.S. Reg. 150/2017

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1 these can be used to compensate for the deferred mercury emissions by 2020 as well as 2 for compliance from 2020 to 2029. NS Power continues to offer the program in 2018. 3 4 6.3 Upcoming Policy Changes 5 6 Until the recent federal coal phase-out policy changes announced in the fall of 2016, 26 7 NS Power’s operation of and planning for its coal-fired generation units has been 8 proceeding consistent with the provisions of the Agreement on Equivalency of Federal 9 and Nova Scotia Regulations for the Control of Greenhouse Gas Emissions from 10 Electricity Producers in Nova Scotia (the Equivalency Agreement). The Equivalency 11 Agreement was finalized in May 2014, and effective starting July 1, 2015 12 contemporaneous with the effective date for the current federal Reduction of Carbon 13 Dioxide Emissions from Coal-Fired Generation of Electricity Regulations. 14 15 In November 2016, the Province of Nova Scotia announced an agreement-in-principle 16 had been reached with the Government of Canada to develop a new equivalency 17 agreement that will enable the province to move directly from fossil fuels to clean energy 18 sources but enable Nova Scotia's coal-fired plants to operate at some capacity beyond 19 2030. The need for this new agreement was driven by amendments proposed by the 20 Federal Government to the Reduction of Carbon Dioxide Emissions from Coal-fired 21 Generation of Electricity Regulations.27 The amendments to the Reduction of Carbon 22 Dioxide Emissions from Coal-fired Generation of Electricity Regulations and potential 23 for a related equivalency agreement are under discussion between the Province and the 24 Government of Canada, and NS Power is providing input to that process as required. 25

26 In addition to the amendments to the Reduction of Carbon Dioxide Emissions from Coal- 27 fired Generation of Electricity Regulations, the Government of Canada announced a

26 https://www.canada.ca/en/environment-climate-change/news/2017/11/taking_action_tophase-outcoalpower.html 27 Vol. 152, No. 7 Canada Gazette Part I Ottawa, Saturday, February 17, 2018.

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1 “Pan-Canadian Approach to Pricing Carbon Pollution”28 in October 2016. This program 2 includes the requirement for each province to implement a carbon price by 2018 through 3 either an explicit carbon tax or a cap and trade program. In November 2016, the Province 4 of Nova Scotia announced that it would comply with the Federal requirement using a 5 cap-and-trade program. Amendments to the Environment Act29 were passed in October 6 2017 and the first set of regulations,30 which provide for emission reporting which is now 7 in effect. The details of the cap and trade program and a related second set of regulations 8 remain under development, with an expected program initiation in January 2019.

28https://www.canada.ca/en/environment-climate-change/news/2016/10/canadian-approach-pricing-carbon- pollution.html 29 Bill No. 15, as passed, Environment Act (amended), R.S.N.S. c. 10, 2017. 30 Quantification, Reporting and Verification Regulations made under Section 112Q of the Environment Act S.N.S. 1994-95, c. 1 O.I.C. 2018-43 (effective February 15, 2018), N.S. Reg. 29/2018.

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1 7.0 RESOURCE ADEQUACY 2 3 7.1 Operating Reserve Criteria 4 5 Operating Reserves are generating resources which can be called upon by system 6 operators on short notice to respond to the unplanned loss of generation or imports. 7 These assets are essential to the reliability of the power system. 8 9 As a member of the Maritimes Area of NPCC, NS Power meets the operating reserve 10 requirements as outlined in NPCC Regional Reliability Reference Directory #5, Reserve. 11 These Criteria are reviewed and adjusted periodically by NPCC and subject to approval 12 by the UARB. The Criteria require that: 13 14 Each Balancing Authority shall have ten-minute reserve available that is at 15 least equal to its first contingency loss…and, 16 Each Balancing Authority shall have thirty-minute reserve available that is 17 at least equal to one half its second contingency loss.31 18 19 In the Interconnection Agreement between Nova Scotia Power Incorporated and New 20 Brunswick System Operator (NBSO),32 NS Power and New Brunswick Power (NB 21 Power) have agreed to share the reserve requirement for the Maritimes Area on the 22 following basis: 23 24 The Ten-Minute Reserve Responsibility, for contingencies within the 25 Maritimes Area, will be shared between the two Parties based on a 12CP 26 [coincident peak] Load-Ratio Share… Notwithstanding the Load-Ratio 27 Share the maximum that either Party will be responsible for is 100 percent 28 of its greatest, on-line, net single contingency, and, NSPI shall be 29 responsible for 50 MW of Thirty-Minute Reserve. 30

31 https://www.npcc.org/Standards/Directories/Forms/Public%20List.aspx 32 New Brunswick's new Electricity Act (the Act) was proclaimed on October 1, 2013. Among other things, the Act establishes the amalgamation of the New Brunswick System Operator (NBSO) with New Brunswick Power Corporation ("NB Power").

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1 The Ten-Minute Reserve Responsibility formula results in a reserve share of 2 approximately 40 percent of the largest loss-of-source contingency in the Maritimes Area 3 (limited to 10 percent of Maritimes Area coincident peak load). This yields a reserve 4 share requirement for NS Power of approximately 40 percent of 550 MW, or 220 MW, 5 capped at the largest on-line unit in Nova Scotia. When Point Aconi is online, NS Power 6 maintains a ten-minute operating reserve of 168 MW (equivalent to Point Aconi net 7 output), of which approximately 33 MW is held as spinning reserve on the system. 8 Additional regulating reserve is maintained to manage the variability of customer load 9 and generation. The reserve sharing requirement with Maritime Link as the largest 10 source in Nova Scotia will depend on the amount of Maritime Link power used in Nova 11 Scotia. 12 13 7.2 Planning Reserve Criteria 14 15 The Planning Reserve Margin (PRM) intends to maintain sufficient resources to serve 16 firm customers. Unit forced outages, higher than forecasted demand, and lower than 17 forecasted wind generation are all conditions that could individually or collectively 18 contribute to a shortfall of dispatchable capacity resources to meet customer demand. 19 20 NS Power is required to comply with the NPCC reliability criteria that have been 21 approved by the UARB. These criteria are outlined in NPCC Regional Reliability 22 Reference Directory #1 – Design and Operation of the Bulk Power System33 and states 23 that: 24 25 Each Planning Coordinator or Resource Planner shall probabilistically 26 evaluate resource adequacy of its Planning Coordinator Area portion of the 27 bulk power system to demonstrate that the loss of load expectation 28 (LOLE) of disconnecting firm load due to resource deficiencies is, on 29 average, no more than 0.1 days per year. [This evaluation shall] make due 30 allowances for demand uncertainty, scheduled outages and deratings, 31 forced outages and deratings, assistance over interconnections with

33 https://www.npcc.org/Standards/Directories/Forms/Public%20List.aspx

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1 neighboring Planning Coordinator Areas, transmission transfer 2 capabilities, and capacity and/or load relief from available operating 3 procedures. 4 5 The 2014 IRP Loss of Load Expectation (LOLE) study confirmed that the 20 percent 6 planning reserve margin applied by NS Power is required to meet the NPCC reliability 7 criteria. The PRM is a long-term planning assumption that is typically updated as part of 8 an IRP process; each year in the 10 Year System Outlook Report the Company verifies 9 that the established PRM remains in compliance with the NPCC reliability criteria. NS 10 Power is in the process of initiating an updated LOLE study to establish the planning 11 reserve margin for the next cycle of long-term planning. 12 13 The planning reserve margin provides a basis for the minimum required firm generation 14 NS Power must maintain to comply with NPCC reliability criteria; it does not represent 15 the optimal or maximum required capacity to serve other system requirements such as 16 load-following (ramping capability) and emissions compliance. The optimal capacity 17 requirement is determined through a long-term planning exercise such as an IRP, as 18 discussed in Section 7.4. 19 20 7.3 Capacity Contribution of Renewable Resources in Nova Scotia 21 22 7.3.1 Wind Capacity Contribution 23 24 NS Power continues to evaluate the coincidence of wind generation with peak load on an 25 annual basis to better understand the Effective Load Carrying Capability (ELCC) or 26 capacity value of wind assets on the NS Power system by completing studies using 27 available data. The capacity value determines the amount of firm capacity contribution 28 that can be credited to wind installed on the system. This is a dynamic value that changes 29 as the wind penetration level changes; it is unique to each electricity system as the 30 capabilities of the other system generating units and the load shape influence its result. 31

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1 In previous 10 Year System Outlook reports, NS Power provided calculations for the 2 capacity value of wind using both the LOLE and Cumulative Frequency methodologies. 3 The LOLE methodology is a long standing utility industry standard for planning reserve 4 margin assessment, which can be adapted to assess the capacity value of wind. 5 Cumulative Frequency is a statistical technique of analyzing a set of historical data points 6 to determine the minimum capacity factor of wind predicted to be available on the system 7 during peak hours, with corresponding certainty. As discussed in the 2017 10 Year 8 System Outlook Report, LOLE is the more robust methodology for calculating wind 9 capacity value; the Company has used the Cumulative Frequency Analysis as a 10 supplementary study to the LOLE. As the industry standard for assessment of the 11 capacity value of wind generation is the LOLE methodology, NS Power no longer plans 12 to continue completing Cumulative Frequency assessments of the ELCC of wind 13 generation. 14 15 The advantages of the LOLE methodology over others are that the calculation practices 16 are well-established and the computation considers not just the coincidence of peak load 17 and wind generation, but also the impact of the amount of wind generation proportional 18 to the system (exhibiting declining capacity factor with higher penetration levels of 19 wind). The main disadvantage of the LOLE approach is that the results can vary 20 significantly year over year. As discussed in the 2017 10-Year System Outlook, the 21 International Energy Agency (IEA) Wind Task 25 Final Report34 recommends that 22 between 10 and 30 years of wind and load data is required to establish a reliable ELCC of 23 wind generation using LOLE calculations. 24 25 To date, the LOLE calculation has been completed each year using the Probabilistic 26 Assessment of System Adequacy (PASA) module of Plexos. The model has taken into 27 account hourly actual wind, hourly actual load, generator capacities, and forced outage 28 rates. In conjunction with the continued update of long-term planning assumptions in

34 IEA Wind Task 25 Final Report - http://www.ieawind.org/AnnexXXV/PDF/Final%20Report%20Task%2025%202008/T2493.pdf

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1 preparation for the next IRP, NS Power has been conducting a revised LOLE study to 2 evaluate the capacity value of wind, as well as the duration requirements for storage 3 technologies discussed in Section 8.3.2, for the NS Power system using a more 4 comprehensive modeling approach. NS Power is in the process of finalizing this study 5 and will bring forward the results as part of the long-term planning assumptions vetting 6 conducted through the next IRP. NS Power has used the 17 percent capacity value of 7 wind historically applied in Nova Scotia for the purposes of this year’s Report. Please 8 also refer to Section 7.3.1.1 regarding the inclusion of Energy Resource Interconnection 9 Service wind resources. 10 11 For future long-term planning exercises, the marginal capacity value of any incremental 12 wind generation decreases due to saturation effects and the increase of variable 13 generation affecting the ability to serve load during peak demand. The results of the study 14 will provide the appropriate capacity values to be used in modeling new wind resources 15 considered in long term resource planning exercises. 16 17 Some municipal load is served from one independent wind farm supply. This generation 18 is not included in NS Power’s sourced wind generation but contributes to operational 19 considerations of the total amount of wind generation. 20 21 7.3.1.1 Energy Resource Interconnection Service Connected Resources 22 23 In the 2017 10 Year System Outlook Report, NS Power advised it was conducting a study 24 to determine the potential capacity contribution of ERIS facilities based on current 25 system configuration and conditions. The study has been completed and is attached as 26 Appendix B. 27 28 The study has concluded that all existing ERIS facilities can operate as though they are 29 NRIS facilities and therefore can contribute to system capacity for the purposes of 30 resource planning at this time without the requirement for additional system upgrades. 31 The transmission system upgrades undertaken to enable the transmission of Maritime

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1 Link energy across Nova Scotia contributed to the change to ERIS facility capacity 2 treatment. 3 4 Consistent with this and for the purposes of reflecting this potential additional capacity in 5 this report, NS Power has applied a capacity value of 17 percent to all existing wind 6 resources, both ERIS and NRIS, in this report. This change results in an additional 28 7 MW of capacity. 8 9 The Company notes that this represents a material change to the treatment of these 10 facilities and a significant increase to the Company’s reported capacity. However, the 11 addition of large-scale wind to the system and the interplay of this with firm and 12 curtailable transmission resources remains a new area for resource planning and remains 13 subject to change. 14 15 Until these matters are better understood it remains premature to make longer-term 16 resource planning decisions based on this capacity addition. The Company will continue 17 to monitor this resource planning input and will refine the capacity estimates as required. 18 Changes, if necessary, will be incorporated within future 10 Year System Outlook 19 Reports. 20 21 7.3.2 Storage Capacity Contribution 22 23 As part of the LOLE study being conducted to evaluate the capacity contribution of wind, 24 NS Power is also evaluating the ability for storage to provide system capacity; most 25 importantly, what duration of energy storage technologies will be required for Nova 26 Scotia at varying levels of storage penetration. The results of this work will be provided 27 with the other LOLE study results in preparation for the next IRP.

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1 7.4 Load and Resources Review 2 3 The ten year Load and Resources Outlook in Figure 22 and Figure 23 below are based 4 on the capacity changes and DSM forecast from Figure 4 above, and provides details 5 regarding NS Power’s required minimum forecasted planning reserve margin equal to 20 6 percent of the firm peak load. 7 8 Figure 22 is intended to provide a medium-term outlook of the capacity resources 9 available to the Company compared to expected customer demand, given the most recent 10 assumptions to date. As noted in Section 8.2, the planning reserve margin provides a 11 basis for the minimum required firm generation NS Power must maintain to comply with 12 NPCC reliability criteria; it does not necessarily represent the optimal or maximum 13 required capacity to serve other system requirements such as wind-following (ramping 14 capability) and emissions compliance. In its final report submitted to the UARB in the 15 Generation Utilization and Optimization proceeding,35 Synapse stated: 16 17 The PRMs provide one high-level measure of the amount of generation 18 capacity relative to the NPCC 20 percent planning reserve margin 19 requirement. PRM is defined as the amount of firm capacity available over 20 the planning peak load. Notably, the NPCC constraint is not the only 21 constraint that dictates how much capacity might be required on the 22 system. Plexos’ ability to model hourly dispatch requirements means that 23 any ramping requirements must be met with adequate capacity. Also, the 24 presence of annual emissions constraints combined with the multi‐fossil‐ 25 fuel environment in which the thermal fleet operates (coal, oil, gas) leads 26 to capacity requirements that could exceed thresholds needed to meet 27 either NPCC reserve or ramping requirements. The integrated aspect of 28 the model (long‐term planning and short‐term dispatch) is intended to 29 allow capture of all these moving parts when optimizing retirement and 30 build decisions.36 31

35 Synapse Energy Economic Inc., Nova Scotia Power Inc. Thermal Generation Utilization and Optimization Economic Analysis of Retention of Fossil‐Fueled Thermal Fleet To and Beyond 2030 – M08059, filed on May 1, 2018 36 Ibid at section 3.1,

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1 As stated by Synapse, other considerations may dictate the most economic generating 2 capacity for the system; therefore, any surplus capacity in this outlook does not 3 necessarily suggest that any full or partial unit retirement would be possible or optimal, 4 as these units may provide other additional value. The optimal capacity requirement, and 5 the appropriateness of any unit retirements, is determined through a long-term planning 6 exercise such as an IRP.

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1 Figure 22: NS Power 10 Year Load and Resources Outlook

Load and Resources Outlook for NSPI - Winter 2018/2019 to 2027/2028 (All values in MW except as noted) 2018/2019 2019/2020 2020/2021 2021/2022 2022/2023 2023/2024 2024/2025 2025/2026 2026/2027 2027/2028

2,025 2,056 2,074 2,095 2,118 2,141 2,154 2,168 2,181 2,197 A Firm Peak Load Forecast 24 41 58 74 90 107 123 141 159 179 B DSM Firm37 2,001 2,015 2,016 2,021 2,028 2,034 2,030 2,027 2,022 2,017 C Firm Peak Less DSM (A - B) 400 403 403 404 406 407 406 405 404 403 D Required Reserve (C x 20%) 2,401 2,418 2,420 2,425 2,433 2,441 2,436 2,433 2,426 2,421 E Required Capacity (C + D)

2405 2405 2405 2405 2405 2405 2405 2405 2405 2405 F Existing Resources

Firm Resource Additions: 33 -153 G Thermal Additions 38 43 H Biomass 39 13.8 2.5 I Community Feed-in-Tariff 40 0.8 0.5 J Tidal Feed-in-Tariff 41 153 K Maritime Link Import 91 3 0 0 0 0 0 0 0 0 Total Annual Firm Additions L (G + H + I + J + K) 91 94 94 94 94 94 94 94 94 94 Total Cumulative Firm Additions M (L + M of the previous year) 2496 2499 2499 2499 2499 2499 2499 2499 2499 2499 N Total Firm Capacity (F + M)

94 81 79 73 66 58 62 66 72 78 + Surplus / - Deficit (N - E) 25% 24% 24% 24% 23% 23% 23% 23% 24% 24% Reserve Margin % [(N - C)/C]

37 Cumulative estimated Firm Peak reduction based on DSM forecast 38 Thermal includes Burnside #4 (winter capacity 33 MW) which is assumed to be returned to service by the end of Q2 2018. Also includes assumed Lingan 2 retirement once Maritime Link Base Block provides firm capacity service. 39 43 MW from the PH Biomass plant which will be able to provide firm service following the transmission upgrades required for the Maritime Link. 40 The Community Feed-in-Tariff represents distribution-connected renewable energy projects, totalling 179.1 MW installed by beginning of 2020 (156.6 wind, 22.5 MW non-wind). 41 Tidal Feed-in-Tariff - Tidal projects assume 6.5 MW by 2020

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1 Figure 23 is a graphical representation of the assessment completed in Figure 22 above. 2 It provides a breakdown of the forecasted system demand and planning reserve margin 3 and how this will be served by the system capacity. 4 5 Figure 23: Firm Capacity and Peak Demand Analysis

6

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1 NS Power performs an assessment of operational resource adequacy covering an 18- 2 month period twice a year (in April and October proceeding the summer and winter peak 3 capacity periods) in compliance with NERC standards and in association with NPCC 4 working groups. These reports of system capacity and adequacy are posted on the 5 NSPSO’s OASIS site in the Forecast and Assessments Section. Figure 24 shows a 6 graphical representation of NS Power’s most recent 18 month assessment. 7 8 Figure 24: 18 Month Load and Capacity Assessment

9 10

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1 8.0 TRANSMISSION PLANNING 2 3 8.1 System Description 4 5 The existing transmission system has approximately 5,220 km of transmission lines at 6 voltages at the 69 kV, 138 kV, 230 kV and 345 kV levels. The configuration of the NS 7 Power transmission system and major facilities is shown in Figure 25. 8 9 Figure 25: NS Power Major Facilities in Service 2018

10 11 12 The 345 kV transmission system is approximately 468 km in length and is comprised of 13 372 km of steel tower lines and 96 km of wood pole lines. 14 15 The 230 kV transmission system is approximately 1271 km in length and is comprised of 16 47 km of steel/laminated structures and 1224 km of wood pole lines. 17

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1 The 138 kV transmission system is approximately 1871 km in length and is comprised of 2 303 km of steel structures and 1568 km of wood pole lines. 3 4 The 69 kV transmission system is approximately 1560 km in length and is comprised of 5 12 km of steel/concrete structures and 1548 km of wood pole lines. 6 7 Nova Scotia is interconnected with the New Brunswick electric system through one 345 8 kV and two 138 kV lines providing up to 350 MW of transfer capability to New 9 Brunswick and up to 300 MW of transfer capability from New Brunswick, depending on 10 system conditions. As the New Brunswick system is interconnected with the province of 11 Quebec and the state of Maine, Nova Scotia is integrated into the NPCC bulk power 12 system. 13 14 Nova Scotia is also interconnected with Newfoundland via a 500MW, +/-200kV DC 15 Maritime Link tie that was placed into service on January 15, 2018 in preparation for the 16 receipt of capacity and energy from the Muskrat Falls Hydro project and the Labrador 17 Island Link DC tie between Labrador and Newfoundland. 18 19 8.2 Transmission Design Criteria 20 21 NS Power, consistent with good utility practice, utilizes a set of deterministic criteria for 22 its interconnected transmission system that combines protection performance 23 specifications with system dynamics and steady state performance requirements. 24 25 The approach used has involved the subdivision of the transmission system into various 26 classifications each of which is governed by the NS Power System Design Criteria. The 27 criteria require the overall adequacy and security of the interconnected power system to 28 be maintained following a fault on and disconnection of any single system component.

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1 8.2.1 Bulk Power System (BPS) 2 3 The NS Power bulk transmission system is planned, designed and operated in accordance 4 with North American Electric Reliability Corporation (NERC) Standards and NPCC 5 criteria. NS Power is a member of the NPCC, therefore, those portions of NS Power’s 6 bulk transmission network where single contingencies can potentially adversely affect the 7 interconnected NPCC system are designed and operated in accordance with the NPCC 8 Regional Reliability Directory 1: Design and Operation of the Bulk Power System, and 9 are defined as Bulk Power System (BPS). 10 11 8.2.2 Bulk Electric System (BES) 12 13 On July 1, 2014, the NERC Bulk Electricity System (BES) definition took effect in the 14 United States. The BES definition encompasses any transmission system element at or 15 above 100 kV with prescriptive Inclusions and Exclusions that further define BES. 16 System Elements that are identified as BES elements are required to comply with all 17 relevant NERC reliability standards. 18 19 NS Power has adopted the NERC definition of the BES and an NS Exception Procedure 20 for elements of the NS transmission system that are operated at 100 kV or higher for 21 which contingency testing has demonstrated no significant adverse impacts outside of the 22 local area. The NS Exception Procedure is used in conjunction with the NERC BES 23 definition to determine the accepted NS BES elements and is equivalent to Appendix 5C 24 of the NERC Rules of Procedure. 25 26 The BES Definition and NS Exception Procedure were approved by Order of the Board 27 dated April 6, 2017. 28 29 Under the BES definition and NS Exception Procedure approved by the Board, elements 30 classified as NS BES elements are required to adhere to all relevant NERC standards that 31 have been approved by the Board for use in Nova Scotia.

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1 8.2.3 Special Protection Systems (SPS) 2 3 NS Power also makes use of Special Protection Systems (SPS) in conjunction with the 4 Supervisory Control and Data Acquisition (SCADA) system to enhance the utilization of 5 transmission assets. These systems act to maintain system stability and remove 6 equipment overloads, post contingency, by rejecting generation and/or shedding load. 7 The NS Power system has several transmission corridors that are regularly operated at 8 limits without incident due to these SPS. 9 10 8.2.4 NPCC A-10 Standard Update 11 12 The NPCC Task Force on Coordination of Planning (TFCP) is in the process of 13 reviewing Document A-10 and its application, in consultation with the Task Force on 14 Coordination of Operation (TFCO), Task Force on System Protection (TFSP), and Task 15 Force on System Studies (TFSS). Currently, Document A-10 provides a methodology to 16 identify Bulk Power System (BPS) elements in the interconnected NPCC Region. At 17 present, all NPCC criteria apply to BPS facilities; however, there are questions as to 18 whether this application produces the appropriate level of reliability in NPCC. 19 20 The objectives of the review are as follows: 21 22 (1) Consider existing and alternative methodologies to: 23 • Identify critical facilities for the applicability of NPCC Directories; 24 • Simplify the existing methodology to make it less labor-intensive; 25 • Improve consistency across Areas in application and outcomes of the 26 methodology. 27 (2) Consider conforming changes to NPCC documents to implement any necessary 28 improvements as a result of the review. 29

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1 NS Power has representation on the A-10 Working group that is performing the review 2 for TFCP. Throughout 2017, Webex meetings have been held twice per week with in- 3 person meetings including representatives from all NPCC areas occurring two days of 4 every month. The working group is now actively testing the first two of the following 5 three methodologies that were submitted to TFCP in the interim report entitled CP-11, A- 6 10 Review Phase 1 Final Report dated Nov 17, 2017: 7 8 1. Proposal #1: Revised A-10 Methodology 9 the working group, in accordance with the TFCP Scope of Work, seeks to 10 maintain the framework of the existing A-10 performance-based test, improve the 11 clarity and consistency of the testing procedure as well as direct the applicability 12 of Directory #1 to where it is technically justified. 13 14 2. Proposal #2: Performance Based Methodology 15 Methodology #2 is a hybrid methodology combining both bright-line filtering and 16 performance-based analysis to develop a list of critical facilities that should be 17 designed and operated according to NPCC’s more stringent criteria. This 18 methodology has two performance-based tests – one for Directory #1 and one for 19 Directory #4 which clearly identify which elements are required to be classified as 20 BPS due to their impact on system performance. 21 22 3. Proposal #3: Connectivity Based Methodology 23 Methodology #3 is a hybrid methodology combining both bright-line 24 determination and connectivity analysis to develop a list of facilities to be 25 designed and operated according to NPCC’s more stringent criteria. The 26 objective of this methodology is to pursue a non-performance based method to 27 identify critical facilities to which NPCC Directory #1 and Directory #4 may be 28 applied. 29

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1 Testing of Methodology #3 is presently on hold. The working group anticipates the 2 testing phase will be completed by the end of Q3, 2018. 3 4 Changes to the existing A-10 methodology could have a material financial impact on NS 5 Power if the new methodology greatly increases the number of BPS elements on NS 6 Power’s transmission system. 7 8 8.3 Transmission Life Extension 9 10 NS Power has in place a comprehensive maintenance program on the transmission 11 system focused on maintaining reliability and extending the useful life of transmission 12 assets. The program is centered on detailed transmission asset inspections and associated 13 prioritization of asset replacement (for example, conductor, poles, cross-arms, guywires, 14 and hardware replacement). 15 16 Transmission line inspections consist of the following actions: 17 18 • Visual inspection of every line once per year via helicopter, or via ground patrol 19 in locations not practical for helicopter patrols. 20 • Foot patrol of each non-BPS (Bulk Power System) line on a three year cycle. 21 Where a Lidar survey is requested for a non-BPS line, the survey will replace the 22 foot patrol in that year. 23 • For BPS lines, Lidar surveys every two years out of three, with a foot patrol 24 scheduled for the third year. 25 26 The aforementioned inspections identify asset deficiencies or damage, and confirm the 27 height above ground level of the conductor span while recording ambient temperature. 28 This enables the NSPSO to confirm the rating of each line is appropriate.

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1 8.4 Transmission Project Approval 2 3 The transmission plan presented in this document provides a summary of the planned 4 reinforcement of the NS Power transmission system. The proposed investments are 5 required to maintain system reliability and security and comply with System Design 6 Criteria and other standards. NS Power has sought to upgrade existing transmission lines 7 and utilize existing plant capacity, system configurations, and existing rights-of-way and 8 substation sites where economic. 9 10 Major projects included in the plan have been included on the basis of a preliminary 11 assessment of need. The projects will be subjected to further technical studies, internal 12 approval at NS Power, and approval by the UARB. Projects listed in this plan may 13 change because of final technical studies, changes in the load forecast, changes in 14 customer requirements or other matters determined by NS Power, NPCC/NERC 15 Reliability Standards, or the UARB. 16 17 In 2008, the Maine and Atlantic Technical Planning Committee (MATPC) was 18 established to review intra-area plans for regional resource integration and transmission 19 reliability. The MATPC forms the core resource for coordinating input to studies 20 conducted by each member organization and presenting study results, such as evaluation 21 of transmission congestion levels in regards to the total transfer capabilities on the utility 22 interfaces. This information is used as part of assessments of potential upgrades or 23 expansions of the interties. The MATPC has transmission planning representation from 24 NS Power, Maritime Electric Company Ltd., Emera Newfoundland and Labrador, 25 Northern Maine Independent System Administrator (which includes Emera Maine 26 Northern Operating Region and Eastern Maine Electric Cooperative), Newfoundland and 27 Labrador Hydro, and New Brunswick Power (NB Power). NS Power and NB Power 28 jointly conduct annual Area Transmission Reviews for NPCC.

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1 9.0 REGIONAL DEVELOPMENT 2 3 9.1 Maritime Link 4 5 The Maritime Link (ML) is a bipolar connection between 101S Woodbine and Bottom 6 Brook terminal station (BBK) in Newfoundland that is based on Voltage-Source 7 Converter (VSC) technology. Each pole is configured as an asymmetric monopole VSC 8 rated for 200kV and 250MW on the DC side of the converter. The bipole configuration 9 allows for redundancy of half of the total rated transfer capability. 10 11 The ML is a combination of cable and overhead line: approximately 171km of subsea 12 cable and 142 + 46 km of overhead line on the NL and NS sides respectively. The AC 13 yard for each pole at each converter station has a converter transformer with high-side tap 14 changer and a pre-insertion resistor, along with filtering, protection, and measuring 15 apparatus. The DC side has a smoothing filter, DC line disconnector, and high speed 16 switch for fast discharge of the DC line. The active and reactive power levels can be 17 constant, gently ramped, or nearly instantly changed (e.g. during use as SPS). 18 19 The ML was placed into service on January 15, 2018. Commercial energy transactions 20 over the ML between NS Power and Nalcor Energy Marketing began on February 19, 21 2018 upon approval of the Newfoundland Open Access Transmission Tariff (OATT). 22 These transactions, in conjunction with the increased reliability and ancillary benefits 23 have created value for customers in both Nova Scotia and Newfoundland. NS Power will 24 continue to work with Nalcor to maximize the value of the Maritime Link on behalf of 25 customers. 26 27 In April 2018, Nalcor reaffirmed the schedule for commissioning the Muskrat Falls 28 Generating Station, with first power still expected in late 2019. It is anticipated that the 29 delivery of the Nova Scotia Block of energy and Surplus Energy pursuant to the Energy 30 Access Agreement will begin in mid-2020.

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1 9.2 Nova Scotia – New Brunswick Intertie Overview 2 3 The power systems of Nova Scotia and New Brunswick are interconnected via three 4 overhead transmission lines; one 345 kV line from Onslow, Nova Scotia to 5 Memramcook, New Brunswick, and two 138 kV lines from Springhill, Nova Scotia to 6 Memramcook, New Brunswick. Since there is only a single 138 kV line between 7 Springhill and Onslow in Nova Scotia, the intertie can be considered to be comprised of a 8 single 345 kV circuit in parallel with a single 138 kV circuit. The primary function of the 9 intertie is to support system reliability. 10 11 Access to the Nova Scotia - New Brunswick intertie is controlled by the terms of the 12 respective OATTs of NS Power and NB Power. As noted in Section 6.1.1, Figure 14, 13 there is currently one active Transmission Service request for Long-Term Firm Point-to- 14 Point Transmission Service across the NB-NS intertie, and no active Network Integration 15 Transmission Service requests for network service within NS. 16 17 Power systems are designed to accommodate a single contingency loss (i.e. loss of any 18 single element and certain multiple elements) and since the 345 kV line carries the 19 majority of the power flow (between NS and NB), loss of a 345 kV line becomes the 20 limiting factor. Power flow on the 138 kV lines is also influenced by the loads in Prince 21 Edward Island; Sackville, New Brunswick; as well as Amherst, Springhill and Debert, 22 Nova Scotia. Wind and planned tidal generation in the Amherst/Parrsboro area can also 23 impact 138 kV line loading. 24 25 Import and export limits (both firm and non-firm) on the intertie have been established to 26 allow the Nova Scotia and the New Brunswick system to withstand a single contingency 27 loss. The limits are currently set at up to 350 MW export and up to 300 MW import. 28 These figures represent limits under pre-defined system conditions, and differ for Firm 29 versus Non-Firm Transmission Service. Conditions which determine the actual limit of 30 the interconnection are shown in Figure 26. 31

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1 In 2018, line L-6513 between Onslow and Springhill will be rebuilt and re-named as L- 2 6613. This work will impact the current import and export levels with New Brunswick. 3 4 Figure 26: Conditions Determining Limits

Export Import Amount of generation in Nova Scotia that Nova Scotia system load level (Import can be rejected or run-back via SPS must be less than 22% of total system action load) Percentage of synchronous generation in Reactive Power Support level in the Nova Scotia (providing inertia and Metro Area frequency response) New Brunswick export level to Prince Arming status of SPS New Brunswick Edward Island and/or New England Real time line ratings (climatological Seasonal line ratings (climatological conditions in northern Nova Scotia) conditions in northern Nova Scotia) Net Northern Nova Scotia System load Load level in Moncton area plus flow to level Prince Edward Island Largest single loss of load contingency in Largest generation/source contingency in Nova Scotia Nova Scotia Generation in the Amherst/Parrsboro area Generation in Amherst/Parrsboro area Internal transmission limitations in Nova Status of generation and transmission Scotia (Cape Breton Export, Onslow lines in New Brunswick Import) Status of the intertie between New Brunswick and Quebec Conditions on intertie between New 5 Brunswick and New England 6 7 If the 345 kV Nova Scotia - New Brunswick intertie trips while exporting, the parallel 8 138 kV lines can be severely overloaded and potentially trip, causing Nova Scotia to 9 separate from New Brunswick. If this happens, the Nova Scotia system frequency 10 (measured in Hertz) will rise, risking unstable generation plant operation and possible 11 equipment damage. To address this, NS Power uses a fast-acting SPS to reject or run 12 back sufficient generation to prevent separation. 13

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1 If the NS Power system becomes separated from the North American interconnected 2 power system during heavy import, Nova Scotia system frequency will drop. Depending 3 on the system configuration at the time of separation and the magnitude of the import 4 electricity flow that was interrupted, the system will respond and re-balance. The system 5 does this by automatically rejecting firm and non-firm load through under-frequency load 6 shedding (UFLS) protection systems as required by NPCC Standard PRC-006-NPCC-1 7 Automatic Under-frequency Load Shedding. The degree of load shedding will be 8 impacted by the amount of in-province generation supplied by non-synchronous power 9 sources, such as wind energy conversion systems, photovoltaic (solar), or tidal power due 10 to the technical characteristics of those sources. NPCC is currently conducting a study of 11 the effects of decreased synchronous generation sources and interaction with the UFLS. 12 High penetration levels of non-synchronous generation in Nova Scotia reduce the total 13 inertia of the NS Power system, thereby increasing the rate at which the Nova Scotia 14 system frequency declines, resulting in the potential for higher levels of load shedding 15 through UFLS. 16 17 The loss of the 345 kV line between Onslow, Nova Scotia and Memramcook, New 18 Brunswick is not the only contingency that can result in Nova Scotia becoming separated 19 from the New Brunswick Power system while importing power. All power imported to 20 Nova Scotia flows through the Moncton/Salisbury area of New Brunswick. Since there is 21 no generation in the Moncton/Salisbury area, and only a limited amount of generation in 22 Prince Edward Island (PEI), power flowing into Nova Scotia is added and shares 23 transmission capacity with the entire load of Moncton, Memramcook, and PEI. In 2016, 24 firm transmission capacity from NB to PEI was increased to 300MW. 25 26 NB Power restricts power export to Nova Scotia to a level such that any single 27 contingency does not cause adverse impacts on New Brunswick, PEI, or the intertie with 28 New England. Any transmission reinforcement proposed to improve reliability, increase 29 import and export power capacity or prevent the activation of UFLS in Nova Scotia must

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1 also consider the reinforcement of the southeast area of the New Brunswick transmission 2 system. 3 4 Although joint studies have been conducted, at this time the timing and configuration of 5 an expansion to the provincial intertie has yet to be determined. The remaining 6 transmission project associated with the Maritime Link will reinforce the 138 kV portion 7 of the intertie and will significantly increase the firm export capability from Nova Scotia. 8 When construction of this new circuit between Onslow and Springhill is completed in 9 2018, it will reduce the exposure to UFLS, potentially increase import capacity, and 10 improve transmission capacity for generation projects in the Amherst/Parrsboro area. 11 However, import capacity will still be limited by transmission congestion in southeast 12 New Brunswick. Given the dynamic nature of the provincial and regional electricity 13 markets it is likely that further upgrades may be required over the next decade. To this 14 end, NS Power has secured a large portion of a right-of-way to support a second 345 kV 15 line between Onslow and the New Brunswick border. 16 17 9.3 Co-operative Dispatch 18 19 NS Power and NB Power continue to operate under the Cooperative Dispatch Agreement 20 executed December 20, 2016, following the successful pilot. The Parties continue to 21 enter in energy and reserve transactions, when economic, to create saving for customers 22 of both utilities. NS Power expects to continue operating under this agreement with no 23 material amendments presently expected.

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1 10.0 TRANSMISSION DEVELOPMENT 2017 TO 2026 2 3 10.1 Transmission Development Plans 4 5 Transmission development plans are summarized below. As highlighted earlier, these 6 projects are subject to change. For 2018, the majority of the projects listed are included in 7 the 2018 Annual Capital Expenditure Plan. 8 9 2018 10 • Separating L-8004 and L-7005 at the Canso Causeway crossing to increase the 11 Cape Breton export limit. This upgrade is associated with the Maritime Link 12 project. (CI 43678) 13 • Completion of Spider Lake substation in the metro area to relieve Halifax 14 generation constraints. (CI 48022) 15 • 2C Port Hastings 138kV substation will be uprated to meet NPCC BPS standards. 16 • L-6513 transmission line re-build to increase the line rating. This upgrade is 17 associated with the Maritime Link project. (CI 43324) 18 • In accordance with a directive from NPCC, Bulk Power System (BPS) elements 19 which previously fell within the “grandfather clause” of NPCC Directory 04 20 System Protection Criteria must have duplicate high-speed protection systems and 21 duplicate station batteries. Lingan 230 kV will be uprated in 2018. (CI 46757) 22 • Replacement of Lingan 230 kV Westinghouse Gas insulated Switchgear (GIS) 23 equipment to mitigate the potential failure and increase reliability. (CI 46591) 24 • 88S Lingan 138kV will be uprated to meet NPCC BPS standards. 25 • 6S Terrace Street 69 kV substation will be retired once the existing 4 kV 26 distribution load is converted to 12 kV. 27 • New 12MVA Mount Hope 69kV-25kV substation in Dartmouth 28 • Replacement of 15/20/25MVA Penhorn 69-12.5kV Transformer 48H-T1

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1 • Replacement of 7.5/10//11.2 MVA Halliburton 69-25kV Transformer 56N-T1 2 with new 15/20/25MVA unit due to load growth and voltage conversions from 3 4kV to 25kV. CI:52328 4 • Capacitor Bank Breaker replacement at 103H-Lakeside (3 breakers). These are 5 high duty cycle units critical to the operation of the transmission system. 6 • 2018 Transmission Right of Way Widening 69kV (CI: 51969) to reduce the 7 occurrence of edge and off right of way tree contacts (Year 3 of 8) 8 • Purchase of new 25MVA mobile transformer to replace 5P (2018 – 2019) 9 • L-5330B (73), L-5549 (21), L-6020 (49), L-6531 (8) structure replacement (2018- 10 2019): CI 49948 11 12 2019 13 • 2019 Transmission Right of Way Widening 69kV (CI: 51969) to reduce the 14 occurrence of edge and off right of way tree contacts (Year 4 of 8) 15 • Purchase of new 25MVA mobile transformer to replace 5P (2018 – 2019) 16 • Replacement of 73W-T1 transformer at Auburndale with a new 138/69-25 kV 17 transformer rated at 15/20/25 MVA. 18 19 2020 20 • 2020 Transmission Right of Way Widening 69kV (CI: 51969) to reduce the 21 occurrence of edge and off right of way tree contacts (Year 5 of 8) 22 • Replace existing 12.5/14MVA Milton transformer with 15/20/25MVA unit 23 supplied at either 69kV or 138kV. 24 • Replace existing 5/5.6MVA Central Argyle 7.5/10/12.5MVA unit. 25 • Replace existing 4.5/10/12.5//14MVA Barrington Passage transformer with 26 15/20/25MVA unit and add additional feeder circuit. 27 • Replace existing 3/4//4.48MVA Lower East Pubnico transformer with 28 7.5/10/12.5MVA unit. 29 • Replace existing 138kV Harbour Crossing (L6014): A transmission planning 30 study is currently underway to determine the most practical means of replacing

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1 the L-6014 capacity that will be displaced with the removal of the Harbour 2 Crossing. The new infrastructure will need to be in service in 2020. 3 4 2021 5 • 2021 Transmission Right of Way Widening 69kV (CI: 51969) to reduce the 6 occurrence of edge and off right of way tree contacts (Year 6 of 8). 7 8 2022 9 • 2022 Transmission Right of Way Widening 69kV (CI: 51969) to reduce the 10 occurrence of edge and off right of way tree contacts (Year 7 of 8) 11 • Install New 138kV Supply to 50V-Klondike and replace existing 69-25kV 12 transformer with new 15/20/25 MVA unit. 13 14 2023 15 • 2020 Transmission Right of Way Widening 69kV (CI: 51969) to reduce the 16 occurrence of edge and off right of way tree contacts (Year 8 of 8). 17 18 10.2 Bulk Electricity System 19

20 The following compliance gaps were identified concerning the implementation of the 21 BES definition in Nova Scotia Power: 22 23 1. The SVC at the 120H Brushy Hill substation was been classified as a BES 24 element. A project is underway to refurbish the SVC at 120H and this capital 25 item should cover any BES disturbance monitoring requirements on the SVC. 26 27 Update: The refurbishment of the SVC at 120H was completed in 2017. As part of this 28 work, disturbance monitoring was added at the site that can be accessed locally. 29

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1 The 85S Wreck Cove substation is not classed as BES but the generator transformers and 2 the generators are classed as BES. A sequence of events recorder exists at the 85S Wreck 3 Cove substation to record breaker positions, protection operations and teleprotection 4 status. The monitoring of the generators and generator transformers that reside in the 5 plant are the responsibility of generation services as protective relaying and other 6 monitoring equipment also resides there. 7 8 Update: The assessment will be scheduled for 2018. 9 10 2. The 14H – Burnside and 83S – Victoria Junction generators have been classified 11 as BES elements. An assessment is required by generation services for sequence 12 of events and fault recorder capabilities. 13 14 Update: The assessment will be scheduled for 2018. 15 16 3. At 1N Onslow and 103H Lakeside there are deficiencies in the monitoring 17 capabilities for the shunt devices and modifications are required to bring these 18 substations into compliance. 19 20 Update: An assessment of the Onslow and Lakeside monitoring capabilities will be 21 scheduled in 2018. The estimated cost to correct deficiencies in the monitoring 22 capabilities of the shunt devices at 1N-Onslow and 103H-Lakeside is $150,000 per site. 23 24 4. The 101S Woodbine substation has a project underway to expand the substation 25 and the disturbance monitoring capabilities for this substation will be covered 26 under this expansion project. 27 28 Update: In 2017, the work to expand the 101S-Woodbine substation was completed. 29 Disturbance monitoring was added as required and event trigger setpoints have been 30 applied.

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1 Compliance work for newly identified BES elements shall be completed within five years 2 from the date of this Order. 3 4 10.3 Western Valley Transmission System – Phase II Study 5

6 A study was initiated in late 2017 to determine the system upgrades needed to address 7 transmission line capacity, clearance, and age issues in the Western Valley over a 15 year 8 transmission planning horizon. In particular, the following 69 kV lines were targeted: 9 10 L-5531 (13V-Gulch to 15V-Sissiboo) 11 L-5532 (13V-Gulch to 3W-Big Falls) 12 L-5535 (15V-Sissiboo to 9W-Tusket) 13 L-5541 (3W-Big Falls to 50W-Milton) 14 15 These lines were targeted as a result of Lidar studies that were performed in 2015 to 16 determine if the existing line to ground clearances were consistent with those required for 17 NS Power’s default 50ºC line temperature rating of each line. Results of these studies 18 indicated that there were numerous clearance violations with respect to clearance to 19 buildings, water, distribution line crossings, and the ground. 20 21 In addition, three of the four 69kV lines noted above were built in the 1950’s using single 22 pole delta wood pole construction. These are now between 60-70 years old and at their 23 end of life. There is also a thermal capacity issue in the Valley and Western NS regions. 24 The transmission system was designed and built to serve load in these areas, which it 25 remains capable of doing. However, over the past 10-15 years, new generation resources 26 have been installed that have significantly changed the flows on these lines. Large scale 27 wind generation facilities and distributed (COMFIT) generation have been added to 28 existing hydro facilities and have reversed typical line flows during periods of light load 29 and high generation such that there is no remaining capacity for additional generation 30 resources between Kingston and Yarmouth.

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1 Scope 2 The scope of the study is to assess four options for dealing with the clearance, age, and 3 capacity issues on Lines L-5531 (13V-Gulch to 15V-Sissiboo), L-5532 (13V-Gulch to 4 3W-Big Falls), L-5535 (15V-Sissiboo to 9W-Tusket), and L-5541 (3W-Big Falls to 5 50W-Milton): 6 7 Option #1 ‐ Restore L-5531, L-5532, L-5535, and L-5541 to 50ºC Temperature Rating 8 Option #2 ‐ Upgrade L-5531, L-5532, L-5535, and L-5541 to 80ºC Temperature Rating 9 Option #3 ‐ Rebuild L-5531, L-5532, L-5535, and L-5541 with 336 ACSR Linnet and 10 100ºC Temperature rating 11 Option #4 ‐ Rebuild L-5531, L-5532, L-5535, and L-5541 with 556 ACSR Dove and 12 100ºC Temperature rating (Operate at 69kV) 13 14 A brief description of each option is as follows: 15 16 Option #1 – Restore L-5531, L-5532, L-5535, and L-5541 to design temperature of 17 50ºC: 18 This option would upgrade the structures so that line would be capable of operating up to 19 50ºC while maintaining sufficient ground clearance (including 0.8m snow buffer). 20 21 Option #2 – Upgrade L-5531, L-5532, L-5535, and L-5541 to design temperature of 22 80ºC: 23 This option would upgrade the structures so that lines would be capable of operating up 24 to 80ºC but existing conductors would remain unchanged. Essentially this would consist 25 of re-tensioning the existing transmission lines and replacing poles where required with 26 higher ones to increase ground clearance. 27 28 Option #3 – Rebuild L-5531, L-5532, L-5535, and L-5541 with ACSR 336.4 Linnet to 29 design temperature of 100ºC:

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1 This option would rebuild the lines with higher rated conductor (ACSR 336.4 Linnet) 2 designed to operate up to 100ºC at 69 kV. Existing transmission Structures would be 3 replaced. 4 5 Option #4 – Rebuild the lines to 138 kV standards with ACSR 556.5 Dove at 100ºC but 6 operate at 69 kV : 7 8 This option would rebuild the lines to 138 kV standards using 556 ACSR (Dove) 9 conductor designed to operate up to 100ºC. The lines would continue to be operated at 10 69kV but would be ready for future conversion to 138kV. This would enable an easier 11 upgrade for the transmission system from 51V-Tremont to 9W-Tusket and 50W-Milton 12 from 69 kV to 138 kV. Note that the existing lines L-5025 (51V-Tremont to 11V- 13 Paradise) and L-5026 (11V-Paradise to 13V-Gulch) were built for 138 kV standards but 14 currently operated at 69 kV. 15 16 Option 4 would also allow for the future conversion of Lines L-5025, L-5026, L-5531, L- 17 5532, L-5535, and L-5541 to 138 kV. However, conversion to 138kV would also require 18 the conversion of numerous line taps; generator interconnection substations; and 19 distribution substations supplied via the principle lines under study. 20 21 Status: The initial draft of the Western Valley Transmission System – Phase II Study is 22 expected to be complete by July 6, 2018.

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1 11.0 CONCLUSION 2 3 Customers count on NS Power for energy to power every moment of every day, and for 4 solutions to power a sustainable tomorrow. Environmental legislation in Canada and 5 Nova Scotia continues to drive a transformation of the NS Power electric power system. 6 Within the 10-year window considered in this Report, NS Power will experience further

7 reductions in hard caps for CO2, SO2, NOX and mercury, and will be required to serve 40 8 percent of sales with renewable electricity from qualifying sources. The outcomes of 9 other ongoing federal and provincial policy changes discussed in Section 6.3 remain 10 uncertain, and could affect the Company’s outlook within this 10-year period. 11 12 This transformation has driven a shift towards renewable electricity generation and a 13 reduction in conventional coal fired electricity production. The integration of variable 14 renewable resources on the NS Power system has imposed revised operating and 15 flexibility demands on previously base-loaded steam units, which continue to bring 16 essential reliability services to the system. 17 18 NS Power is participating in the Board’s Generation Utilization and Optimization 19 process. On June 7, 2018, the Company submitted comments to the UARB and 20 stakeholders indicating its general support of the recommendations included in Synapse’s 21 Thermal Generation Utilization and Optimization Economic Analysis of Retention of 22 Fossil Fueled Thermal Fleet to and Beyond 2030 Final Report. As noted in NS Power’s 23 comments, uncertainty remains with respect to the design and implementation of the 24 carbon policy regime for the province. In its letter, the Company submitted that the 25 issues and recommendations discussed in Synapse’s report would be best examined 26 through an Integrated Resource Planning exercise in 2019 after the Board, stakeholders 27 and the Company have more certainty around federal and provincial carbon policy. 28 29 From the resource planning perspective, this Report is intended to provide a medium term 30 outlook of the capacity resources available to the Company compared to expected 31 customer demand, given the most recent assumptions to date. NS Power continues to

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1 review and refine the main drivers of resource planning requirements, such as the end-use 2 forecasting methodology for forecasting firm peak load, the studies used to evaluate the 3 firm capacity contribution of wind and ERIS resources, and the planning reserve margin 4 requirement. 5 6 As noted in Section 7.4, the capacity assessment in this report provides a basis for the 7 minimum required firm generation NS Power must maintain to comply with NPCC 8 reliability criteria; it does not necessarily represent the optimal or maximum required 9 capacity to serve other system requirements (such as ramping capability to follow wind 10 and load patterns). The optimal capacity requirement, and the appropriateness of any unit 11 retirements or additions, is determined through a long-term planning exercise such as an 12 IRP. The Company will continue to analyze and adjust its outlook accordingly as load 13 forecasting methodology matures, planning assumptions are updated and the outcomes of 14 policy changes regarding carbon emissions and coal unit retention become clear. 15 16 The key inputs for Transmission Planning in the ten-year window of this Report include 17 transmission of energy to be delivered over the Maritime Link, continued compliance 18 with Reliability Standards, and opportunities for regional cooperation.

DATE REVISED: July 12, 2018 Page 70 of 70 2018 10 Year System Outlook Report Appendix A Page 1 of 4 2018 10 Year System Outlook Report Status of 2014 IRP Action Items 2014 IRP Action Item IRP Reference 2018 10YSO Report Status Reference Continue to develop an understanding of the operational IRP Final Report, 2018 10YSO Report: Annual Update: Item to be challenges associated with the planned increasing levels of page 69, Section Section 8.3 addressed annually in 10 Year variable generation integration and report to the UARB as part 6.2.2 System Outlook reports. of the 10 Year System Outlook Report. Report to the UARB on the status of the need for flexible IRP Final Report, 2018 10YSO Report: Annual Update: Item to be resources to integrate additional variable generation in the 10 page 69, Section Section 8.3 addressed annually in 10 Year Year System Outlook Report. 6.2.2 System Outlook reports.

During 2015-2020, conduct additional system studies to IRP Final Report, 2018 10YSO Report: Annual Update: Item to be evaluate operations with increased levels of renewable pages 73 – 74, Section 4.3.1 – Impact addressed in annual 10 Year resources that are expected over the next few years. Include Section 6.2.5 of increased levels of System Outlook reports. investigation of system requirements with fewer steam units renewables included in providing real power operations. Utilization Factor calculation and • Report on the status of such efforts each year in the projections of steam 10 Year System Outlook Report. unit operations. • Use Plexos to continue to assess hourly patterns of system need and resources with respect to operation under higher levels of wind resources expected over the next few years.

During 2015-2016, continue to evaluate the coincidence of IRP Final Report, 2018 10YSO Report: Item Complete: LOLE and wind generation with peak load to better understand the page 68, Section Analysis updated in Cumulative Frequency Analyses capacity value of wind assets on the NS Power system. 6.2.2 Section 8.3.1. conducted in 2015 and 2016, and reported in respective 10 Year System Outlook Reports.

Annual Update: Update of wind capacity value analysis to be continued in future 10YSO reports. Report on the ongoing evaluation of the planning reserve IRP Final Report, 2018 10YSO Report: Annual Update: Item to be margin for the power system in the 10 Year System Outlook page 75, Section Section 8.2 discussed annually in annual 10 2018 10 Year System Outlook Report Appendix A Page 2 of 4 2018 10 Year System Outlook Report Status of 2014 IRP Action Items 2014 IRP Action Item IRP Reference 2018 10YSO Report Status Reference Report. 6.2.7 Year System Outlook reports. Comprehensive study of Planning Reserve Margin requirements to be conducted as input to next Integrated Resource Plan. ERIS connected wind resources will be evaluated for firm IRP Final Report, 2018 10YSO Report: Item Complete: capacity contribution. During 2015, NS Power will determine page 75, Section Section 8.3.1.1 NS Power completed study to the extent to which ERIS resources can count as capacity 6.2.6 evaluate potential capacity towards resource adequacy during winter peak. contribution level of ERIS Resources. Study confirmed ERIS resources are able to deliver capacity on transmission system; ERIS resources have been included as contributing to firm capacity in the 2018 10YSO report.

Continue the thermal generation asset analysis work from the IRP Final Report, 2018 10YSO Report: Item Complete: Unit Utilization & IRP process. By the end of June 2015, file an initial thermal pages 71 – 72, Section 4.3 Investment Strategy included in asset management plan striving to optimize the level of Section 6.2.4 2015 10 Year System Outlook sustaining capital expenditures required for the fleet of Report, and all subsequent 10YSO coal/oil/gas plant. Update this plan each year in the 10 Year Reports. System Outlook Report. The plan will include the following: The Generation Utilization & • Recognition of uncertainty of many elements involved Optimization Synapse Report filed in this form of analysis. with the UARB provided additional context on some of these issues. NS • Recognition of/adherence to planning reserve margin Power expects the next IRP will also requirement and level of planning reserve surplus inform any outstanding issues. associated with different net firm peak load trajectories based on then-anticipated DSM peak reductions and associated net firm peak load forecast.

2018 10 Year System Outlook Report Appendix A Page 3 of 4 2018 10 Year System Outlook Report Status of 2014 IRP Action Items 2014 IRP Action Item IRP Reference 2018 10YSO Report Status Reference • Projections of possible retirement paths for the thermal fleet. • Prioritization of units or plans for retention given system constraints.

• Consideration of locational value of Tufts Cove plant, and flexible operating characteristics of gas and oil- fired steam units compared to coal-fired units. There may be locational or system considerations that could give preference to sustaining capital or life extension expenditures at the Tufts Cove location compared to other plants.

• Consideration of location of other system resources, either NS Power-owned or IPP-owned, and their capacity value.

• Consideration of unit utilization forecasts and the significant driver that operating hours is for maintenance investment.

Monitor ongoing developments of tidal energy and report to IRP Final Report, 2018 10YSO Report: Annual Update: Updates provided the UARB as part of the 10 Year System Outlook Report filed page 68, Section Section 4.2 (current tidal in 10YSO on known tidal annually in June. 6.2.2 forecasted capacity developments, when applicable. additions)

File Renewable to Retail Tariff Application by September 1, IRP Final Report, N/A Item Complete 2015. page 69, Section 6.2.2

Complete the integration of the Maritime Link. IRP Final Report, 2018 10YSO Report: Item Complete page 68, Section Section 10.1 2018 10 Year System Outlook Report Appendix A Page 4 of 4 2018 10 Year System Outlook Report Status of 2014 IRP Action Items 2014 IRP Action Item IRP Reference 2018 10YSO Report Status Reference 6.2.2

Execute the Maritime Link transmission investments. IRP Final Report, 2018 10YSO Report: Item to be completed in 2018. page 73, Section Section 10.1 6.2.5 Monitor cost-effective market opportunities (imports and IRP Final Report, 2018 10YSO Report: Annual Update: Item to be exports) as well as enhancements in regional balancing and page 70, Section Section 10.2 and 10.3 continually addressed in annual 10 interconnection and report on developments in the 10 Year 6.2.3 Year System Outlook reports. System Outlook Report. During 2015, continue discussions with Newfoundland IRP Final Report, 2018 10YSO Report: Annual Update: Item to be (NALCOR) and New Brunswick (New Brunswick Power) on page 70, Section Section 10.1, 10.2 & continually addressed in annual 10 greater regional electric system coordination: 6.2.3 10.3 Year System Outlook reports. • Provide an annual update to the UARB. • Discuss need, impacts, and cost allocation associated with a second 345 kV line to New Brunswick. • Explore mechanisms to advance efficient regional unit commitment, dispatch, and operating reserve sharing policies.

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2017 NRIS Wind Study Report 062-2017TSMG-R0

Principal Investigator John Charlton, P. Eng.

December, 2017

Transmission Planning Nova Scotia Power Inc.

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Executive Summary

This study was initiated to determine if the Effective Load Carrying Capability (ELCC) of existing Energy Resource Interconnection Service (ERIS) wind generating facilities within Nova Scotia can be counted toward resource adequacy following the construction of the system Network Upgrades associated with the Maritime Link project.

This report presents the results of the study with the objective of assessing the impact of Maritime Link Network Upgrades on existing ERIS wind generation facilities connected to the Nova Scotia transmission system. The scope of the study was limited to short circuit analysis, steady state analysis, and stability analysis, and also included a provision to estimate the cost of any additional network upgrades required to enable the existing ERIS facilities to operate in a similar fashion to NRIS facilities.

The results of the analysis demonstrate the following:

 There are no thermal, voltage, or stability violations on the transmission system resulting from receipt of full output of all existing ERIS wind generation facilities connected to the NSPI transmission system under normal and first contingency conditions with the Maritime Link (ML) upgrades in service. Analysis cases included winter peak, summer peak, and light load scenarios with maximum levels of wind on the NSPI backbone system.

 Short circuit levels at all NSPI and wind generation facility substations (≥ 69 kV) were satisfactory and were confirmed to be below NSPI design criteria levels.

 All NS transmission and distribution connected wind can be included in the ELCC calculations from the perspective of transmission system capacity. Note that this study did not attempt to define what the ELCC contribution from wind generation facilities should be, as NSPI is currently studying methodologies based on Loss of Load Expectation (LOLE), and on Cumulative Frequency Analysis (CFA) to determine the appropriate ELCC value for Nova Scotia. At present, CFA analysis shows that an overall ELCC of 8% could be obtained with a confidence level of 90%. This would result in an ELCC contribution of 48.8MW based on existing wind resources of approximately 610MW.

 No additional facilities are required in order to operate existing ERIS designated facilities in the same manner as existing NRIS facilities.

 Analysis of wind generation includes all facilities under the jurisdiction of the NSPI System Operator, not just facilities with a power purchase agreement with NSPI.

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Table of Contents Page

Executive Summary ...... ii

List of Appendices ...... v

List of Tables and Figures ...... v

1.0 Introduction ...... 1

1.1 Scope ...... 1 1.2 Existing Transmission System ...... 1 1.3 Maritime Link Project ...... 4 1.4 Expected Generation Facilities ...... 5 1.5 Expected Generation Retirements ...... 5 1.6 Expected Export Transmission Service Facilities ...... 5 1.7 Base Case Development ...... 5 1.8 Assumptions ...... 6 2.0 Technical Model ...... 6

2.1 System Load ...... 7 2.2 System Model and Methodology ...... 8 3.0 Technical Analysis ...... 9

3.1 Short Circuit ...... 9 3.2 Steady State Analysis ...... 10 3.2.1 Base Cases ...... 10 3.2.2 Steady-State Contingencies ...... 10 3.2.3 Steady-State Evaluation ...... 14 3.3 Stability Analysis ...... 14 3.3.1 Stability Base Cases ...... 14 3.3.2 Stability Contingencies ...... 14 3.3.3 Stability Evaluation ...... 17 4.0 Resource Adequacy ...... 17

5.0 System Requirements ...... 19

6.0 Conclusions and Recommendations ...... 20

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List of Appendices

Appendix A: Transmission Connected Wind Farms: 1-Line Diagrams Appendix B: Short Circuit Levels Appendix C: Distributed Generation – Bus Load Adjustments Appendix D: Steady State Cases – Load Flow Diagrams Appendix E: Steady State Results Appendix F: Stability Results Appendix G: Stability Results 2021LL Cases Appendix H: Stability Results2021SUM Cases Appendix I: Stability Results 2021WIN Cases

List of Tables and Figures

Table 1: Transmission Connected Wind Farms ...... 3 Table 2: Coincident Peak Demand ...... 8 Table 3: Short Circuit Levels ...... 9 Table 4: Base Case Models ...... 10 Table 5: Steady State Contingencies ...... 14 Table 6: Dynamic Contingencies ...... 17

Figure 1: NS Interfaces ...... 2 Figure 2: Transmission Connected Wind Generation Facilities ...... 3 Figure 3: PSS®E model ...... 7

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1.0 Introduction

This study was initiated to determine if the Effective Load Carrying Capability (ELCC) of existing Energy Resource Interconnection Service (ERIS) wind generating facilities within Nova Scotia can be counted toward resource adequacy following the construction of the system Network Upgrades associated with the Maritime Link project. The objective was not to determine how a facility can be reclassified from Energy Resource Interconnection Service (ERIS) to Network Resource Interconnection Service (NRIS), but rather to determine if its ELCC can be included in resource adequacy calculations.

1.1 Scope This report presents the results of the study with the objective of assessing the impact of Maritime Link Network Upgrades on existing ERIS wind generation facilities connected to the Nova Scotia transmission system. In particular, the study evaluates whether or not the ERIS facilities could essentially operate as NRIS facilities as a result of the ML improvements to the transmission system.

The scope of the study is limited to the following:  Short circuit analysis  Steady state analysis to determine any thermal overload of transmission elements or voltage criteria violation  Stability analysis to demonstrate that the interconnected power system is stable for various fault contingencies

The scope of this report also provides for a high-level non-binding cost estimate of any remaining upgrades needed to permit existing ERIS facilities to operate in a similar manner as NRIS facilities.

1.2 Existing Transmission System The existing NSPI transmission system has approximately 5,150 km of transmission lines at voltages 69 kV, 138 kV, 230 kV and 345 kV, and is interconnected to New Brunswick Power via one 345kV and two 138kV transmission lines. It has concentrated generation in the eastern portion of the province, and flows from the east are typically towards Onslow in the centre of the province. From Onslow there is a transmission corridor to the Nova Scotia border with New Brunswick in addition to a corridor towards the load centre in Halifax.

The corridors of the BPS system which are monitored and have associated stability limits are:  Cape Breton Export (CBX), a corridor with high flows from the high generation zone in the east towards the centre of the province.

 Onslow Import (ONI), a corridor of lines coming into Onslow from the east with flows typically towards Onslow.

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 Nova Scotia Import/Export (NSX), the tie lines with NB Power.

 Onslow South (ONS), the corridor south from Onslow with flows typically out of Onslow. This corridor supplies additional generation to the Halifax load centre and the western portion of the province.

CBX and ONI have been identified as having Interconnection Reliability Operating Limits (IROLs) to the Maritimes Area Reliability Coordinator.

Figure 1: NS Interfaces

Transmission Connected Wind Generation: There are currently 11 wind generation facilities located in Nova Scotia that are considered to be connected to NSPI’s transmission system. These facilities are identified below in Figure 2 and Table 1. Single line diagrams for each facility are included in Appendix A of this report.

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Figure 2: Transmission Connected Wind Generation Facilities

Transmission Connected Wind Farms in Nova Scotia # I.D. Wind Farm MW IR # Service 1 106W Pubnico Point 30 5 N/A 2 19C Sable 13.8 8 NRIS 3 92N Amherst 31.5 45 N/A 4 109S Lingan 14 48 N/A 5 89N Nuttby 49.5 82 ERIS 6 91N Dalhousie Mountain 50 84 ERIS 7 93N Glendhu 62.1 114 ERIS 8 98V Gullivers Cove 30 141 NRIS 9 120C Bear Head 23 150 NRIS South Canoe I 24 372 NRIS 10 110W South Canoe II 78 379 NRIS 11 102V St Croix. (Ellershouse) 16.5 * 461 NRIS * - An additional 14.1 MW is under development at 102V

Table 1: Transmission Connected Wind Farms

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In order to connect to the transmission system, the majority of these facilities were studied under the Standard Generator Interconnection Procedures (GIP), as approved by the Nova Scotia Utility and Review Board. However, a few facilities were proposed prior to the effective date of the GIP. While the studies for these early projects were similar to those used after the GIP came into effect, their service designation was not defined and appears as ‘N/A’ in Table 1. Projects with this designation essentially operate as NRIS generation. Projects that proceeded after the GIP came into effect were classified as either ERIS or NRIS.

It should be noted that the three ERIS projects in Table 1 are all located on the backbone of the Nova Scotia (NS) transmission system, either between Cape Breton and Onslow, or between Onslow and New Brunswick (NB). These are the portions of the transmission system most impacted by upgrades associated with the Maritime Link project, which will enable firm export of 150MW to NB between December 1 and March 31 of each year, and 330MW of firm exports to NB between April 1 and November 31 of each year.

1.3 Maritime Link Project The Maritime Link (ML) is a bi-directional Voltage-Source Converter High Voltage Direct Current interconnection between NS and the island of Newfoundland. The nominal rating of the converters is 500 MW, but with cable and inverter losses, the delivered power at the 101S-Woodbine terminal is expected to be approximately 475 MW. The ML is configured for two poles of 250 MW (net 237.5 MW) each.

The following Network upgrades were identified as required for the Maritime Link to proceed. The last of these upgrades is scheduled for completion in 2018:

1. 67N-Onslow 345kV bus re-configuration to eliminate L-8002 + L-8003 common breaker contingency by swapping the 345kV Termination nodes for L-8001 (Memramcook – NB L- 3025) and L-8003 (79N-Hopewell). 2. 101S-Woodbine 345 kV bus development per 1-Line (Appendix A) including a second 556 MVA 345kV/230kV transformer. 3. Lines L-7011 and L-7012 termination at 101S-Woodbine per 1-Line (Appendix A) 4. Line protection upgrade for L-7011, L-7012, L-7021, L-7022, and SPS modification to include run-back of HVDC 5. New tower crossing at Canso Causeway to eliminate shared tower crossing for lines L-7005 and L-8004 6. Uprating of Line L-7019 from 60oC operating temperature to 70oC (273/345 MVA), 7. Uprating of Line L-6511 from 50oC operating temperature to 60oC (140/184 MVA), 8. Rebuild of Line L-6513 with operating temperature of 100oC (287/287 MVA – limited to 287 MVA by breaker ratings)

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1.4 Expected Generation Facilities All in-service transmission connected generation facilities are included in the study. As of November 2017, NSPI’s Advanced Stage Generation Interconnection Request queue included four transmission generation projects at various stages of interconnection study. The following new generation projects are expected to proceed prior to 2021:

 14.1 MW wind generation (1 project)

 13 MW tidal generation (3 projects: 2MW, 5MW, 6MW)

1.5 Expected Generation Retirements The 150MW 87S-Lingan generator G2 is scheduled for retirement in conjunction with the commissioning of the Maritime Link and the flow of the NS block of energy (firm capacity) from the Muskrat Falls hydro facility in Labrador. As such, the Lingan Unit G2 was not included in the base case models.

1.6 Expected Export Transmission Service Facilities The transmission service request TSR-400 for firm Point to Point Service between NS and NB was included in base case scenario models. TSR-400 calls for Firm export capacity of 330MW between April 1 and November 30 of each year, and for 150MW of Firm export capacity between December 1 and March 31 of each year. Firm transfers between NS and NB are scheduled to begin with the completion of the Maritime Link project and the start of commercial operation of the Muskrat Falls Hydro facility in Labrador. While the Maritime Link is scheduled to go into service in late 2017, the Muskrat Falls generating station is scheduled to provide first power in 2019, with full power becoming available in 2020.

1.7 Base Case Development The system representation used in the base cases for this study was developed jointly with NBP for the Maritimes area from the update of MMWG 2014 Series MMWG 2020 base cases. The projects planned for installation between 2017 and 2021 that are listed below, were included: 1. Network Upgrades associated with the Maritime Link per Section 1.3 2. Dual high-speed protection systems installed at 1N-Onslow 138 kV, 103H-Lakeside 138kV, 120H-Brushy Hill 138kV, 120H-brushy Hill 345kV, and 3C-Port Hastings 230kV. 3. 120H Brushy Hill SVC controls replacement 4. Addition of 50MVAR Capacitor Bank at 103H-Lakeside 5. Addition of 50MVAR Capacitor Bank at 90H-Sackville 6. Replacement of Lingan 230 kV Westinghouse Gas insulated Switchgear (GIS) 7. Installation of dual high-speed protection systems at 88S-Lingan 230kV substation during GIS replacement project. 8. Installation of new 138kV Spider Lake substation in Dartmouth. 9. Thermal uprating of L-7003 from 60°C to 70°C operating temperature.

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1.8 Assumptions The study was performed using the following assumptions: 1. NSPI’s transmission line ratings as posted on NSPI’s Intranet, including any projected line upgrades for the periods under study. 2. Committed generation as listed in Section 1.4 is modeled in the base cases. 3. All transmission elements are in-service, including capacitor banks and the Static Var Compensator. 4. All transmission upgrades associated with Maritime Link have been completed 5. Remedial Action Schemes (SPS’s) are armed to reject or run-back the Maritime Link HVDC facility up to 330 MW for contingencies. 6. COMFIT generation is not dynamically modelled, but is treated as negative load netted at the appropriate substation bus. Wind generation currently connected to the NSPI distribution system totals 185MW.

2.0 Technical Model

For the steady state analysis, the seven transmission wind facilities interconnected along the backbone of the NS electrical system were operated at nameplate capacity for each of the Winter Peak (2021WIN), Summer Peak (2021SUM), and Light Load (2021LL) cases. These facilities include the three existing ERIS facilities: IR#82 - Nuttby Mountain, IR#84 - Dalhousie mountain, and IR#114 - Glen Dhu, and also the two facilities having ‘N/A’ designations: IR #45 - Amherst and IR #48 - Lingan. The remaining four transmission wind facilities that do not interconnect with the backbone system were dispatched at 30% of their nameplate capacity in all cases except for one light load case where they were dispatched to 0MW. The PSS®E model for load flow is shown in Figure 3.

As noted in Section 1.8, the 185MW of distribution system connected wind generation was not explicitly modelled. Instead, it was treated as negative load, meaning that connected load at each distribution substation bus was netted out with the generation connected to feeders originating from that bus. For the case of this NRIS study, it was assumed that all distribution connected wind was operating at 70% nameplate rating. The tables of load adjustments made to each of the 2021WIN, 2021SUM, and 2021LL PSS®E cases are included in Appendix C of this report.

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Figure 3: PSS®E model

2.1 System Load NSPI has a winter peaking system with a large Non-Firm component. The forecast for system “Peak Total” includes Non-Firm load as the system is planned to accommodate both Firm and Non-Firm Load. However, the Non-Firm load has highly variable production schedules and can be curtailed by the System Operator if needed for system control, and typically responds to real-time marginal pricing to self-curtail coincident with system peak demand.

In 2012, a large industrial customer retired part of their infrastructure, lowering their interruptible load by approximately 65MW. In addition, they migrated a portion of their interruptible load to a real time pricing rate. While this load remained interruptible under the new rate, customer production schedules were adjusted resulting in lower customer interruptible load during peak periods.

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The 2021 Coincident Peak Demand for NSPI, including Demand Side Management effects, is provided in Table 2. The summer and light load forecast are scaled from the firm winter peak load forecast based on historic load patterns. The Non-Firm load has a wide variability and can be on maximum or minimum at any time of the year. However, with the real time pricing component, the non-firm load will most likely be off during system peak.

Coincident Peak Demand - 2017 NSPI Forecast for 2021 Year Peak Total (MW) Non-Firm (MW) Firm (MW) Peak 2193 155 2038 Summer Peak 1477 155 1322 Light Load 696 62 634

Table 2: Coincident Peak Demand

2.2 System Model and Methodology Testing and analysis was conducted using the following criteria, software packages and/or modelling data.

Short Circuit NSPI system sequence models are kept current for the Aspen OneLiner program. The base cases for the 2017 year were updated with the planned facilities described in Section 1. Short circuit analysis was then performed to compare post Maritime Link fault levels at each of the transmission wind generation sites with NSPI’s design criteria to confirm that fault levels remain within design limits.

The methodology used to determine the short circuit level at each of the wind farm HV buses was as follows:  With all lines in service and all generators on-line, a classical fault analysis for all buses was performed using ASPEN OneLiner. Classical fault analysis assumes a uniform pre-fault voltage profile of magnitude of 1.0 p.u. at 0 degrees.  The results of the short circuit analysis are shown in Table 3 for Transmission Connected wind farms. Results for all provincial buses are shown in Appendix B.

Steady State Analysis was carried out using Python scripts within PSS®E software version 33.7. The scripts simulate base case and a wide range of single contingencies, with the output reports summarizing bus voltages or branch flows that exceed established limits.

System modifications and additions up to 2021 were modeled and contingencies that would best provide a measure of system reliability were tested in accordance with NSPI and NPCC design criteria. The Study year 2021 was selected to accommodate the completion and full operation of the Maritime Link project. Details on the contingencies studied are provided in Section 3.2.2.

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Steady State analysis was run for the contingencies on each of the bases cases listed in Section 3.2.1.

Stability Analysis was carried out using PSS®E software version 33.7. Stability analysis was performed for the 2021 study year and system configuration. Winter Peak, Summer Peak and Light Load cases were studied for a wide range of contingencies to provide an overall measure of the impacts of operating ERIS generation as NRIS generation on system reliability. Details on the contingencies studied are provided in Section 3.2.2.

3.0 Technical Analysis

3.1 Short Circuit The NSPI design criteria for maximum system fault capacity (three phase, symmetrical) is 5,000 MVA on 138kV and 3,500 MVA on 69kV.

Short circuit analysis was performed using Aspen OneLiner V11.8, classical fault study, 3LG and flat voltage profile at 1 per unit voltage. The short-circuit level at each of the transmission interconnected wind farm buses within Nova Scotia was determined to demonstrate that the Network Upgrades associated with the Maritime Link project did not raise the short circuit levels above equipment design criteria.

Wind Generation Site Short Circuit Level (at POI) 2021 Bus # Stn Name MW kV MVA 199275 106W Pubnico Point 30 69 231 199080 19C Sable 13.8 69 104 199530 92N Amherst 31.5 138 1125 199016 109S Lingan 14 69 527 199581 89N Nuttby 49.5 69 272 199590 91N Dalhousie Mountain 50 230 2306 199610 93N Glendhu 62.1 138 1222 199710 98V Gullivers Cove 30 69 153 199052 120C (At 1C) Bear Head (at 1C HV) 23 138 2284 South Canoe I 24 199501 110W 138 889 South Canoe II 78 199635 102V St Croix. (Ellershouse) 16.5 69 805

Table 3: Short Circuit Levels

Short circuit levels do not change significantly as a result of the Network upgrades associated with the Maritime Link project. The wind generation sites that are remote to the backbone system saw little or no change in fault level at their Point of Interconnection. Wind sites connected to the

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backbone of the system saw marginal increases in short circuit level at their Point of Interconnection, but remained well within the design criteria ratings.

3.2 Steady State Analysis 3.2.1 Base Cases Table #4 shows the complete list of base cases used within this study. Base cases included Winter Peak, Summer Peak, and Light Load scenario’s under a variety of import and export conditions. 1- line diagrams for each steady state base case are presented in Appendix D.

Base Case Models

ML MW NB/HQ NB/NE NB/PEI NS/NB ONI CBX Wind GEN Load Case Condition ONS NL/NS MW MW MW MW MW MW MW MW MW

2021WIN Normal WP 330 -300 0 200 0 979 709 893 302 1720 2050

2021WIN-1 WP, NSX: 150MW 330 -300 0 200 150 1113 845 876 302 1878 2058

WP, NSX: 150MW 2021WIN-1a 330 -300 0 200 150 1123 856 887 302 1884 2064 Pt Tupper off

2021WIN-2 WP, NSX: -100MW 330 -300 0 200 -100 896 622 911 302 1613 2043

2021WIN-3 WP, NSX: -100MW -100 -300 0 200 -100 878 604 893 302 2046 2046

2021SUM Normal SP 475 -300 800 160 0 603 469 590 304 1012 1487

2021SUM-1 SP, NSX: 330MW 475 -300 800 160 330 952 680 609 304 1217 1362

2021SUM-2 SP, NSX: -100MW 475 -300 800 160 -100 525 430 612 304 766 1341

SP, NSX: -100MW 2021SUM-3 -100 -300 800 160 -100 528 213 616 304 1340 1340 ML: -100MW SP, NSX: -100MW 2021SUM-3a -100 -300 800 160 -100 203 72 291 304 1326 1326 ML: -100MW, Metro

2021LL Normal LL 70 600 800 80 0 233 99 263 207 505 575

NSX: 330MW 2021LL-1 410 600 800 80 330 564 436 263 207 504 584 ML: 475MW NSX: -100MW 2021LL-2 -100 600 800 80 -100 134 -11 263 207 575 575 ML: -100MW

Table 4: Base Case Models

 These cases demonstrate the behaviour of the system with maximum amounts of wind generation on the backbone system, under conditions of maximum export and import.  In each case, distributed generation is modelled at 70% nameplate rating.

3.2.2 Steady-State Contingencies The steady state analysis included the contingencies listed in Table 5.

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BES/BPS Elements Load Flow Contingencies

Station Element Load Flow SPS Bkr line Bus Var Gen Xfmr

x 710 88S, 88S-710 - x 711 88S, 88S-711 - x 712 88S, 88S-712 - x 713 88S, 88S-713 - x 720 88S, 88S-720 - x 721 88S, 88S-721 - 88S x 722 88S, 88S-722 - 230kV 88S, 88S-723, G0 - x 723 88S, 88S-723, G8 G8 BBU x L7014 88S, L-7014 - x L7021 88S, L-7021, G0 - x L7022 88S, L-7022, G0 - x 88S-T71 88S, 88S-T71 - x 701 101S, 101S-701, G0 - x 702 101S, 101S-702, G0 - x 703 101S, 101S-703 - x 704 101S, 101S-704, G0 - x 705 101S, 101S-705, G0 - 101S x 706 101S, 101S-706, G0 - 230kV x 711 101S, 101S-711, G0 - x 712 101S, 101S-712 - x 713 101S, 101S-713 - x L7011 101S, L-7011, G0 - x L7012 101S, L-7012, G0 - x L7015 101S, L-7015 - x 811 101S, 101S-811 - 101S, 101S-812, G0 - x 812 101S, 101S-812, G5 G5 CBX Lo 101S, 101S-812, G6 G6 CBX Hi 101S, 101S-813, G0 - x 813 101S, 101S-813, G5 G5 CBX Lo 101S, 101S-813, G6 G6 CBX Hi 101S x 814 101S, 101S-814 - 345kV x 816 101S, 101S-816 - x L8006 P1 101S, ML-POLE1 - x 2 poles 101S, ML-BIPOLE - 101S, L-8004, G0 - x L8004 101S, L-8004, G5 G5 CBX Lo 101S, L-8004, G6 G6 CBX Hi x x 101S-T81 101S, 101S-T81 -

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BES/BPS Elements Load Flow Contingencies

Station Element Load Flow SPS Bkr line Bus Var Gen Xfmr

x L6515 2C, L-6515 - x L6516 2C, L-6516 - x L6517 2C, L-6517 - x L6518 2C, L-6518 - 2C 2C, L-6537, G0 - 138kV x L6537 2C, L-6537, G20 WC L6538 o/l 2C, 2C-B61, G0 - x 2C-B61 2C, 2C-B61, G20 WC L6538 o/l x 2C-B62 2C, 2C-B62 - x 710 3C, 3C-710, G0 - x 711 3C, 3C-711, G0 - x 712 3C, 3C-712, G0 - x 713 3C, 3C-713, G0 - x 714 3C, 3C-714, G0 - 3C x 715 3C, 3C-715, G0 - 230kV x 716 3C, 3C-716, G0 - x 720 3C, 3C-720, G0 - x L7003 3C, L-7003, G0 - x L7004 3C, L-7004, G0 - x L7005 3C, L-7005, G0 - x 3C-T71 3C, 3C-T71 - x 600 1N, 1N-600 - x 601 1N, 1N-601 - x 613 1N, 1N-613 - 1N x L6001 1N, L-6001 - 138kV x L6503 1N, L-6503 - x L6513 1N, L-6513 - x 1N-B61 1N, 1N-B61 - x 1N-B62 1N, 1N-B62 - x 701 67N, 67N-701, G0 - x 702 67N, 67N-702, G0 - x 703 67N, 67N-703, G0 - x 704 67N, 67N-704, G0 - x 705 67N, 67N-705, G0 - x 706 67N, 67N-706, G0 - x 710 67N, 67N-710, G0 - 67N x 711 67N, 67N-711, G0 - 230kV x 712 67N, 67N-712, G0 - x 713 67N, 67N-713, G0 - x L7001 67N, L-7001 - x L7002 67N, L-7002 - x L7018 67N, L-7018 - x L7019 67N, L-7019 - x 67N-T71 67N, 67N-T71 -

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BES/BPS Elements Load Flow Contingencies

Station Element Load Flow SPS Bkr line Bus Var Gen Xfmr

67N, 67N-811, G0 - x 811 67N, 67N-811, G5 G5 ONI Lo 67N, 67N-811, G6 G5 ONI Hi x 812 67N, 67N-812 - x 813 67N, 67N-813 - 67N, 67N-814, G0 - x 814 67N, 67N-814, NSX1 G9 NSX Lo 67N, 67N-814, NSX2 G9 NSX Hi 67N, 67N-815, G0 - 67N x 815 67N, 67N-815, NSX1 G9 NSX Lo 345kV 67N, 67N-815, NSX2 G9 NSX Hi 67N, 67N-816, G0 - x 816 67N, 67N-816, G5 G5 ONI Lo 67N, 67N-816, G6 G6 ONI Hi 67N, L-8001, G0 - x L8001 67N, L-8001, G5 G9 NSX Lo 67N, L-8001, G6 G9 NSX Hi x L8002 67N, L-8002 - x x 67N-T81 67N, 67N-T81 - 79N, 79N-601 - x 601 79N, 79N-601, G5 G5 CBX Lo 79N, 79N-601, G6 G6 CBX Hi 79N 79N, 79N-606 - 138kV x 606 79N, 79N-606, G5 G5 CBX Lo 79N, 79N-606, G6 G6 CBX Hi x L6507 79N, L-6507 - x L6508 79N, L-6508 - 79N, 79N-803, G0 - x 803 79N, 79N-803, G5 G5 CBX Lo 79N, 79N-803, G6 G6 CBX Hi 79N, 79N-810, G0 - x 810 79N, 79N-810, G5 G5 CBX Lo 79N 79N, 79N-810, G6 G6 CBX Hi 345kV 79N, L-8003, G0 - x L8003 79N, L-8003, G5 G5 ONI Lo 79N, L-8003, G6 G6 ONI Hi 79N, 79N-T81, G0 - x x 79N-T81 79N, 79N-T81, G5 G5 CBX Lo 79N, 79N-T81, G6 G6 CBX Hi x 701 91N, 91N-701 - 91N x 702 91N, 91N-702 - 230kV x 703 91N, 91N-703 - x 91N-B71 91N, 91N-B71 -

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BES/BPS Elements Load Flow Contingencies

Station Element Load Flow SPS Bkr line Bus Var Gen Xfmr

x L6507_L6508 DCT, L-6507][L-6508 - x L6534_L7021 DCT, L-6534][L-7021 - DCT, L-7003][L-7004, G0 - DCT x L7003_L7004 DCT, L-7003][L-7004, G3 G4 BBU 1 x L7008_L7009 DCT, L-7008][L-7009 - x L7009_L8002 DCT, L-7009][L-8002 -

Table 5: Steady State Contingencies

3.2.3 Steady-State Evaluation The Network Upgrades associated with the Maritime Link are sufficient to permit the existing ERIS designated transmission connected wind farms to operate in a similar manner to NRIS facilities. None of the contingencies listed in Table 3 resulted in thermal or voltage violations. As such, no additional upgrades are required to accept their full output under normal and first contingency conditions once the ML facilities are installed.

3.3 Stability Analysis Design criteria require the system to be stable and well damped in all modes of oscillations. The peak values of any mode of oscillation must decay to a value that is 60% less than the original amplitude over any 10 second period.

3.3.1 Stability Base Cases Each of the cases identified in Section 3.2.1 in Table 4 for Steady State analysis were also analysed for stability using contingencies that provide the best measure of system reliability.

3.3.2 Stability Contingencies The stability analysis included the contingencies listed in Table 6.

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Elements 2021 Dynamics Contingencies

Station Element Dynamics SPS Bkr Var line Bus Gen Xfmr

x 713 88S BBU 88S-713 - x 720 88S BBU 88S-720 - x 721 88S BBU 88S-721 - 88S x 722 88S BBU 88S-722 - 230kV x 723 88S BBU 88S-723 G0 - x L7014 88S L7014 3PH Fault - x L7021 88S L7021 3PH Fault - x L7022 88S L7022 3PH Fault - x 701 101S BBU 101S-701 G0 - x 702 101S BBU 101S-702 G0 - x 706 101S BBU 101S-706 - x 712 101S BBU 101S-712 - 101S x L7011 101S L7011 3PH Fault G0 - 230kV x L7012 101S L7012 3PH Fault G0 - x L7014 101S L7014 3PH Fault - x L7021 101S L7021 3PH Fault - x L7022 101S L7022 3PH Fault - x 811 101S BBU 101S-811 - 101S BBU 101S-812 G0 - x 812 101S BBU 101S-812 G5 G5 CBX Lo 101S BBU 101S-812 G6 G6 CBX Hi 101S BBU 101S-813 G0 - 101S x 813 101S BBU 101S-813 G5 G5 CBX Lo 345kV 101S BBU 101S-813 G6 G6 CBX Hi x 2 poles 101S, MLBIPOLE - 101S L8004 3PH Fault G0 - x L8004 101S L8004 3PH Fault G5 G5 CBX Lo 101S L8004 3PH Fault G6 G6 CBX Hi 2C 138kV x 2C-B62 2C BUS 2C-B62 3PH Fault - x 711 3C BBU 3C-711 G0 - 3C x 715 3C BBU 3C-715 G0 - 230kV x L7005 3C L7005 3PH Fault G0 - x L7012 3C L7012 3PH Fault G0 - x 600 1N BKR 1N-600 1P - x 601 1N BKR 1N-601 - 1N x 613 1N BBU 1N-613 - 138kV x L6001 1N L6001 3PH Fault - x L6503 1N L6503 3PH Fault - x L6513 1N L6513 3PH Fault -

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Elements 2021 Dynamics Contingencies

Station Element Dynamics SPS Bkr Var line Bus Gen Xfmr

x 711 67N BBU 67N-711 - x 712 67N BBU 67N-712 - 67N x 713 67N BBU 67N-713 - 230kV x L7005 67N L7005 3PH Fault G0 - L7005 67N BBU 67N-811 G0 - x L7018 67N L7005 3PH Fault G3 - 67N BBU 67N-811 G5 G5 ONI Lo x 811 67N L7018 3PH Fault - 67N BBU 67N-811 G6 G5 ONI Hi x 813 67N BBU 67N-813 - 67N BBU 67N-814 G0 - x 814 67N BBU 67N-814 NSX1 G9 NSX Lo 67N BBU 67N-814 NSX2 G9 NSX Hi 67N 67N L8001 3PH Fault G0 - 345kV 67N L8001 3PH Fault NSX1 G9 NSX Lo x L8001 67N L8001 3PH Fault NSX2 G9 NSX Hi 67N L8001 3PH Fault NSI G10 NSI x L8002 67N L8002 3PH Fault - 67N L8003 3PH Fault G0 - x L8003 67N L8003 3PH Fault G5 G5 ONI Lo 67N L8003 3PH Fault G6 G6 ONI Hi 79N BBU 79N-601 G0 - 79N x 601 79N BBU 79N-601 G5 G5 CBX Lo 138kV 79N BBU 79N-601 G6 G6 CBX Hi x L6507 79N L6507 3PH Fault - 79N BBU 79N-803 G0 - x 803 79N BBU 79N-803 G5 G5 CBX Lo 79N BBU 79N-803 G6 G6 CBX Hi 79N BBU 79N-810 G0 - x 810 79N BBU 79N-810 G5 G5 CBX Lo 79N BBU 79N-810 G6 G6 CBX Hi 79N L8003 3PH Fault G0 - 79N x L8003 79N L8003 3PH Fault G5 G5 ONI Lo 345kV 79N L8003 3PH Fault G6 G6 ONI Hi 79N L8004 3PH Fault G0 - x L8004 79N L8004 3PH Fault G5 G5 CBX Lo 79N L8004 3PH Fault G6 G6 CBX Hi 79N T81 HV Fault G0 - x 79N-T81 79N T81 HV Fault G5 G5 CBX Lo 79N T81 HV Fault G6 G6 CBX Hi

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Elements 2021 Dynamics Contingencies

Station Element Dynamics SPS Bkr Var line Bus Gen Xfmr

x L6507_L6508 DCT L6507][L6508 79N - x L6534_L7021 DCT L6534][L7021 - Dbl Cct x L7003_L7004 DCT L7003][L7004 G0 - TOWERS x L7008_L7009 DCT L7008][L7009 - x L7009_L8002 DCT L7009][L8002 - x L3006 410N L3006 3PH Fault - NB 410N x L8001 410N L8001 3PH Fault -

Table 6: Dynamic Contingencies

3.3.3 Stability Evaluation All contingencies were found to be stable and well damped. A summary of the contingency results is included in Appendix F. PSS®E plotted output files for each contingency can be found in Appendices G through I.

4.0 Resource Adequacy

The analysis of Section 3 of this report indicates that ERIS designated transmission interconnected wind generation facilities may be included with the NRIS facilities in the calculation of Resource Adequacy from a system capacity point of view. In other words, at current levels of transmission service and transmission & distribution connected generation, the addition of the Maritime Link Network Upgrades has removed the transmission constraints that would have prevented the full output of the ERIS designated facilities under normal and first contingency conditions.

This study does not attempt to dictate what the overall acceptable level of ELCC contribution should be from the existing transmission and distribution wind on the NSPI system. Two methods of determining this value are currently under review by NSPI and these are presented in Section 8 of the 2017 10 Year System Outlook report, as posted on the NSPI OASIS site at...

http://oasis.nspower.ca/en/home/oasis/forecasts-and-assessments.aspx

A summary of these two methods taken from the 10 Year System Outlook Report is included below.

Analysis of Currently Planned Levels of Variable Generation

NS Power continues to evaluate the coincidence of wind generation with peak load on an annual basis to better understand the Effective Load Carrying Capability (ELCC) or capacity value of wind assets on the NS Power system by completing studies using available data and both the LOLE and Cumulative Frequency Analysis (CFA) methodologies.

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Loss of Load Expectation (LOLE):

The LOLE methodology is a long standing utility industry standard for planning reserve margin assessment, which can be adapted to assess the capacity value of wind. This calculation is completed using the Probabilistic Assessment of System Adequacy (PASA) module of Plexos, and takes into account hourly actual wind, hourly actual load, generator capacities, and forced outage rates. The advantages of this methodology are that the calculation practices are well-established and the computation considers not just the coincidence of peak load and wind generation, but also the impact of the amount of wind generation proportional to the system (exhibiting declining capacity factor with higher penetration levels of wind). The main disadvantage of the LOLE approach is that the results can vary significantly year over year. As discussed in the 2016 10 Year System Outlook, the International Energy Agency (IEA) Wind Task Final Report recommends that between 10 and 30 years of wind and load data is required to establish a reliable ELCC of wind generation using LOLE calculations.

Cumulative frequency Analysis

NS Power’s Cumulative Frequency Analysis assessment of the ELCC of wind generation provides a second method of quantifying the capacity value of wind on the NS Power system. This technique analyzes a set of historical data points, in this case hourly wind generation and load, to determine how often a particular value is exceeded (e.g. wind correlation to peak). The objective of the analysis is to determine what minimum capacity factor of wind we can predict to be available to the NS Power system in peak hours, with corresponding certainty. Other jurisdictions including CAISO (California Independent System Operator), BPA (Bonneville Power Administration), and SPP (South West Power Pool) use variations of this approach. The CFA is completed using Excel and Oracle’s Crystal Ball software, and takes into account hourly actual wind and hourly actual load, in the top 10 percent of peak demand periods. The advantage of this method is that the analysis is conducted on a top percentile of peak hours, focusing results on key hours for reliability. The disadvantages of the method are that it does not consider the proportion of wind relative to the system, and adjacent peaks can produce skewed results in either direction.

Until NS Power gains multi-year operating experience with approximately 600 MW of wind generation, in order to acquire sufficient data to reliably estimate the ELCC of wind generation in Nova Scotia, there could be a risk to system reliability if the capacity value of wind generation is overstated. This is particularly true given the relatively large installed wind capacity on the NS Power system...

The report notes that the ELCC of wind generation based on the multi-year LOLE methodology varies from 15 to 28 percent depending on the study year, based on the presently contracted level of in-province wind generation (~600 MW). The ELCC of wind generation based on the Cumulative Frequency Methodology estimates the capacity value of wind at approximately 8%, with a 90% confidence level.

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The 2017 10-Year System Outlook Report also states in Section 8.3 that...

...Loss of Load Expectation is a robust methodology for calculating wind capacity value; however, as 10 to 30 years of data is recommended for accuracy, the Cumulative Frequency Analysis provides important Validation of LOLE results with a focus on reliability. As noted above, further wind generation data at the 600 MW level will need to be studied to produce a more reliable estimate of wind generation capacity value. Incremental wind above the currently planned levels will have a declining capacity value on the system.

ELCC of Wind Generation using Cumulative Frequency Methodology

For the Resource Adequacy Assessment in Section 8 of this report, NS Power continued to use a wind capacity value of 17 percent for NRIS and 0 percent for ERIS resources (averaging to 12 percent overall ELCC of Nova Scotia wind generation resources). NS Power will continue to monitor the system as the additional planned variable COMFIT generation comes online and more experience is gained with an elevated wind penetration.

At current levels of wind penetration of approximately 610MW, (Transmission: 423MW1; Distribution: 185MW), an 8% ELCC would result in 48.8MW of capacity contribution.

5.0 System Requirements

The analysis of Section 3 determined that the Network Upgrades associated with the Maritime Link project were sufficient to enable the existing ERIS designated generating facilities to operate in a manner similar to NRIS facilities. As such, no additional Network Upgrades are required.

It should be noted that a formal request by a facility owner to transition an existing ERIS generating facility to NRIS would incur study costs identified in the Generator Interconnection Procedures (GIP).

1 The NSPI System Operator considers all wind generation within the Nova Scotia Operating Area in this analysis, as long as they supply load within the Operating Area. This would include supply to NSPI through Power Purchase Agreements and to eligible wholesale load customers through the Open Access Transmission Tariff. It does not include wind generation installed in Nova Scotia for exclusive export to other Operating Areas.

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6.0 Conclusions and Recommendations

Technical analysis, including short circuit, steady state, and stability analysis was performed. NSPI and NPCC planning criteria were applied.

The results of the analysis demonstrate the following:

 There are no thermal; voltage; or stability violations on the transmission system resulting from receipt of full output of all existing ERIS wind generation facilities connected to the NSPI transmission system under normal and first contingency conditions with the Maritime Link (ML) upgrades in service. Analysis cases included winter peak, summer peak, and light load scenarios with maximum levels of wind on the NSPI backbone system.

 Short circuit levels at all NSPI and wind generation facility substations (≥ 69 kV) were satisfactory and were confirmed to be below NSPI design criteria levels.

 All NS transmission and distribution connected wind can be included in the ELCC calculations from the perspective of transmission system capacity. Note that this study did not attempt to define what the ELCC contribution from wind generation facilities should be, as NSPI is currently studying methodologies based on Loss of Load Expectation (LOLE), and on Cumulative Frequency Analysis (CFA) to determine the appropriate ELCC value for Nova Scotia. At present, CFA analysis shows that an overall ELCC of 8% could be obtained with a confidence level of 90%. This would result in an ELCC contribution of 48.8MW based on existing wind resources of approximately 610MW.

 No additional facilities are required in order to operate existing ERIS designated facilities in the same manner as existing NRIS facilities.

 Analysis of wind generation includes all facilities under the jurisdiction of the NSPI System Operator, not just facilities with a power purchase agreement with NSPI.

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Appendix A

Transmission Connected Wind Farms: 1-Line Diagrams

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Appendix B

Short Circuit Levels

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Maximum Short Circuit Level NO BUS KV Max Amps X/R Max MVA 199010 2S-VJ 69 10958.3 7.9 1310 199011 84S-VJ_DIST 69 10353.8 6.6 1237 199012 4S-TOWNSEND 69 8402.6 4.8 1004 199013 6S-TERRACE 69 8148.5 5.1 974 199014 82S-WHITNEY 69 5978.7 4.1 715 199015 15S-WATRFORD 69 3491 3.2 417 199016 109S-LINWIND 69 4411.9 4.1 527 199017 6S-TERR_EXT 69 8156.7 5.3 975 199018 11S-KELTIC_D 69 3991.9 3.9 477 199019 81S-RESERVE 69 5371.8 3.7 642 199020 1S-SEABOARD 69 5234.3 3.3 626 199022 97S-DONKINRD 69 4788.1 2.9 572 199023 57S-ALBERT_B 69 2068.1 1.6 247 199026 3S-GANNON_RD 69 3358.2 5.7 401 199066 67C-WHYCOCO 69 1995.9 5.5 239 199067 9C-ABERDEEN 69 1534.4 3.8 183 199068 58C-SW_MARG 69 1078.6 3 129 199069 103C-CHETCMP 69 711.1 2.7 85 199077 4C-LOCHABER 69 1523.4 9.7 182 199078 57C-SALMON_R 69 1164.1 3.7 139 199079 24C-DICKIEBR 69 1089.5 3.4 130 199080 19C-CANSO 69 874.3 3.6 104 199091 50N-TRENTON 69 9596.3 10.8 1147 199092 62N-BRIDG_AV 69 3843.9 4.4 459 199094 0N-STELLAR 69 5276.7 3 631 199095 89H-TRAFALGR 69 1937.3 3 232 199096 88H-UP_MUSQ 69 1035.2 1.8 124 199097 95H-MALAY_FL 69 1197.7 3.6 143 199098 96H-RUTH_FLS 69 1109.2 3.3 133 199102 54N-ABERCROM 69 6153.9 5.3 735 199104 53N-KIMCLRK 69 5554.2 4.6 664 199106 56N-HALIBURT 69 4484.6 3.5 536 199107 55N-PICTOU 69 3745.6 3 448 199111 1N-ONSLOW_A 69 5311.9 16.6 635 199112 1N-ONSLOW_B 69 5356.2 11.1 640 199114 15N-WILLOWLN 69 4317.9 5.7 516 199115 11N-LAFARGE 69 2542.6 4 304 199116 16N-STEWIAKE 69 1957.3 3.3 234 199118 4N-TATAMAG 69 1466.5 3.1 175 199136 74N-SPRINGHL 69 3450 10 412

B - 1

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Maximum Short Circuit Level NO BUS KV Max Amps X/R Max MVA 199137 3N-OXFORD 69 2260.6 6.8 270 199138 7N-PUGWASH 69 1300.1 5.7 155 199139 10N-ABER_ST 69 3114.2 7 372 199141 6N-BLK_RIV 69 2755.5 5.4 329 199146 30N-MACCAN 69 3128.9 8.9 374 199147 37N-PARSBORO 69 1411.1 5.1 169 199148 75N-DOMTAR 69 2337.1 4.2 279 199149 20N-PARKST 69 2535.3 5.7 303 199151 17N-BROWNELL 69 2403.7 4.8 287 199166 91H-TUFTCOVE 69 18597 10.9 2223 199170 99H-FARRELL 69 17976.1 10.2 2148 199171 62H-ALBRO 69 13086.5 6.8 1564 199172 40H-WOODLAWN 69 7852.2 5.6 938 199173 58H-IMPERIAL 69 8427.5 4.8 1007 199175 48H-PENHORN 69 9988.9 5.1 1194 199176 54H-MAPLE_ST 69 12452.1 6.1 1488 199177 124H-AKERLEY 69 11600.8 6.4 1386 199178 90H-SACKVILL 69 10108.5 8.5 1208 199179 23H-ROCKHAM 69 4686.6 4.8 560 199180 20H-SPRYFLD 69 2182 12.7 261 199196 34H-GEIZERS 69 2468.4 27.8 295 199205 103H-LAKSIDE 69 2806.1 66.9 335 199211 87W-HUBBARDS 69 2166.8 7.7 259 199212 86W-EASTRIV 69 1893.3 5.5 226 199213 86W-MIDRIVSW 69 1563.3 4.2 187 199215 85W-CANEXEL 69 1753.6 5 210 199216 84W-ROB-SONS 69 1432.5 3.3 171 199218 75W-WESTHAVE 69 3055.8 10.8 365 199219 77W-MAHONE_T 69 2601.6 4.5 311 199220 78W-MARTINS 69 2215.6 3 265 199221 79W-LUN_SWST 69 2094.4 2.7 250 199222 81W-LUNENBUR 69 2021.8 2.5 242 199223 82W-NATIONNS 69 1833.2 2.3 219 199224 80W-INDIANNS 69 1606.7 2.4 192 199225 76W-MAHONE_B 69 2487.4 4 297 199231 99W-BRIDGEWT 69 4955.1 20.5 592 199232 89W-E_B-WATR 69 3711.5 7.5 444 199233 73W-AUBURNDA 69 4622.2 14 552 199234 73W-WILEVILL 69 4164.6 9.7 498 199235 70W-HIGHSTBW 69 3813.8 7.9 456

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2018 10 Year System Outlook Report Appendix B Page 42 of 84

Maximum Short Circuit Level NO BUS KV Max Amps X/R Max MVA 199246 50W-MILTON 69 4987.8 9.7 596 199249 4W-L_GR_BRK 69 4162.2 5.1 497 199252 3W-BIG_FALL 69 3521.5 4 421 199259 91W-MIDDLEFI 69 2421.3 2.1 289 199260 57W-CALEDONI 69 1859 1.7 222 199263 48W-WATERLOO 69 3302.1 5.1 395 199264 46W-BROADRVR 69 2901.9 2.9 347 199265 36W-GREENHBR 69 2108.2 3 252 199266 37W-LOCKPORT 69 1809.6 2.8 216 199271 30W-SOURIQUO 69 2335.6 5 279 199272 25W-SHELBURN 69 2123.5 4.4 254 199274 23W-CLYDE_RI 69 1317.6 2.9 157 199275 106W-PUBWND 69 1937 5.2 231 199276 22W-BARRINGT 69 1276.2 3.6 153 199281 9W-TUSKET 69 4461.2 6.6 533 199282 19W-ARGYLE 69 2726.1 4.8 326 199283 20W-PUBNICO 69 1961.5 5.2 234 199284 21W-WOODSHBR 69 1546.6 4.5 185 199286 10W-TUSKETGT 69 4011.7 5.4 479 199288 16W-HEBRON 69 2914.9 3.2 348 199290 11W-KING_ST 69 2292.3 2.2 274 199291 88W-PLEASANT 69 2387.1 2.3 285 199292 92W-CARLETON 69 2761.2 2.2 330 199294 88W-PLSNT_B5 69 2251.5 2.8 269 199301 17V-ST_CROIX 69 8038.6 10.3 961 199303 1V-AVON 69 2821.4 2.2 337 199307 18V-BURLINGT 69 3271.1 1.5 391 199308 17V-L5016TAP 69 6131.9 5.1 733 199309 79V-3MIPLAIN 69 5359.2 3.5 640 199310 79V-L5015TAP 69 5402 3.5 646 199311 20V-FIVE_PT 69 4735.7 3.6 566 199321 83V-WOLFVILL 69 4548.2 3.6 544 199322 43V-CANAANRD 69 6907.9 5.8 826 199323 50V-KLONDIKE 69 2882 2.3 344 199324 22V-NEWMINAS 69 4802.6 3.6 574 199325 36V-HILLATON 69 3080.2 2.8 368 199326 3V-HELS_GATE 69 4182 8.1 500 199332 6V-HOLLOW_A 69 4352.4 3.3 520 199335 92V-MICH_WAT 69 3837.1 3.8 459 199336 55V-WATERTAP 69 3743.6 3.6 447

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Maximum Short Circuit Level NO BUS KV Max Amps X/R Max MVA 199337 55V-WATERVLL 69 3535.5 3.4 423 199338 53V-BERWKTAP 69 3648.2 3.3 436 199339 52V-BERWICK 69 3326.5 3.1 398 199341 5V-LUMDEN-A 69 5541.2 4.3 662 199342 7V-METHAL-A 69 2846.8 2.6 340 199346 51V-TREMONT 69 5261.4 5.4 629 199347 64V-GREENWD 69 4526.6 4.1 541 199348 63V-KINGSTON 69 3975.7 3.8 475 199351 12V-LEQUILLE 69 2824.6 3.9 338 199352 81V-ANNAPTAP 69 2841.7 4 340 199354 70V-BRIDGTAP 69 2870.3 4.4 343 199355 70V-BRIDGTWN 69 2600.4 4.1 311 199356 11V-PARADISE 69 2975.8 4.5 356 199358 65V-MIDDLTAP 69 3864.6 4.7 462 199359 65V-MIDDLETN 69 3315.5 4.2 396 199360 10V-NICTAUX 69 3916.1 4.8 468 199362 74V-CORNWTAP 69 2612.8 3.3 312 199363 74V-CORNWLLS 69 2366 2.6 283 199364 13V-GULCH 69 2615.6 2.9 313 199366 77V-CONWAY 69 1697.3 1.9 203 199367 14V-RIDGE_HY 69 2257 2.3 270 199369 76V-MAITLAND 69 1760.9 1.8 210 199370 15V-SISSIBOO 69 2028.9 2 242 199374 16V-WEYMOUTH 69 425.2 39 51 199376 93V-SAULNIER 69 67.5 0.1 8 199581 89N_NUTBHV 69 2276.4 3.8 272 199635 102V-ELLERSH 69 6734.8 7.4 805 199710 98V-GULLCOVE 69 1281 2.1 153 199855 DC_POLE1 120 6583.4 21 1368 199857 DC_POLE2 120 6583.4 21 1368 199005 88S-LINGAN_A 138 8313.2 11.9 1987 199006 88S-LINGAN_B 138 8346.5 12.8 1995 199007 2S-VICTORIA 138 8963.9 8.5 2143 199025 3S-GANNON_RD 138 4919.6 5.3 1176 199031 5S-GLEN_TOSH 138 5517.4 6.8 1319 199033 104S-BADDECK 138 4701.9 6 1124 199035 85S-WRK_COVE 138 5674.9 12.4 1356 199051 2C-HASTINGS 138 11647.1 9.7 2784 199052 1C-TUPPER 138 9555.5 9.3 2284 199053 47C-NEW_PAGE 138 9452.2 9.1 2259

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Maximum Short Circuit Level NO BUS KV Max Amps X/R Max MVA 199056 59C-STPETERS 138 4407.2 5.4 1053 199057 67C-WHYC_TAP 138 4319.7 5.3 1033 199058 67C-WHYCOCO 138 3256 4.8 778 199063 22C-CLEVLAND 138 6951.4 6.4 1662 199075 100C-PORCUPN 138 9867.7 8.1 2359 199076 4C-LOCHABER 138 4885 4.7 1168 199090 50N-TRENTON 138 11913.7 10.1 2848 199100 49N-MICHGRAN 138 9161.8 9.5 2190 199110 1N-ONSLOW 138 9610.2 7.6 2297 199121 79N-HOPWELL 138 10560.3 11.4 2524 199134 81N-DEBERT 138 6496.3 5.7 1553 199135 74N-SPRNGHIL 138 5080.8 4.2 1214 199145 30N-MACCAN 138 4575.9 4.2 1094 199152 22N-CHURCHST 138 4323.7 4.2 1033 199154 82V-ELMSDALE 138 5314.1 5.3 1270 199156 127H-AEROTAP 138 6298.9 5.6 1506 199158 139H-DARTCRO 138 11157.5 7.1 2667 199159 132H-SPIDRLK 138 9056.3 6.7 2165 199161 113H-EASTDRT 138 9570.9 6.8 2288 199162 126H-PORTERS 138 5170.3 5.6 1236 199163 87H-MUSQ.HBR 138 3594.1 5.2 859 199165 91H-TUFTCOVE 138 15416.1 8.9 3685 199184 90H-SACKVILL 138 15033.6 7.4 3593 199185 101H-COBEQUI 138 13233.3 6.9 3163 199187 108H-BURNSID 138 13911.9 7.6 3325 199190 103H-LAKSIDE 138 12268.5 7.6 2932 199192 129H-KEARNEY 138 8762.2 7.3 2094 199193 1H-WATER_ST 138 10018.6 6.6 2395 199198 104H-KEMPT_R 138 12019.1 7.8 2873 199201 120H-BRUSHY 138 14360.9 8.1 3433 199204 92H-TIDEWTR 138 4945.8 4.6 1182 199208 137H-HAMMNDS 138 9815.3 8.3 2346 199210 87W-HUBBARDS 138 3718.6 4.3 889 199214 103W-GOLD_RV 138 2509.1 4.2 600 199217 75W-WESTHAVE 138 4346.5 6.9 1039 199228 74W-MICHBWTP 138 5873.7 9.7 1404 199229 74W-MICH_B-W 138 5564.7 9 1330 199230 99W-BRIDGEWT 138 5882.3 9.8 1406 199245 50W-MILTON 138 4863.3 9.1 1162 199270 30W-SOURIQUO 138 2365.4 4.4 565

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Maximum Short Circuit Level NO BUS KV Max Amps X/R Max MVA 199277 101W-BMPC 138 4398.7 9 1051 199280 9W-TUSKET_A 138 1908.2 8.4 456 199287 9W-TUSKET_B 138 1869.5 5.3 447 199298 104W-BROOKLY 138 4421.8 9 1057 199300 17V-ST_CROIX 138 7957.2 6.8 1902 199333 99V-HIGHBURY 138 4871.7 5 1164 199340 43V-CANAANRD 138 5342.3 5.2 1277 199345 51V-TRMT_B61 138 3561.3 4.8 851 199501 110W-S_CANOE 138 3720.8 5.7 889 199530 92N-AMHSTWIN 138 4708 4.2 1125 199610 93N-GLENDHU 138 5111.4 5 1222 199000 88S-LINGAN 230 9194.7 13.6 3663 199042 101S-WOODBIN 230 9442.3 13.1 3762 199044 89S-PT_ACONI 230 4634.8 13.3 1846 199050 3C-HASTINGS 230 8033.9 8.9 3200 199130 67N-ONSLOW 230 10520.8 8.6 4191 199200 120H-BRUSHY 230 8652.5 8.3 3447 199240 99W-BWATER_A 230 3316.8 9.4 1321 199241 99W-BWATER_B 230 3859.8 10.4 1538 199590 91N-DALHOUS 230 5787.9 6.9 2306 199045 101S-WOODBIN 345 5424.5 15.4 3241 199120 79N-HOPWELL 345 5890.3 10.7 3520 199125 67N-ONSLOW 345 7276.4 8.9 4348 199195 103H-LAKSIDE 345 4309.1 9.7 2575

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2017 NRIS Wind Study

Appendix C

Distributed Generation – Bus Load Adjustments

2018 10 Year System Outlook Report Appendix B Page 47 of 84

PSSe Load Data % Distributed Generation (x) 70%

PSS/e Load Data 2021LL Case Distribution Generation (MW) Net MW at Est Mvar Bus # Bus Name MW Mvar Wind Biogas Biomass Hydro Tidal Total x% 199001 88S-LINGAN_114.400 8.1 4.1 0.0 8.1 4.10 199002 88S-LINGAN_214.400 7.8 4 0.0 7.8 4.00 199003 88S-LINGAN_314.400 8.2 4.2 0.0 8.2 4.20 199004 88S-LINGAN_414.400 8 4.1 0.00 8.0 4.10 199011 84S-VJ_DIST 69.000 2.71 1.47 2.3 2.30 1.1 0.71 199012 4S-TOWNSEND 69.000 10.65 5.78 0.00 10.7 5.78 199013 6S-TERRACE 69.000 1.76 0.73 0.00 1.8 0.73 199014 82S-WHITNEY 69.000 2.15 0.26 2.35 2.35 0.5 0.22 199015 15S-WATRFORD69.000 1.5 0.57 2.35 2.35 0.0 0.18 199018 11S-KELTIC_D69.000 11.3 4.71 4 4.00 8.5 3.35 199019 81S-RESERVE 69.000 9.73 3.09 4.8 4.80 6.4 1.95 199023 57S-ALBERT_B69.000 2.63 0.84 2.3 2.30 1.0 0.58 199026 3S-GANNON_RD69.000 9.74 1.65 6.35 6.35 5.3 1.08 199033 104S-BADDECK138.00 1.77 0.47 1.7 1.70 0.6 0.37 199035 85S-WRK_COVE138.00 1.81 0.47 0.00 1.8 0.47 199043 102S-ACONI 20.000 14.2 7.3 0.00 14.2 7.30 199051 2C-HASTINGS 138.00 1.51 0.22 2 2.00 0.1 0.18 199052 1C-TUPPER 138.00 0.43 0.09 0.00 0.4 0.09 199054 47C-NEW_PAGE13.800 33.6 21 0.00 33.6 21.00 199055 1C-TUPPER_GN14.400 6 2 0.00 6.0 2.00 199056 59C-STPETERS138.00 1.02 0.21 0.00 1.0 0.21 199058 67C-WHYCOCO 138.00 2.45 0.07 1.7 1.70 1.3 0.07 199060 47C-NP_PMP2 13.800 32.3 19 0.00 32.3 19.00 199063 22C-CLEVLAND138.00 4.51 0.91 1.99 1.99 3.1 0.83 199065 47C-NP_RL3 13.800 10.6 7.5 0.00 10.6 7.50 199067 9C-ABERDEEN 69.000 0.23 0.01 0.00 0.2 0.01 199068 58C-SW_MARG 69.000 2.77 0.08 2 2.00 1.4 0.08 199069 103C-CHETCMP69.000 1.16 0.03 1.6 1.60 0.0 0.03 199075 100C-PORCUPN138.00 4.16 1.53 0.23 0.23 4.0 1.53 199076 4C-LOCHABER 138.00 5.51 2.3 10.6 0.5 11.10 0.0 0.00 199077 4C-LOCHABER 69.000 0 0 0.00 0.0 0.00 199078 57C-SALMON_R69.000 1.51 0.47 0.00 1.5 0.47 199080 19C-CANSO 69.000 0.39 0.19 0.00 0.4 0.19 199082 24C-DICKIEBR25.000 1.34 0.24 0.00 1.3 0.24 199085 50N-TRENTON518.000 7.8 4.1 0.00 7.8 4.10 199086 50N-TRENTON613.800 7.2 3.7 0.00 7.2 3.70 199091 50N-TRENTON 69.000 7.21 1.21 7.8 7.80 1.8 0.37 199091 50N-TRENTON 69.000 2.2 2.71 0.00 2.2 2.71 199092 62N-BRIDG_AV69.000 7.6 3.3 13.2 13.20 0.0 0.00 199096 88H-UP_MUSQ 69.000 1.71 0.74 1.1 1.10 0.9 0.74 199096 88H-UP_MUSQ 69.000 1.46 1.5 0.00 1.5 1.50 199098 96H-RUTH_FLS69.000 1.19 0.52 1.5 1.50 0.1 0.31 199100 49N-MICHGRAN138.00 11.37 3.08 0.00 11.4 3.08 199105 53N-NRT PULP13.800 25 3 0.00 25.0 3.00 199106 56N-HALIBURT69.000 3.07 1.33 3 3.00 1.0 0.50 199106 56N-HALIBURT69.000 0 0 0.00 0.0 0.00 199107 55N-PICTOU 69.000 1.33 0.58 0.00 1.3 0.58 199110 1N-ONSLOW 138.00 7.06 1.33 5 1 6.00 2.9 0.90 199111 1N-ONSLOW_A 69.000 3.65 1.78 0.00 3.7 1.78 199112 1N-ONSLOW_B 69.000 2.31 0.13 0.00 2.3 0.13

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PSSe Load Data % Distributed Generation (x) 70%

PSS/e Load Data 2021LL Case Distribution Generation (MW) Net MW at Est Mvar Bus # Bus Name MW Mvar Wind Biogas Biomass Hydro Tidal Total x% 199114 15N-WILLOWLN69.000 11.2 4.29 13.8 13.80 1.5 0.00 199114 15N-WILLOWLN69.000 3.19 0 0.00 3.2 0.00 199114 15N-WILLOWLN69.000 0.27 0.15 0.00 0.3 0.15 199115 11N-LAFARGE 69.000 3.59 1.2 0.00 3.6 1.20 199116 16N-STEWIAKE69.000 0.95 0.28 0.5 0.50 0.6 0.28 199118 4N-TATAMAG 69.000 2.28 0.57 1.6 1.60 1.2 0.49 199134 81N-DEBERT 138.00 4.15 2.08 3.6 3.60 1.6 0.48 199136 74N-SPRINGHL69.000 5.46 0.7 0.00 5.5 0.70 199137 3N-OXFORD 69.000 2.47 1.26 0.00 2.5 1.26 199137 3N-OXFORD 69.000 0.47 0.19 0.00 0.5 0.19 199138 7N-PUGWASH 69.000 1.42 0.47 0.00 1.4 0.47 199138 7N-PUGWASH 69.000 1.1 0.05 0.00 1.1 0.05 199141 6N-BLK_RIV 69.000 2.15 0.87 1.2 1.20 1.3 0.75 199141 6N-BLK_RIV 69.000 1.76 0.96 0.00 1.8 0.96 199146 30N-MACCAN 69.000 0.76 0.28 0.00 0.8 0.28 199147 37N-PARSBORO69.000 1.93 0.57 0.00 1.9 0.57 199147 37N-PARSBORO69.000 0.14 0.14 0.00 0.1 0.14 199148 75N-DOMTAR 69.000 3 0.74 0.00 3.0 0.74 199149 20N-PARKST 69.000 0.61 0.13 0.00 0.6 0.13 199151 17N-BROWNELL69.000 0.76 0.16 0.00 0.8 0.16 199152 22N-CHURCHST138.00 9.63 2.84 6 6.00 5.4 1.31 199153 139H_25KV 25.000 9.7 4.3 2 2.00 8.3 3.91 199155 82V-ELMSDALE26.400 11.27 3.18 10 1.1 11.10 3.5 0.00 199155 82V-ELMSDALE26.400 0.44 0.25 0.00 0.4 0.25 199155 82V-ELMSDALE26.400 0.3 0 0.00 0.3 0.00 199155 82V-ELMSDALE26.400 0.23 0.08 0.00 0.2 0.08 199156 127H-AEROTAP138.00 6.79 1.89 0.5 0.50 6.4 1.89 199156 127H-AEROTAP138.00 1.71 0.25 0.00 1.7 0.25 199157 133H-HBR EST138.00 4.74 1.7 0.00 4.7 1.70 199160 113H-EASTDRT25.000 17.53 5.02 0.00 17.5 5.02 199162 126H-PORTERS138.00 3.7 0.29 3.2 3.20 1.5 0.26 199163 87H-MUSQ.HBR138.00 2.36 0.18 2.3 2.30 0.8 0.16 199167 91H-TUFTCV1 13.800 4.1 1.3 0.00 4.1 1.30 199168 91H-TUFTCV2 13.800 3.7 1.2 0.00 3.7 1.20 199169 91H-TUFTCV3 14.400 8 4 0.00 8.0 4.00 199170 99H-FARRELL 69.000 4.28 1.36 0.00 4.3 1.36 199171 62H-ALBRO 69.000 3.17 0.89 0.00 3.2 0.89 199172 40H-WOODLAWN69.000 4.18 0.09 0.00 4.2 0.09 199173 58H-IMPERIAL69.000 6.16 1.23 0.00 6.2 1.23 199174 58H-IMPERIAL26.400 8.97 2.84 0.00 9.0 2.84 199175 48H-PENHORN 69.000 7.58 2.84 0.00 7.6 2.84 199176 54H-MAPLE_ST69.000 5.01 3.27 0.00 5.0 3.27 199177 124H-AKERLEY69.000 2.27 0.94 0.00 2.3 0.94 199179 23H-ROCKHAM 69.000 7.08 2.37 0.00 7.1 2.37 199180 20H-SPRYFLD 69.000 10.44 3.79 4.6 4.60 7.2 2.42 199186 101H-COBEQUI26.400 17.3 6.39 0.00 17.3 6.39 199187 108H-BURNSID138.00 6.68 3.44 0.00 6.7 3.44 199191 103H-LAKSIDE26.400 14.05 4.74 7.05 7.05 9.1 1.97 199192 129H-KEARNEY138.00 9.62 3.33 0.00 9.6 3.33 199194 1H-WATER_ST 26.400 27.35 9.06 0.00 27.4 9.06

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PSSe Load Data % Distributed Generation (x) 70%

PSS/e Load Data 2021LL Case Distribution Generation (MW) Net MW at Est Mvar Bus # Bus Name MW Mvar Wind Biogas Biomass Hydro Tidal Total x% 199194 1H-WATER_ST 26.400 2.55 1.04 0.00 2.6 1.04 199194 1H-WATER_ST 26.400 0.25 0.04 0.00 0.3 0.04 199197 2H-ARMDALE 138.00 14.53 4.74 0.00 14.5 4.74 199199 104H-KEMPT_R26.400 38.95 13.23 0.00 39.0 13.23 199199 104H-KEMPT_R26.400 0.81 0.3 0.00 0.8 0.30 199199 104H-KEMPT_R26.400 0.36 0.07 0.00 0.4 0.07 199203 131H-LUCASVL138.00 11.18 3.88 8 2.1 3.1 13.20 1.9 0.10 199206 92H-TIDEWTR 13.200 3.13 1.42 0.00 3.1 1.42 199209 137H-HAMONDS26.470 7.51 2.24 10 10.00 0.5 0.00 199210 87W-HUBBARDS138.00 1.56 0.31 0.00 1.6 0.31 199214 103W-GOLD_RV138.00 2.97 0.59 0.00 3.0 0.59 199215 85W-CANEXEL 69.000 1.15 0.28 0.00 1.2 0.28 199216 84W-ROB-SONS69.000 1.81 0.36 2 2.00 0.4 0.28 199220 78W-MARTINS 69.000 0.68 0.28 0.00 0.7 0.28 199222 81W-LUNENBUR69.000 1.49 0.47 0.00 1.5 0.47 199223 82W-NATIONNS69.000 0.96 0.2 0.00 1.0 0.20 199224 80W-INDIANNS69.000 1.87 0.57 0.00 1.9 0.57 199225 76W-MAHONE_B69.000 0.57 0.19 0.00 0.6 0.19 199229 74W-MICH_B-W138.00 12.78 6.35 0.00 12.8 6.35 199229 74W-MICH_B-W138.00 1.89 0.85 0.00 1.9 0.85 199232 89W-E_B-WATR69.000 3.65 1.06 4 4.00 0.9 0.40 199233 73W-AUBURNDA69.000 2.59 0.95 0.85 0.85 2.0 0.95 199235 70W-HIGHSTBW69.000 6.3 1.89 3.2 3.20 4.1 1.44 199246 50W-MILTON 69.000 3.52 1.03 3.6 3.60 1.0 0.49 199259 91W-MIDDLEFI69.000 0.78 0.39 0.00 0.8 0.39 199260 57W-CALEDONI69.000 0.68 0.34 0.00 0.7 0.34 199263 48W-WATERLOO69.000 1.99 1.37 0.00 2.0 1.37 199264 46W-BROADRVR69.000 0.87 0.28 0.00 0.9 0.28 199265 36W-GREENHBR69.000 0.65 0.19 0.00 0.7 0.19 199266 37W-LOCKPORT69.000 0.41 0.09 0.00 0.4 0.09 199272 25W-SHELBURN69.000 5.88 1.89 0.00 5.9 1.89 199274 23W-CLYDE_RI69.000 3.17 0.61 0.00 3.2 0.61 199276 22W-BARRINGT69.000 2.91 0.82 3.2 3.20 0.7 0.42 199277 101W-BMPC 138.00 0.85 0.28 0.00 0.9 0.28 199282 19W-ARGYLE 69.000 1.09 0.31 0.00 1.1 0.31 199283 20W-PUBNICO 69.000 0.68 0.19 0.00 0.7 0.19 199284 21W-WOODSHBR69.000 0.64 0.18 0.00 0.6 0.18 199286 10W-TUSKETGT69.000 2.48 0.25 0.00 2.5 0.25 199288 16W-HEBRON 69.000 2.24 0.47 2 2.00 0.8 0.38 199290 11W-KING_ST 69.000 1.31 0.25 0.00 1.3 0.25 199291 88W-PLEASANT69.000 4.08 0.78 4 4.00 1.3 0.49 199292 92W-CARLETON69.000 0.33 0.09 0.00 0.3 0.09 199294 88W-PLSNT_B569.000 3.26 1.14 0.00 3.3 1.14 199303 1V-AVON 69.000 1 0.04 0.00 1.0 0.04 199307 18V-BURLINGT69.000 1.93 0.47 2 2.00 0.5 0.35 199309 79V-3MIPLAIN69.000 6.7 2.13 6 6.00 2.5 0.35 199311 20V-FIVE_PT 69.000 0.93 0.37 0.00 0.9 0.37 199313 41V-MBPP 23.000 3.22 3.25 0.00 3.2 3.25 199321 83V-WOLFVILL69.000 3.21 1.14 0.00 3.2 1.14 199323 50V-KLONDIKE69.000 6.99 1.89 6 6.00 2.8 1.89

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2018 10 Year System Outlook Report Appendix B Page 50 of 84

PSSe Load Data % Distributed Generation (x) 70%

PSS/e Load Data 2021LL Case Distribution Generation (MW) Net MW at Est Mvar Bus # Bus Name MW Mvar Wind Biogas Biomass Hydro Tidal Total x% 199324 22V-NEWMINAS69.000 8 1.85 0.00 8.0 1.85 199325 36V-HILLATON69.000 3 0.69 0.00 3.0 0.69 199325 36V-HILLATON69.000 0.27 0.21 0.00 0.3 0.21 199329 45V-ACADIA 23.000 0.45 0.05 0.00 0.5 0.05 199333 99V-HIGHBURY138.00 3.79 1.23 0.00 3.8 1.23 199335 92V-MICH_WAT69.000 8.22 2.14 0.00 8.2 2.14 199337 55V-WATERVLL69.000 4.78 1.61 0.00 4.8 1.61 199339 52V-BERWICK 69.000 1.54 0.47 0.00 1.5 0.47 199346 51V-TREMONT 69.000 1.42 0.68 0.00 1.4 0.68 199347 64V-GREENWD 69.000 2.39 0.38 0.00 2.4 0.38 199348 63V-KINGSTON69.000 4.24 0.67 0.00 4.2 0.67 199351 12V-LEQUILLE69.000 2.21 0.6 2 2.00 0.8 0.46 199355 70V-BRIDGTWN69.000 2.38 0.65 0.00 2.4 0.65 199359 65V-MIDDLETN69.000 2.62 0.95 0.00 2.6 0.95 199363 74V-CORNWLLS69.000 0.64 0.18 0.00 0.6 0.18 199365 13V-GULCH 13.800 1.15 0.16 0.00 1.2 0.16 199366 77V-CONWAY 69.000 4.52 0.38 1.7 2 3.70 1.9 0.37 199369 76V-MAITLAND69.000 0.15 0.08 0.00 0.2 0.08 199374 16V-WEYMOUTH69.000 0.97 0.98 0.3 0.30 0.8 0.98 199376 93V-SAULNIER69.000 3.82 1.23 0.6 0.60 3.4 1.21 199376 93V-SAULNIER69.000 0.85 0.19 0.00 0.9 0.19 199690 1C-TUPPER 25.000 2.95 1.72 0.8 0.80 2.4 1.61 199690 1C-TUPPER 25.000 0.6 0.2 0.00 0.6 0.20 199690 1C-TUPPER 25.000 0.06 0.07 0.00 0.1 0.07 Totals 810.06 295.67 184.99 4.43 11.5 1.35 2 204.27 671.12 256.94

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2018 10 Year System Outlook Report Appendix B Page 51 of 84

PSSe Load Data % Distributed Generation (x) 70%

PSS/e Load Data 2021SUM Case Distribution Generation (MW) Net MW at Est Mvar Bus # Bus Name MW Mvar Wind Biogas Biomass Hydro Tidal Total x% 199001 88S-LINGAN_114.400 8.10 4.10 0.0 8.1 4.10 199002 88S-LINGAN_214.400 7.80 4.00 0.0 7.8 4.00 199003 88S-LINGAN_314.400 8.20 4.20 0.0 8.2 4.20 199004 88S-LINGAN_414.400 8.00 4.10 0.00 8.0 4.10 199011 84S-VJ_DIST 69.000 6.61 2.97 2.3 2.30 5.0 2.45 199012 4S-TOWNSEND 69.000 26.03 11.69 0.00 26.0 11.69 199013 6S-TERRACE 69.000 3.77 1.73 0.00 3.8 1.73 199014 82S-WHITNEY 69.000 4.64 0.93 2.35 2.35 3.0 0.82 199015 15S-WATRFORD69.000 6.81 1.46 2.35 2.35 5.2 1.34 199018 11S-KELTIC_D69.000 24.21 11.08 4 4.00 21.4 9.44 199019 81S-RESERVE 69.000 5.18 7.43 4.8 4.80 1.8 0.00 199023 57S-ALBERT_B69.000 1.40 2.01 2.3 2.30 0.0 0.00 199026 3S-GANNON_RD69.000 18.35 5.02 6.35 6.35 13.9 3.54 199033 104S-BADDECK138.00 3.87 1.05 1.7 1.70 2.7 0.95 199035 85S-WRK_COVE138.00 2.23 1.32 0.00 2.2 1.32 199043 102S-ACONI 20.000 14.20 7.30 0.00 14.2 7.30 199051 2C-HASTINGS 138.00 3.19 0.76 2 2.00 1.8 0.65 199052 1C-TUPPER 138.00 0.97 0.00 0.00 1.0 0.00 199054 47C-NEW_PAGE13.800 33.60 21.00 0.00 33.6 21.00 199055 1C-TUPPER_GN14.400 6.00 2.00 0.00 6.0 2.00 199056 59C-STPETERS138.00 2.09 0.60 0.00 2.1 0.60 199058 67C-WHYCOCO 138.00 5.34 1.45 1.7 1.70 4.2 1.35 199060 47C-NP_PMP2 13.800 32.30 19.00 0.00 32.3 19.00 199063 22C-CLEVLAND138.00 9.25 2.65 1.99 1.99 7.9 2.49 199065 47C-NP_RL3 13.800 10.60 7.50 0.00 10.6 7.50 199067 9C-ABERDEEN 69.000 0.50 0.14 0.00 0.5 0.14 199068 58C-SW_MARG 69.000 6.05 1.64 2 2.00 4.7 1.50 199069 103C-CHETCMP69.000 2.52 0.69 1.6 1.60 1.4 0.60 199075 100C-PORCUPN138.00 6.46 4.79 0.23 0.23 6.3 4.79 199076 4C-LOCHABER 138.00 23.97 7.26 10.6 0.5 11.10 16.2 2.21 199077 4C-LOCHABER 69.000 0.00 0.00 0.00 0.0 0.00 199078 57C-SALMON_R69.000 3.17 -0.62 0.00 3.2 -0.62 199080 19C-CANSO 69.000 0.83 -0.16 0.00 0.8 -0.16 199082 24C-DICKIEBR25.000 2.81 -0.55 0.00 2.8 -0.55 199085 50N-TRENTON518.000 7.80 4.10 0.00 7.8 4.10 199086 50N-TRENTON613.800 7.20 3.70 0.00 7.2 3.70 199091 50N-TRENTON 69.000 15.33 4.60 7.8 7.80 9.9 1.92 199091 50N-TRENTON 69.000 3.62 3.65 0.00 3.6 3.65 199092 62N-BRIDG_AV69.000 21.15 12.03 13.2 13.20 11.9 0.00 199096 88H-UP_MUSQ 69.000 4.75 2.70 1.1 1.10 4.0 2.70 199096 88H-UP_MUSQ 69.000 0.00 0.00 0.00 0.0 0.00 199098 96H-RUTH_FLS69.000 3.32 1.89 1.5 1.50 2.3 1.53 199100 49N-MICHGRAN138.00 19.89 8.86 0.00 19.9 8.86 199105 53N-NRT PULP13.800 25.00 4.68 0.00 25.0 4.68 199106 56N-HALIBURT69.000 7.60 2.73 3 3.00 5.5 2.16 199106 56N-HALIBURT69.000 1.17 1.15 0.00 1.2 1.15 199107 55N-PICTOU 69.000 3.29 1.18 0.00 3.3 1.18 199110 1N-ONSLOW 138.00 14.38 4.34 5 1 6.00 10.2 3.22 199111 1N-ONSLOW_A 69.000 6.93 3.47 0.00 6.9 3.47 199112 1N-ONSLOW_B 69.000 3.85 0.57 0.00 3.9 0.57

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2018 10 Year System Outlook Report Appendix B Page 52 of 84

PSSe Load Data % Distributed Generation (x) 70%

PSS/e Load Data 2021SUM Case Distribution Generation (MW) Net MW at Est Mvar Bus # Bus Name MW Mvar Wind Biogas Biomass Hydro Tidal Total x% 199114 15N-WILLOWLN69.000 24.87 11.10 13.8 13.80 15.2 0.00 199114 15N-WILLOWLN69.000 3.13 -3.15 0.00 3.1 -3.15 199114 15N-WILLOWLN69.000 1.07 0.48 0.00 1.1 0.48 199115 11N-LAFARGE 69.000 4.78 -0.31 0.00 4.8 -0.31 199116 16N-STEWIAKE69.000 0.88 -2.31 0.5 0.50 0.5 0.00 199118 4N-TATAMAG 69.000 5.84 1.46 1.6 1.60 4.7 1.38 199134 81N-DEBERT 138.00 10.91 0.64 3.6 3.60 8.4 0.62 199136 74N-SPRINGHL69.000 4.78 1.96 0.00 4.8 1.96 199137 3N-OXFORD 69.000 2.91 0.22 0.00 2.9 0.22 199137 3N-OXFORD 69.000 2.85 1.48 0.00 2.9 1.48 199138 7N-PUGWASH 69.000 1.94 0.14 0.00 1.9 0.14 199138 7N-PUGWASH 69.000 2.70 0.38 0.00 2.7 0.38 199141 6N-BLK_RIV 69.000 3.79 1.54 1.2 1.20 3.0 1.42 199141 6N-BLK_RIV 69.000 1.75 0.95 0.00 1.8 0.95 199146 30N-MACCAN 69.000 2.16 1.62 0.00 2.2 1.62 199147 37N-PARSBORO69.000 4.15 0.13 0.00 4.2 0.13 199147 37N-PARSBORO69.000 0.02 0.05 0.00 0.0 0.05 199148 75N-DOMTAR 69.000 0.39 0.31 0.00 0.4 0.31 199149 20N-PARKST 69.000 1.48 0.30 0.00 1.5 0.30 199151 17N-BROWNELL69.000 1.84 0.37 0.00 1.8 0.37 199152 22N-CHURCHST138.00 20.06 4.64 6 6.00 15.9 3.70 199153 139H_25KV 25.000 27.00 8.60 2 2.00 25.6 8.40 199155 82V-ELMSDALE26.400 23.79 7.57 10 1.1 11.10 16.0 2.61 199155 82V-ELMSDALE26.400 0.43 0.27 0.00 0.4 0.27 199155 82V-ELMSDALE26.400 0.34 -0.13 0.00 0.3 -0.13 199155 82V-ELMSDALE26.400 1.01 0.47 0.00 1.0 0.47 199156 127H-AEROTAP138.00 18.19 -1.17 0.5 0.50 17.8 0.00 199156 127H-AEROTAP138.00 2.91 0.63 0.00 2.9 0.63 199157 133H-HBR EST138.00 10.78 3.56 0.00 10.8 3.56 199160 113H-EASTDRT25.000 38.82 12.94 0.00 38.8 12.94 199162 126H-PORTERS138.00 7.64 1.51 3.2 3.20 5.4 1.31 199163 87H-MUSQ.HBR138.00 4.87 0.97 2.3 2.30 3.3 0.87 199167 91H-TUFTCV1 13.800 4.10 1.30 0.00 4.1 1.30 199168 91H-TUFTCV2 13.800 3.70 1.20 0.00 3.7 1.20 199169 91H-TUFTCV3 14.400 8.00 4.00 0.00 8.0 4.00 199170 99H-FARRELL 69.000 7.81 2.78 0.00 7.8 2.78 199171 62H-ALBRO 69.000 9.28 3.57 0.00 9.3 3.57 199172 40H-WOODLAWN69.000 10.66 2.95 0.00 10.7 2.95 199173 58H-IMPERIAL69.000 19.28 3.71 0.00 19.3 3.71 199174 58H-IMPERIAL26.400 10.24 7.90 0.00 10.2 7.90 199175 48H-PENHORN 69.000 15.37 4.96 0.00 15.4 4.96 199176 54H-MAPLE_ST69.000 11.38 3.67 0.00 11.4 3.67 199177 124H-AKERLEY69.000 6.87 3.26 0.00 6.9 3.26 199179 23H-ROCKHAM 69.000 12.12 3.06 0.00 12.1 3.06 199180 20H-SPRYFLD 69.000 18.88 5.21 4.6 4.60 15.7 4.42 199186 101H-COBEQUI26.400 34.51 10.78 0.00 34.5 10.78 199187 108H-BURNSID138.00 15.10 5.39 0.00 15.1 5.39 199191 103H-LAKSIDE26.400 30.59 9.94 7.05 7.05 25.7 7.37 199192 129H-KEARNEY138.00 0.00 0.00 0.00 0.0 0.00 199194 1H-WATER_ST 26.400 64.90 27.86 0.00 64.9 27.86

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2018 10 Year System Outlook Report Appendix B Page 53 of 84

PSSe Load Data % Distributed Generation (x) 70%

PSS/e Load Data 2021SUM Case Distribution Generation (MW) Net MW at Est Mvar Bus # Bus Name MW Mvar Wind Biogas Biomass Hydro Tidal Total x% 199194 1H-WATER_ST 26.400 0.20 0.06 0.00 0.2 0.06 199194 1H-WATER_ST 26.400 3.46 1.65 0.00 3.5 1.65 199197 2H-ARMDALE 138.00 30.03 9.25 0.00 30.0 9.25 199199 104H-KEMPT_R26.400 74.73 27.54 0.00 74.7 27.54 199199 104H-KEMPT_R26.400 2.05 0.96 0.00 2.1 0.96 199199 104H-KEMPT_R26.400 1.52 0.62 0.00 1.5 0.62 199203 131H-LUCASVL138.00 25.23 7.63 8 2.1 3.1 13.20 16.0 4.76 199206 92H-TIDEWTR 13.200 6.51 1.30 0.00 6.5 1.30 199209 137H-HAMONDS26.470 15.97 6.45 10 10.00 9.0 0.00 199210 87W-HUBBARDS138.00 3.23 0.65 0.00 3.2 0.65 199214 103W-GOLD_RV138.00 6.17 1.23 0.00 6.2 1.23 199215 85W-CANEXEL 69.000 2.60 1.77 0.00 2.6 1.77 199216 84W-ROB-SONS69.000 3.76 0.75 2 2.00 2.4 0.67 199220 78W-MARTINS 69.000 1.61 0.32 0.00 1.6 0.32 199222 81W-LUNENBUR69.000 3.51 0.70 0.00 3.5 0.70 199223 82W-NATIONNS69.000 2.06 0.17 0.00 2.1 0.17 199224 80W-INDIANNS69.000 4.40 0.88 0.00 4.4 0.88 199225 76W-MAHONE_B69.000 1.35 0.27 0.00 1.4 0.27 199229 74W-MICH_B-W138.00 13.31 5.80 0.00 13.3 5.80 199229 74W-MICH_B-W138.00 2.16 0.97 0.00 2.2 0.97 199232 89W-E_B-WATR69.000 9.96 4.11 4 4.00 7.2 2.78 199233 73W-AUBURNDA69.000 6.92 1.37 0.85 0.85 6.3 1.37 199235 70W-HIGHSTBW69.000 16.84 3.32 3.2 3.20 14.6 3.12 199246 50W-MILTON 69.000 7.27 2.58 3.6 3.60 4.8 1.78 199259 91W-MIDDLEFI69.000 2.37 1.65 0.00 2.4 1.65 199260 57W-CALEDONI69.000 2.07 1.44 0.00 2.1 1.44 199263 48W-WATERLOO69.000 2.01 1.92 0.00 2.0 1.92 199264 46W-BROADRVR69.000 1.91 0.41 0.00 1.9 0.41 199265 36W-GREENHBR69.000 1.44 0.31 0.00 1.4 0.31 199266 37W-LOCKPORT69.000 0.90 0.19 0.00 0.9 0.19 199272 25W-SHELBURN69.000 4.77 0.38 0.00 4.8 0.38 199274 23W-CLYDE_RI69.000 2.58 0.21 0.00 2.6 0.21 199276 22W-BARRINGT69.000 10.05 4.89 3.2 3.20 7.8 3.70 199277 101W-BMPC 138.00 0.54 0.32 0.00 0.5 0.32 199282 19W-ARGYLE 69.000 3.76 1.83 0.00 3.8 1.83 199283 20W-PUBNICO 69.000 2.33 1.14 0.00 2.3 1.14 199284 21W-WOODSHBR69.000 2.21 1.07 0.00 2.2 1.07 199286 10W-TUSKETGT69.000 4.46 0.61 0.00 4.5 0.61 199288 16W-HEBRON 69.000 4.74 1.37 2 2.00 3.3 1.21 199290 11W-KING_ST 69.000 2.68 0.67 0.00 2.7 0.67 199291 88W-PLEASANT69.000 8.35 2.10 4 4.00 5.6 1.60 199292 92W-CARLETON69.000 0.83 -0.26 0.00 0.8 -0.26 199294 88W-PLSNT_B569.000 6.90 0.81 0.00 6.9 0.81 199303 1V-AVON 69.000 2.33 0.32 0.00 2.3 0.32 199307 18V-BURLINGT69.000 4.40 0.87 2 2.00 3.0 0.79 199309 79V-3MIPLAIN69.000 15.64 5.60 6 6.00 11.4 3.34 199311 20V-FIVE_PT 69.000 2.73 0.76 0.00 2.7 0.76 199313 41V-MBPP 23.000 3.05 3.01 0.00 3.1 3.01 199321 83V-WOLFVILL69.000 6.69 1.01 0.00 6.7 1.01 199323 50V-KLONDIKE69.000 16.15 4.30 6 6.00 12.0 4.30

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2018 10 Year System Outlook Report Appendix B Page 54 of 84

PSSe Load Data % Distributed Generation (x) 70%

PSS/e Load Data 2021SUM Case Distribution Generation (MW) Net MW at Est Mvar Bus # Bus Name MW Mvar Wind Biogas Biomass Hydro Tidal Total x% 199324 22V-NEWMINAS69.000 19.31 7.08 0.00 19.3 7.08 199325 36V-HILLATON69.000 7.21 2.64 0.00 7.2 2.64 199325 36V-HILLATON69.000 0.35 0.24 0.00 0.4 0.24 199329 45V-ACADIA 23.000 0.76 0.20 0.00 0.8 0.20 199333 99V-HIGHBURY138.00 7.55 2.70 0.00 7.6 2.70 199335 92V-MICH_WAT69.000 10.44 4.59 0.00 10.4 4.59 199337 55V-WATERVLL69.000 12.89 3.64 0.00 12.9 3.64 199339 52V-BERWICK 69.000 4.15 1.17 0.00 4.2 1.17 199346 51V-TREMONT 69.000 1.75 -1.06 0.00 1.8 -1.06 199347 64V-GREENWD 69.000 5.59 1.55 0.00 5.6 1.55 199348 63V-KINGSTON69.000 9.94 2.76 0.00 9.9 2.76 199351 12V-LEQUILLE69.000 4.89 1.62 2 2.00 3.5 1.40 199355 70V-BRIDGTWN69.000 5.26 1.74 0.00 5.3 1.74 199359 65V-MIDDLETN69.000 7.46 2.14 0.00 7.5 2.14 199363 74V-CORNWLLS69.000 1.42 0.47 0.00 1.4 0.47 199365 13V-GULCH 13.800 1.65 1.14 0.00 1.7 1.14 199366 77V-CONWAY 69.000 9.19 1.53 1.7 2 3.70 6.6 1.49 199369 76V-MAITLAND69.000 0.46 0.32 0.00 0.5 0.32 199374 16V-WEYMOUTH69.000 1.75 1.85 0.3 0.30 1.5 1.85 199376 93V-SAULNIER69.000 10.70 2.80 0.6 0.60 10.3 2.79 199376 93V-SAULNIER69.000 0.83 -0.06 0.00 0.8 -0.06 199690 1C-TUPPER 25.000 6.64 2.76 0.8 0.80 6.1 2.71 199690 1C-TUPPER 25.000 1.12 1.24 0.00 1.1 1.24 199690 1C-TUPPER 25.000 0.24 0.20 0.00 0.2 0.20 Totals 1457.49 517.49 184.99 4.43 11.5 1.35 2 204.27 1314.71 447.82

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2018 10 Year System Outlook Report Appendix B Page 55 of 84

PSSe Load Data % Distributed Generation (x) 70%

PSS/e Load Data 2021WIN Case Distribution Generation (MW) Net MW at Est Mvar Bus # Bus Name MW Mvar Wind Biogas Biomass Hydro Tidal Total x% 199001 88S-LINGAN_114.400 8.10 4.10 0.0 8.1 4.10 199002 88S-LINGAN_214.400 7.80 4.00 0.0 7.8 4.00 199003 88S-LINGAN_314.400 8.20 4.20 0.0 8.2 4.20 199004 88S-LINGAN_414.400 8.00 4.10 0.00 8.0 4.10 199011 84S-VJ_DIST 69.000 8.61 2.29 2.3 2.30 7.0 2.11 199012 4S-TOWNSEND 69.000 33.92 9.04 0.00 33.9 9.04 199013 6S-TERRACE 69.000 6.31 2.12 0.00 6.3 2.12 199014 82S-WHITNEY 69.000 8.51 1.21 2.35 2.35 6.9 1.15 199015 15S-WATRFORD69.000 11.46 3.20 2.35 2.35 9.8 2.99 199018 11S-KELTIC_D69.000 40.46 13.60 4 4.00 37.7 12.71 199019 81S-RESERVE 69.000 32.31 7.35 4.8 4.80 29.0 6.77 199023 57S-ALBERT_B69.000 8.74 1.99 2.3 2.30 7.1 1.86 199026 3S-GANNON_RD69.000 31.99 6.16 6.35 6.35 27.5 5.43 199033 104S-BADDECK138.00 5.95 2.10 1.7 1.70 4.8 1.92 199035 85S-WRK_COVE138.00 4.27 1.20 0.00 4.3 1.20 199043 102S-ACONI 20.000 14.20 7.30 0.00 14.2 7.30 199051 2C-HASTINGS 138.00 3.99 1.30 2 2.00 2.6 1.09 199052 1C-TUPPER 138.00 1.12 0.32 0.00 1.1 0.32 199054 47C-NEW_PAGE13.800 33.60 21.00 0.00 33.6 21.00 199055 1C-TUPPER_GN14.400 6.00 2.00 0.00 6.0 2.00 199056 59C-STPETERS138.00 3.28 0.96 0.00 3.3 0.96 199058 67C-WHYCOCO 138.00 8.23 2.91 1.7 1.70 7.0 2.73 199060 47C-NP_PMP2 13.800 32.30 19.00 0.00 32.3 19.00 199063 22C-CLEVLAND138.00 14.55 4.22 1.99 1.99 13.2 4.06 199065 47C-NP_RL3 13.800 10.60 7.50 0.00 10.6 7.50 199067 9C-ABERDEEN 69.000 0.78 0.27 0.00 0.8 0.27 199068 58C-SW_MARG 69.000 9.31 3.28 2 2.00 7.9 3.04 199069 103C-CHETCMP69.000 3.89 1.37 1.6 1.60 2.8 1.21 199075 100C-PORCUPN138.00 8.40 7.00 0.23 0.23 8.2 7.00 199076 4C-LOCHABER 138.00 38.20 10.01 10.6 0.5 11.10 30.4 6.23 199077 4C-LOCHABER 69.000 0.00 0.00 0.00 0.0 0.00 199078 57C-SALMON_R69.000 6.06 2.11 0.00 6.1 2.11 199080 19C-CANSO 69.000 1.58 0.54 0.00 1.6 0.54 199082 24C-DICKIEBR25.000 5.36 1.62 0.00 5.4 1.62 199085 50N-TRENTON518.000 7.80 4.10 0.00 7.8 4.10 199086 50N-TRENTON613.800 7.20 3.70 0.00 7.2 3.70 199091 50N-TRENTON 69.000 28.82 7.36 7.8 7.80 23.4 5.42 199091 50N-TRENTON 69.000 3.35 3.14 0.00 3.3 3.14 199092 62N-BRIDG_AV69.000 37.32 11.66 13.2 13.20 28.1 3.32 199096 88H-UP_MUSQ 69.000 8.39 2.62 1.1 1.10 7.6 2.62 199096 88H-UP_MUSQ 69.000 0.61 0.51 0.00 0.6 0.51 199098 96H-RUTH_FLS69.000 5.87 1.83 1.5 1.50 4.8 1.72 199100 49N-MICHGRAN138.00 11.47 5.07 0.00 11.5 5.07 199105 53N-NRT PULP13.800 8.92 3.08 0.00 8.9 3.08 199106 56N-HALIBURT69.000 12.99 2.41 3 3.00 10.9 2.26 199106 56N-HALIBURT69.000 1.19 0.82 0.00 1.2 0.82 199107 55N-PICTOU 69.000 5.63 1.04 0.00 5.6 1.04 199110 1N-ONSLOW 138.00 22.61 4.99 5 1 6.00 18.4 4.39 199111 1N-ONSLOW_A 69.000 4.55 0.76 0.00 4.6 0.76 199112 1N-ONSLOW_B 69.000 10.40 3.21 0.00 10.4 3.21

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2018 10 Year System Outlook Report Appendix B Page 56 of 84

PSSe Load Data % Distributed Generation (x) 70%

PSS/e Load Data 2021WIN Case Distribution Generation (MW) Net MW at Est Mvar Bus # Bus Name MW Mvar Wind Biogas Biomass Hydro Tidal Total x% 199114 15N-WILLOWLN69.000 46.01 18.96 13.8 13.80 36.3 3.11 199114 15N-WILLOWLN69.000 3.30 1.00 0.00 3.3 1.00 199114 15N-WILLOWLN69.000 0.36 0.14 0.00 0.4 0.14 199115 11N-LAFARGE 69.000 1.17 0.08 0.00 1.2 0.08 199116 16N-STEWIAKE69.000 5.63 1.62 0.5 0.50 5.3 1.62 199118 4N-TATAMAG 69.000 10.75 2.69 1.6 1.60 9.6 2.61 199134 81N-DEBERT 138.00 29.00 9.69 3.6 3.60 26.5 8.98 199136 74N-SPRINGHL69.000 7.97 2.25 0.00 8.0 2.25 199137 3N-OXFORD 69.000 2.97 0.86 0.00 3.0 0.86 199137 3N-OXFORD 69.000 2.79 1.52 0.00 2.8 1.52 199138 7N-PUGWASH 69.000 1.98 0.54 0.00 2.0 0.54 199138 7N-PUGWASH 69.000 3.09 0.67 0.00 3.1 0.67 199141 6N-BLK_RIV 69.000 5.42 1.50 1.2 1.20 4.6 1.44 199141 6N-BLK_RIV 69.000 1.40 0.87 0.00 1.4 0.87 199146 30N-MACCAN 69.000 3.09 2.63 0.00 3.1 2.63 199147 37N-PARSBORO69.000 6.90 2.15 0.00 6.9 2.15 199147 37N-PARSBORO69.000 0.18 0.12 0.00 0.2 0.12 199148 75N-DOMTAR 69.000 0.52 0.14 0.00 0.5 0.14 199149 20N-PARKST 69.000 2.76 0.57 0.00 2.8 0.57 199151 17N-BROWNELL69.000 3.41 0.71 0.00 3.4 0.71 199152 22N-CHURCHST138.00 23.72 7.52 6 6.00 19.5 5.74 199153 139H_25KV 25.000 35.21 10.77 2 2.00 33.8 10.58 199155 82V-ELMSDALE26.400 44.66 12.92 10 1.1 11.10 36.9 8.82 199155 82V-ELMSDALE26.400 0.74 0.48 0.00 0.7 0.48 199155 82V-ELMSDALE26.400 0.49 0.32 0.00 0.5 0.32 199155 82V-ELMSDALE26.400 0.36 0.16 0.00 0.4 0.16 199156 127H-AEROTAP138.00 26.02 3.27 0.5 0.50 25.7 3.27 199156 127H-AEROTAP138.00 1.79 0.48 0.00 1.8 0.48 199157 133H-HBR EST138.00 14.97 4.99 0.00 15.0 4.99 199160 113H-EASTDRT25.000 71.84 19.38 0.00 71.8 19.38 199162 126H-PORTERS138.00 19.20 4.45 3.2 3.20 17.0 4.18 199163 87H-MUSQ.HBR138.00 12.24 2.83 2.3 2.30 10.6 2.69 199167 91H-TUFTCV1 13.800 4.10 1.30 0.00 4.1 1.30 199168 91H-TUFTCV2 13.800 3.70 1.20 0.00 3.7 1.20 199169 91H-TUFTCV3 14.400 8.00 4.00 0.00 8.0 4.00 199170 99H-FARRELL 69.000 13.09 3.36 0.00 13.1 3.36 199171 62H-ALBRO 69.000 12.87 2.63 0.00 12.9 2.63 199172 40H-WOODLAWN69.000 15.18 4.31 0.00 15.2 4.31 199173 58H-IMPERIAL69.000 6.05 2.00 0.00 6.1 2.00 199174 58H-IMPERIAL26.400 17.02 3.71 0.00 17.0 3.71 199175 48H-PENHORN 69.000 20.96 4.53 0.00 21.0 4.53 199176 54H-MAPLE_ST69.000 15.98 3.46 0.00 16.0 3.46 199177 124H-AKERLEY69.000 6.48 3.14 0.00 6.5 3.14 199179 23H-ROCKHAM 69.000 23.11 5.22 0.00 23.1 5.22 199180 20H-SPRYFLD 69.000 47.03 14.97 4.6 4.60 43.8 13.92 199186 101H-COBEQUI26.400 69.11 19.38 0.00 69.1 19.38 199187 108H-BURNSID138.00 19.04 4.50 0.00 19.0 4.50 199191 103H-LAKSIDE26.400 51.74 17.23 7.05 7.05 46.8 14.53 199192 129H-KEARNEY138.00 41.15 11.11 0.00 41.2 11.11 199194 1H-WATER_ST 26.400 50.39 14.94 0.00 50.4 14.94

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PSSe Load Data % Distributed Generation (x) 70%

PSS/e Load Data 2021WIN Case Distribution Generation (MW) Net MW at Est Mvar Bus # Bus Name MW Mvar Wind Biogas Biomass Hydro Tidal Total x% 199194 1H-WATER_ST 26.400 0.47 0.05 0.00 0.5 0.05 199194 1H-WATER_ST 26.400 4.32 1.50 0.00 4.3 1.50 199197 2H-ARMDALE 138.00 33.27 8.61 0.00 33.3 8.61 199199 104H-KEMPT_R26.400 115.14 26.92 0.00 115.1 26.92 199199 104H-KEMPT_R26.400 0.59 0.20 0.00 0.6 0.20 199199 104H-KEMPT_R26.400 1.23 0.49 0.00 1.2 0.49 199203 131H-LUCASVL138.00 64.69 16.15 8 2.1 3.1 13.20 55.4 14.20 199206 92H-TIDEWTR 13.200 15.91 3.19 0.00 15.9 3.19 199209 137H-HAMONDS26.470 28.20 4.93 10 10.00 21.2 3.43 199210 87W-HUBBARDS138.00 7.91 1.58 0.00 7.9 1.58 199214 103W-GOLD_RV138.00 15.08 3.01 0.00 15.1 3.01 199215 85W-CANEXEL 69.000 2.83 1.63 0.00 2.8 1.63 199216 84W-ROB-SONS69.000 9.20 1.84 2 2.00 7.8 1.76 199220 78W-MARTINS 69.000 3.01 0.51 0.00 3.0 0.51 199222 81W-LUNENBUR69.000 6.60 1.12 0.00 6.6 1.12 199223 82W-NATIONNS69.000 1.78 0.26 0.00 1.8 0.26 199224 80W-INDIANNS69.000 8.27 1.40 0.00 8.3 1.40 199225 76W-MAHONE_B69.000 2.54 0.43 0.00 2.5 0.43 199229 74W-MICH_B-W138.00 11.51 5.15 0.00 11.5 5.15 199229 74W-MICH_B-W138.00 1.85 0.83 0.00 1.9 0.83 199232 89W-E_B-WATR69.000 15.46 4.09 4 4.00 12.7 3.54 199233 73W-AUBURNDA69.000 12.58 2.55 0.85 0.85 12.0 2.55 199235 70W-HIGHSTBW69.000 30.62 6.22 3.2 3.20 28.4 6.02 199246 50W-MILTON 69.000 13.92 4.01 3.6 3.60 11.4 3.48 199259 91W-MIDDLEFI69.000 2.95 0.98 0.00 3.0 0.98 199260 57W-CALEDONI69.000 2.56 0.86 0.00 2.6 0.86 199263 48W-WATERLOO69.000 9.52 1.93 0.00 9.5 1.93 199264 46W-BROADRVR69.000 3.66 0.10 0.00 3.7 0.10 199265 36W-GREENHBR69.000 2.75 0.08 0.00 2.7 0.08 199266 37W-LOCKPORT69.000 1.72 0.04 0.00 1.7 0.04 199272 25W-SHELBURN69.000 8.70 0.93 0.00 8.7 0.93 199274 23W-CLYDE_RI69.000 4.69 0.51 0.00 4.7 0.51 199276 22W-BARRINGT69.000 15.20 4.21 3.2 3.20 13.0 3.83 199277 101W-BMPC 138.00 0.74 0.20 0.00 0.7 0.20 199282 19W-ARGYLE 69.000 5.69 1.57 0.00 5.7 1.57 199283 20W-PUBNICO 69.000 3.53 0.98 0.00 3.5 0.98 199284 21W-WOODSHBR69.000 3.34 0.93 0.00 3.3 0.93 199286 10W-TUSKETGT69.000 8.41 1.64 0.00 8.4 1.64 199288 16W-HEBRON 69.000 9.36 3.01 2 2.00 8.0 2.81 199290 11W-KING_ST 69.000 4.10 0.72 0.00 4.1 0.72 199291 88W-PLEASANT69.000 12.78 2.23 4 4.00 10.0 1.99 199292 92W-CARLETON69.000 1.71 1.91 0.00 1.7 1.91 199294 88W-PLSNT_B569.000 13.61 1.79 0.00 13.6 1.79 199303 1V-AVON 69.000 4.02 0.34 0.00 4.0 0.34 199307 18V-BURLINGT69.000 4.87 1.62 2 2.00 3.5 1.40 199309 79V-3MIPLAIN69.000 29.93 9.28 6 6.00 25.7 7.59 199311 20V-FIVE_PT 69.000 4.68 1.14 0.00 4.7 1.14 199313 41V-MBPP 23.000 2.24 0.93 0.00 2.2 0.93 199321 83V-WOLFVILL69.000 12.99 1.86 0.00 13.0 1.86 199323 50V-KLONDIKE69.000 21.10 3.81 6 6.00 16.9 3.81

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PSSe Load Data % Distributed Generation (x) 70%

PSS/e Load Data 2021WIN Case Distribution Generation (MW) Net MW at Est Mvar Bus # Bus Name MW Mvar Wind Biogas Biomass Hydro Tidal Total x% 199324 22V-NEWMINAS69.000 22.44 5.36 0.00 22.4 5.36 199325 36V-HILLATON69.000 8.40 2.00 0.00 8.4 2.00 199325 36V-HILLATON69.000 0.31 0.19 0.00 0.3 0.19 199329 45V-ACADIA 23.000 2.70 0.56 0.00 2.7 0.56 199333 99V-HIGHBURY138.00 11.97 2.23 0.00 12.0 2.23 199335 92V-MICH_WAT69.000 8.47 4.09 0.00 8.5 4.09 199337 55V-WATERVLL69.000 19.96 3.95 0.00 20.0 3.95 199339 52V-BERWICK 69.000 6.43 1.27 0.00 6.4 1.27 199346 51V-TREMONT 69.000 4.44 1.08 0.00 4.4 1.08 199347 64V-GREENWD 69.000 8.52 1.62 0.00 8.5 1.62 199348 63V-KINGSTON69.000 15.14 2.87 0.00 15.1 2.87 199351 12V-LEQUILLE69.000 7.94 1.91 2 2.00 6.5 1.79 199355 70V-BRIDGTWN69.000 8.55 2.06 0.00 8.5 2.06 199359 65V-MIDDLETN69.000 13.05 2.79 0.00 13.0 2.79 199363 74V-CORNWLLS69.000 2.30 0.55 0.00 2.3 0.55 199365 13V-GULCH 13.800 3.31 1.08 0.00 3.3 1.08 199366 77V-CONWAY 69.000 15.25 2.79 1.7 2 3.70 12.7 2.74 199369 76V-MAITLAND69.000 0.58 0.19 0.00 0.6 0.19 199374 16V-WEYMOUTH69.000 2.97 1.08 0.3 0.30 2.8 1.08 199376 93V-SAULNIER69.000 14.12 3.23 0.6 0.60 13.7 3.22 199376 93V-SAULNIER69.000 0.26 0.15 0.00 0.3 0.15 199690 1C-TUPPER 25.000 8.98 2.99 0.8 0.80 8.4 2.96 199690 1C-TUPPER 25.000 0.81 0.68 0.00 0.8 0.68 199690 1C-TUPPER 25.000 0.20 0.17 0.00 0.2 0.17 Totals 2207.04 638.08 184.99 4.43 11.5 1.35 2 204.27 2064.05 584.59

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2018 10 Year System Outlook Report Appendix B Page 59 of 84

2017 NRIS Wind Study

Appendix D

Steady State Cases – Load Flow Diagrams

2018 10 Year System Outlook Report Appendix B Page 60 of 84

EEXS: 21.7 MW NB to NE: 805.1 MW EEXEB: 81.6 MW NB to QC: 596.2 MW ML HVDC: 70.0 MW NSX 0.1 MW MAINLAND AT HASTINGS: 31.7 MW CBX 98.8 MW HASTINGS FROM 88S,5S,2S: 94.9 MW ONI 233.0 MW 1.017 199137 199555 70.2 3N-OXFORD FORCE_HV L-7011:39.0 MW ONS 262.6 MW 199138 199147 1.000 5.0 199557 2.5 1 7N-PUGWASH 37N-PARSBORO 0.7 -1.0R IR516_G L-7012: 41.3 MW NB to PEI: 80.1 MW 1.3 2.5 -2.5 1.4 12.4 -14.414.5 1.000 4.0 199558 Nova Scotia New Brunswick L-7011 + L-7012: 80.4 MW 1 0.4 IR517 5.5 5.5 -5.5 0.0 -0.5 0.5 -4.0 3.3 -3.2 -0.7R 190401 1.015 1.014 1.010 5.6 199559 MEM138 0.7 1.3 -1.5 1 70.0 70.0 0.7 0.0H IR542_G 190075 190150 190197 SACK138 MEM69 1.014 199530 C.COVE 199139 70.0 92N-AMHSTWIN 199531 199533 10N-ABER_ST 92N-AMHSTLV 92N-AMHSTGEN 3.7 -12.2 -17.7 17.7

199146 199145 1 1.027 3.1 -3.1 14.1 0.9875 30N-MACCAN 30N-MACCAN 141.7 -7.1 -24.8 1 -24.9 25.0 1.0 -2.9 4.7 -6.1 1.014 -12.3 -1.0 1.019 -3.7 1.027

1 1.032 349.8

1.6 -1.7 1 4.0 -87.8 70.3 3.9 71.2 141.7 134.2 4.9 6.5 4.3 -3.3L 199136 1.020 1.018 1.012 1.009 190379 74N-SPRINGHL 70.4 70.3 34.9 0.6 BOR1159 17.7 L6535

-14.2 14.3 -7.1 7.1 -17.6 -17.63.7 13.90.8 -13.9 -16.2 16.2

3.9 L6514 -5.2 0.3 L6551 -1.0 -5.5 5.2 3.9 -4.7 4.3 4.7 -6.1 36 Mvar 1.027 1.027 141.7 141.7 1.026 1.027 141.6 141.7 199152 190408 22N-CHURCHST BOR1160 190258 190498 1.031 -133.5 L6513 7.6 L6536 44.3 -7.5 -7.6 2.2 2.2 -2.2 MURRCRNORTON 355.6

-5.5 -2.3 0.9 -2.2 -1.5 -0.0 1.027 190341 1.027 199135 141.8 HARDRD

5.4 1.3 30.6 -30.3 29.1 -29.0

199134 1.6 141.7 74N-SPRNGHIL 199125 1.6 81N-DEBERT 67N-ONSLOW -73.2 -26.5 25.2 -25.5 25.0 144.0 1.2 0.3 199195 0.5 1.046 1.051 103H-LAKSIDE 1.032 144.3 145.1

-81.4 -9.1-2.1 7.5 L8002 81.6 142.5 190320 -28.2 -29.0 190402 SALBRY MEM345 1.043 359.8 0.0 + 37.5 MVar 190381 -47.3 40.6 BR3025 0.0 -143.6 31.6 -19.8 L8001 19.8 190417

1.0375 40.6 40.8 1.028 BATHURST -37.2 -28.3 -67.1 199130 141.8 67.2 3.8 -3.6 67N-ONSLOW 58.1 199045 -78.4 6.8 -105.5 101S-WOODBIN 0.0 1.004 199120 199042 346.4 79N-HOPWELL 101S-WOODBIN 1.040 27.00.0 22.5 1.048 199043358.9 1 -106.4 106.5 -66.9 361.6 67.1 -1.0 102S-ACONI 27.00.0 21.2 199200 24.1 L8003 -51.5 -28.4 L8004 -81.1 63.1 L7015 120H-BRUSHY 0.0 -55.6 55.8 70.0 L7001 27.0 22.1 199855 1.01 -30.2 199001 27.0 1 22.6 31.9R -43.2 43.3 NS_DC_POLE1 88S-LINGAN_1 20.9 35.0 -1.9 70.0 1.9 -14.8 199121 79N-HOPWELL-19.8 -39.6 14.2 -62.3R 1 -14.0 27.7R 1.045 199593 7.3

6.6 0.98 79.8 0.995 -42.3 L7002 42.5 0.0 91N-DALHOGEN 0.0 360.6 199050 119.4 199857 42.0 3C-HASTINGS NS_DC_POLE2 1.000 8.1 1.5 -14.8 32.0 52.3 -19.8 0.0 35.0 0.0 -7.2 L7014 20.0 7.2 1.040 199590 -1.1R 4.1 358.8 91N-DALHOUS 6.6 32.0 1.024 -62.3R 2 * 50 Mvar 52.3 -18.0 11.0 0.6 0.995 -61.3 L7018 61.4 -54.0 L7019 2 * 30 Mvar 54.2 -13.7 L7004 13.7 -38.7 39.0 -7.5 L7021 7.5 119.4 1.025 0.980 353.6 14.1 0.1 -18.1 -5.1 0.1 -10.3 -15.4 17.9 L7011 -35.5 -17.2 10.3

1.043 L7003 L7012 L7022 -21.0 239.9 21.1 -41.1 41.3 -7.2 7.2 199202 17.1 -34.9 -18.0 11.0 120H-BRSHSVC -12.9 -17.2 199002 199010 88S-LINGAN_2 0.0 -22.2 L7005 22.3 199110 199015 199016 2S-VJ 1.023 1N-ONSLOW 15S-WATRFORD-0.0 0.0 109S-LINWIND 235.3 -0.3R -15.3 -15.5 199051 5.4 -0.2 0.2 4.3 -4.3 2C-HASTINGS 199019 9.1 1 19.9 19.9 1.026 199100 70.8 81S-RESERVE -14.4 12.0 -12.0 -12.0 12.0 -12.0 1.4 -1.6 1.041 49N-MICHGRAN 1.2 -8.0 -8.0 1 1 239.3 1.039 199076 -1.2R 2.1 3.0 -3.1 3.1 1.000 199154 239.0 4C-LOCHABER 11.4 3.1 -3.1 2.1 -2.1 6.4 199090 199610 199075 1.000 14.4 82V-ELMSDALE 50N-TRENTON 93N-GLENDHU 100C-PORCUPN 1 6.5 199423 0.4 0.3 -0.5 0.3 -0.3 2.0 11.4 3.1 109S-LINWIND 1.026 -33.5 L6001 33.8 L6503 41.0 -26.8 L651126.9 21.6 L6552 -21.6 29.7 L6515 -29.5 25.5 L6515 -29.4 29.5 -25.4 70.8 11.4 9.0 2.7 -4.9 3.3 -6.1 -3.2 -2.20.2 -7.0 5.8 -8.8 6.5 -8.0 7.8 199007 1.021 2S-VICTORIA 1.029 1 6.5 199063 199056 70.5 199003

0.99 7.6 142.0 199091 22C-CLEVLAND 59C-STPETERS 88S-LINGAN_3 50N-TRENTON -48.5 0.0 -8.1 4.0 50 Mvar 1.035 9.1 6.8 0.0 3.0 1.5 4.5 199006 7.7 0.99 88S-LINGAN_B 1.043 5.3 L6516 L6533 239.8 1.025 1.037 1.038 1.039 1.025

-4.7 3.1 0.8 1.0 0.2 8.9 -19.8 19.8 19.8 143.2 143.3 143.4 70.7 199053 4.4 -12.0 5.3 -6.1 -5.9 2.9 4.4 70.0 47C-NEW_PAGE 1.01 -30.8 L6518 30.9 1.038 1.036 1.020 199611 199057 143.3 143.0 140.8 1.000

0.9 1.01 1.01 5.1 -4.6R 93N-GLENDHUM -2.9 2.9 67C-WHYC_TAP 199005 -1.6 1.0 199033 199031 199025 14.4 199072 104S-BADDECK 5S-GLEN_TOSH 3S-GANNON_RD 88S-LINGAN_A 1.035 1.4 -2.4 L6534 199112 71.4 1.031 48C-BIOMASS 199004 L6517 -5.0 L6537 5.0 -5.6 5.6 -7.4 L6538 7.4 L6539 12.8 -20.0 20.1 20.1 1N-ONSLOW_B 199111 142.3 199118 1.005 88S-LINGAN_4 4N-TATAMAG -0.0 0.0 24.0 -2.1 2.1 199114 1N-ONSLOW_A 199580 34.71.2 -31.1 -48.6 1 15N-WILLOWLN 2.9 -4.5 4.1 -5.0 11.1 -13.2 -14.3 5.7 -6.6 1.01 -6.4 89N_NUTBTP 8.1 1.2 -1.2 1.2 0.0 -1.1 2.7 -3.3 -0.5 1.021 1.038 1.021 140.8 7.3 -29.1 38.1 199612 141.0

0.99375 14.3 0.1 -0.5 0.5 93N-GLENDHUG 0.6 5.3 199584 199026

1.036 1.040 1.042 0.99 0.3 13.7 -7.3 89N_NUTBG 199581 71.5 143.5 143.8 3S-GANNON_RD

1.045 0.9875

2.3 0.4 1.2 72.1 89N_NUTBHV 49.8 1.028 -39.3 39.3 40.0 L6523 1.037 1.033 1.030 71.6 236.5 1.000 3.7 142.6 1.02535.5-2.3 14.4

7.2 -7.1 -0.5R -49.8 199613 1.046 1.8 1.0370.988 1.041 1.030 199035 93N-GLENDHU 72.1 71.6 0.4 143.6 142.2 85S-WRK_COVE 1.037 L6545 199037 3.6 -4.2 4.2 71.5 0.9 -0.9 85S-WRECK_2 199052 1.2 -8.2 -3.4

-1.3 1.0 31.1 -3.0 -0.2 -24.0

0.6 0.1 1C-TUPPER

1.026 50.0 1.037

1.022 4.5R 199115 70.5 70.8 143.2 0.9 L6549 -0.9

11N-LAFARGE 0.4 0.1 9.4 -13.5

6.0 2.0 -3.0 -0.2 1 199036 1.8 85S-WRECK_1

0.6-0.6 -0.3 1.039 0.5 143.4 0.3 199690 1.041 1C-TUPPER0.996 143.6 1.021 24.9 199116 70.5 16N-STEWIAKE 1.6

199054 2.4 6.4 -16.6 47C-NEW_PAGE 1.038 199692 120C-BEARHD 1.000 143.2 Bus - Voltage (kV/pu) 13.8 199691

-17.0-5.6 17.0

17.0 120C-BEARHD Branch - MW/Mvar 1.025 5.6 -4.5R Equipment - MW/Mvar 0.960 100.0%Rate A 0.4 1.050OV 0.970UV kV: <=35.000 <=69.000 <=138.000 <=230.000 <=345.000 >345.000 2021 LIGHT LOAD: 2021LL - FULL WIND ON BACKBONE Total Wind Gen: 207.5 MW Gross Tupper 0.0 MW Gross Wreck Cove 0.0 MW Net NewPage Load 61.9 MW Summer Ratings FROM UPDATE OF 2014 SERIES MMWG 2020 SPRING LIGHT LOAD Gross Lingan 70.0 MW Gross Trenton 70.0 MW Gross Gas Turbine 0.0 MW Gross NewPage Load 61.9 MW Figure ___D-1 SUN, OCT 01 2017 0:02 Gross Pt Aconi 70.0 MW Gross Tuft's Cove 70.0 MW Gross Small Hydro 14.6 MW Total BMPC Load -0.9 MW Includes 70% Distributed Generation Total Gross Gen: 502.1 MW ML HVDC: 70.0 MW Gross Gen + ML: 572.1 MW modeled as Negative Load: -143.0 MW 1 2018 10 Year System Outlook Report Appendix B Page 61 of 84

EEXS: 39.0 MW NB to NE: 805.0 MW EEXEB: 287.9 MW NB to QC: 596.2 MW ML HVDC: 410.0 MW NSX 330.2 MW MAINLAND AT HASTINGS: 188.8 MW CBX 436.0 MW HASTINGS FROM 88S,5S,2S: 254.6 MW ONI 564.0 MW 1.013 199137 199555 69.9 3N-OXFORD FORCE_HV L-7011:104.7 MW ONS 262.6 MW 199138 199147 1.000 5.0 199557 2.5 1 7N-PUGWASH 37N-PARSBORO 0.7 -0.9R IR516_G L-7012: 109.1 MW NB to PEI: 80.2 MW 1.3 2.5 -2.5 1.4 12.4 -14.414.5 1.000 4.0 199558 Nova Scotia New Brunswick L-7011 + L-7012: 213.8 MW 1 0.4 IR517 5.5 5.5 -5.5 0.1 -0.5 0.5 -3.7 3.0 -3.0 -0.6R 190401 1.011 1.012 1.009 5.6 199559 MEM138 0.7 1.3 -1.5 1 69.8 69.8 0.7 0.0H IR542_G 190075 190150 190197 SACK138 MEM69 1.012 199530 C.COVE 199139 69.8 92N-AMHSTWIN 199531 199533 10N-ABER_ST 92N-AMHSTLV 92N-AMHSTGEN 3.7 -12.2 8.1 -8.1

199146 199145 1 1.024 3.1 -3.1 14.1 0.9875 30N-MACCAN 30N-MACCAN 141.3 -7.1 -24.8 1 -24.9 25.0 1.0 -2.9 -2.6 1.1 1.016 -12.3 -1.0 1.016 -3.7 1.025

1 1.029 350.5

1.6 -1.7 1 4.0 70.1 3.7 71.0 141.4 -45.1 -68.0 4.7 6.5 4.3 -3.3L 199136 1.016 1.015 1.009 1.006 190379 74N-SPRINGHL 70.1 70.0 34.8 0.6 BOR1159 41.1 L6535

9.2 -9.2 16.3 -16.3 -41.1 -40.83.7 37.10.8 -37.0 9.0 -9.0

-1.5 L6514 0.2 -4.9 L6551 4.2 -10.7 10.6 10.1 -10.9 10.7 -2.3 0.8 36 Mvar 1.023 1.025 141.2 141.4 1.023 1.023 141.2 141.2 199152 190408 22N-CHURCHST BOR1160 190258 190498 1.031

L6513 36.8 L6536 45.2 18.8 -60.1 -36.6 31.2 31.2 -31.1 MURRCRNORTON 355.6

6.1 -8.6 7.8 -9.1 -8.7 7.7 1.024 190341 1.023 199135 141.3 HARDRD

5.4 1.3 30.6 -30.3 29.1 -29.0

199134 -5.8 141.2 74N-SPRNGHIL 199125 1.6 81N-DEBERT 67N-ONSLOW -45.0 -43.3 -26.5 25.2 -25.6 25.1 1.2 0.3 199195 0.5 1.043 1.049 103H-LAKSIDE 1.025 143.9 144.7 -72.9 5.3 L8002 73.0 -62.2141.4 60.6 190320 -23.6 -33.0 190402 SALBRY MEM345 1.035 357.0 0.0 + 37.5 MVar 190381 -66.2 40.4 BR3025 0.0 45.1 37.0 257.9 L8001 -255.6 190417

1.0375 40.4 6.4 1.025 BATHURST -59.0 19.8 189.4 199130 141.4 -189.0 57.4 -57.1 67N-ONSLOW 13.9 199045 -30.7 0.1 -96.9 101S-WOODBIN 0.0 1.003 199120 199042 345.9 79N-HOPWELL 101S-WOODBIN 1.037 26.50.0 -24.3 1.042 199043357.9 1 -282.8 283.7 -244.5 359.6 247.1 -80.5 102S-ACONI 26.50.0 23.8 199200 44.9 L8003 -60.0 -12.5 L8004 -59.3 60.3 L7015 120H-BRUSHY 0.0 -55.6 55.8 70.0 L7001 26.5 -23.9 199855 1.01 -30.7 199001 26.5 1 23.2 32.4R -46.6 46.8 NS_DC_POLE1 88S-LINGAN_1 23.4 205.0 -82.3 70.0 5.7 -18.1 199121 79N-HOPWELL-19.6 -39.2 14.2 -29.9R 1 -16.7 28.6R 1.036 199593 7.3

3.6 0.98 72.5 1.006 -45.6 L7002 45.8 0.0 91N-DALHOGEN 0.0 357.3 199050 120.7 199857 42.0 3C-HASTINGS NS_DC_POLE2 1.000 8.1 5.3 -18.0 31.5 52.3 -19.6 0.0 205.0 0.0 1.7 L7014 20.0 -1.7 1.030 199590 1.0R 4.1 355.3 91N-DALHOUS 3.6 31.5 1.026 -29.9R 2 * 50 Mvar 52.3 -18.2 11.2 0.6 1.006 -66.3 L7018 66.5 -98.1 L7019 2 * 30 Mvar 98.6 -58.1 L7004 58.7 -103.2 104.7 1.1 L7021 -1.1 120.7 1.025 0.980 353.6 14.1 5.3 -22.5 2.3 -5.4 -2.6 -18.9 24.3 L7011 -33.3 -17.7 10.8

1.033 L7003 L7012 L7022 -65.0 237.7 66.3 -107.9 109.1 1.7 -1.7 199202 21.1 -29.9 -18.2 11.2 120H-BRSHSVC -2.6 -21.5 199002 199010 88S-LINGAN_2 0.0 -69.3 L7005 70.0 199110 199015 199016 2S-VJ 1.023 1N-ONSLOW 15S-WATRFORD0.0 0.0 109S-LINWIND 235.2 -0.0R -9.0 -15.3 199051 -25.2 -0.2 0.2 4.3 -4.3 2C-HASTINGS 199019 62.3 1 19.6 19.6 1.024 199100 70.7 81S-RESERVE -8.2 12.0 -12.0 -12.0 12.0 -12.0 1.4 -1.6 1.032 49N-MICHGRAN -5.2 -5.0 -5.0 1 1 237.4 1.029 199076 -1.0R 1.9 2.8 -3.0 2.9 1.000 199154 236.7 4C-LOCHABER 8.0 3.1 -3.1 2.1 -2.1 6.4 199090 199610 199075 1.001 14.4 82V-ELMSDALE 50N-TRENTON 93N-GLENDHU 100C-PORCUPN 1 5.1 199423 0.4 0.3 -0.5 0.3 -0.3 2.0 11.4 3.1 109S-LINWIND 1.024 -30.2 L6001 30.5 L6503 60.6 -46.0 L651146.4 2.1 L6552 -2.1 10.2 L6515 -10.2 6.2 L6515 -48.8 49.2 -6.2 70.7 8.0 9.0 3.6 -6.0 5.7 -6.4 -3.2 1.7-2.4 -2.9 1.5 -4.2 1.0 -2.5 2.3 199007 1.020 2S-VICTORIA 1.023 1 5.1 199063 199056 70.4 199003

0.99 7.5 141.2 199091 22C-CLEVLAND 59C-STPETERS 88S-LINGAN_3 50N-TRENTON -48.5 0.0 -8.1 4.0 50 Mvar 1.035 9.1 5.4 0.0 2.6 1.5 4.5 199006 7.6 0.99 88S-LINGAN_B 1.035 5.3 L6516 L6533 238.1 1.025 1.032 1.032 1.033 1.024

-19.4 3.1 0.8 1.0 0.2 23.9 -32.9 33.0 33.0 142.4 142.5 142.5 70.6 199053 6.6 -12.7 5.8 -6.3 -5.8 2.9 4.4 70.0 47C-NEW_PAGE 1.01 -30.8 L6518 30.9 1.032 1.030 1.020 199611 199057 142.4 142.2 140.7 1.000

0.9 1.01 1.01 5.2 5.3R 93N-GLENDHUM -2.9 2.9 67C-WHYC_TAP 199005 -1.1 0.6 199033 199031 199025 14.4 199072 104S-BADDECK 5S-GLEN_TOSH 3S-GANNON_RD 88S-LINGAN_A 1.028 1.4 -2.3 L6534 199112 71.0 1.025 48C-BIOMASS 199004 L6517 -16.2 L6537 16.2 -16.8 16.8 -18.6 L6538 18.7 L6539 24.2 -33.3 33.4 33.4 1N-ONSLOW_B 199111 141.4 199118 1.003 88S-LINGAN_4 4N-TATAMAG -0.0 0.0 -31.1 24.0 -13.2 13.3 199114 1N-ONSLOW_A 199580 34.6-0.3 -48.6 1 15N-WILLOWLN 4.1 -5.6 5.2 -6.0 12.0 -13.9 -14.6 6.4 -7.0 1.01 -6.5 89N_NUTBTP 7.6 1.2 -1.2 1.2 0.0 -1.1 2.2 -1.7 -1.8 1.020 1.031 1.020 140.7 7.3 -29.1 38.1 199612 140.8

0.99375 14.2 0.1 -0.5 0.5 93N-GLENDHUG 0.6 5.3 199584 199026

1.032 1.033 1.037 0.99 0.3 12.4 -6.0 89N_NUTBG 199581 71.2 142.5 143.0 3S-GANNON_RD

1.037 0.9875

3.8 0.4 1.2 71.5 89N_NUTBHV 49.8 1.027 -39.3 39.3 40.0 L6523 1.034 1.025 1.030 71.4 236.3 1.000 3.7 141.5 1.02535.5-3.8 14.4

5.9 -5.9 0.8R -49.8 199613 1.038 1.8 1.0330.990 1.036 1.027 199035 93N-GLENDHU 71.6 71.3 0.4 142.9 141.8 85S-WRK_COVE 1.033 L6545 199037 3.6 -4.2 4.2 71.3 0.9 -0.9 85S-WRECK_2 199052 1.2 -7.7 -2.9

-1.3 1.0 31.1 -3.0 -0.2 -23.9

0.6 0.1 1C-TUPPER

1.020 50.0 1.031

1.015 6.0R 199115 70.0 70.4 142.2 0.9 L6549 -0.9

11N-LAFARGE 0.4 0.1 8.4 -13.5

6.0 2.0 -3.0 -0.2 1 199036 1.8 85S-WRECK_1

0.6-0.6 -0.3 1.035 0.5 142.8 0.3 199690 1.036 1C-TUPPER0.994 143.0 1.014 24.9 199116 70.0 16N-STEWIAKE 1.6

199054 2.4 5.4 -16.6 47C-NEW_PAGE 1.031 199692 120C-BEARHD 1.000 142.3 Bus - Voltage (kV/pu) 13.8 199691

-17.0-4.6 17.0

17.0 120C-BEARHD Branch - MW/Mvar 1.025 4.6 -3.6R Equipment - MW/Mvar 0.963 100.0%Rate A 0.4 1.050OV 0.970UV kV: <=35.000 <=69.000 <=138.000 <=230.000 <=345.000 >345.000 2021 LIGHT LOAD: 2021LL-1 - FULL WIND ON BACKBONE Total Wind Gen: 207.5 MW Gross Tupper 0.0 MW Gross Wreck Cove 0.0 MW Net NewPage Load 61.9 MW Summer Ratings FROM UPDATE OF 2014 SERIES MMWG 2020 SPRING LIGHT LOAD Gross Lingan 70.0 MW Gross Trenton 70.0 MW Gross Gas Turbine 0.0 MW Gross NewPage Load 61.9 MW Figure ___D-2 SUN, OCT 01 2017 0:00 Gross Pt Aconi 70.0 MW Gross Tuft's Cove 70.0 MW Gross Small Hydro 14.6 MW Total BMPC Load -0.9 MW Includes 70% Distributed Generation Total Gross Gen: 502.1 MW ML HVDC: 410.0 MW Gross Gen + ML: 912.1 MW modeled as Negative Load: -143.0 MW 1 2018 10 Year System Outlook Report Appendix B Page 62 of 84

EEXS: 27.2 MW NB to NE: 802.7 MW EEXEB: 13.2 MW NB to QC: 596.2 MW ML HVDC: -100.0 MW NSX -99.4 MW MAINLAND AT HASTINGS: -16.8 MW CBX -11.2 MW HASTINGS FROM 88S,5S,2S: 46.1 MW ONI 133.6 MW 1.013 199137 199555 69.9 3N-OXFORD FORCE_HV L-7011:18.5 MW ONS 262.5 MW 1.000 5.0 2.5 199138 199147 1 199557 7N-PUGWASH 37N-PARSBORO 0.7 -0.9R IR516_G L-7012: 20.0 MW NB to PEI: 80.2 MW 1.3 2.5 -2.5 1.4 12.4 -14.414.5 1.000 4.0 Nova Scotia New Brunswick 1 199558 L-7011 + L-7012: 38.5 MW 0.4 IR517 5.5 5.5 -5.5 0.1 -0.5 0.5 -3.8 3.0 -3.0 -0.6R 190401 1.011 1.012 1.009 5.6 MEM138 0.7 1.3 -1.5 1 199559 69.8 69.8 0.7 0.0H IR542_G 190075 190150 190197 SACK138 MEM69 1.012 199530 C.COVE 199139 69.8 92N-AMHSTWIN 199531 199533 3.7 -12.2 -25.6 25.7 10N-ABER_ST 92N-AMHSTLV 92N-AMHSTGEN 1.024 199146 199145 1 3.1 -3.1 14.1 0.9875 30N-MACCAN 30N-MACCAN 141.3 -7.1 -24.8 1 -24.9 25.0 1.0 -2.9 5.7 -6.9 1.011

-12.3 -1.0 1.015 -3.7 1.029 1.024 348.7 1.6 -1.7 4.0 1 1 70.1 -88.5 71.0 141.3 189.2 3.7 4.7 6.5 4.3 -3.3L 199136 1.016 1.015 1.009 1.006 190379 74N-SPRINGHL 70.1 70.0 34.8 0.6 BOR1159 -21.2 21.3 -14.2 14.2 10.6 L6535 -10.6 -10.6 6.8 -6.8 -23.9 24.0 3.7 0.8

4.9 L6514 -6.1 1.4 L6551 -2.1 -4.4 4.1 2.7 -3.5 3.0 5.7 -6.9 36 Mvar 1.024 1.024 141.3 141.3 1.023 1.023 141.2 141.2 199152 190408 1.027 22N-CHURCHST BOR1160 190258 190498 -188.0 L6513 -1.2 L6536 50.9 8.3 1.2 -6.6 -6.6 6.6 MURRCRNORTON 354.3 -8.0 -0.9 -0.5 -0.8 -0.1 -1.4 1.024 190341 1.023 199135 141.3 HARDRD 30.6 -30.3 29.1 -29.0 141.2 5.4 1.3 199134 4.1 74N-SPRNGHIL 199125 1.6 81N-DEBERT 67N-ONSLOW -78.9 -26.5 25.2 -25.6 25.1 201.8 199195 0.5 1.2 0.3 1.043 1.048 103H-LAKSIDE 1.029 143.9 144.7 6.7 -8.3 -83.6 -4.6 142.1 L8002 83.8 190320 -30.5 -26.2 190402 SALBRY 1.039 MEM345 358.5 0.0 + 37.5 MVar 40.3 190381 -41.3 BR3025 0.0 -200.9 31.5 -103.4 L8001 103.8 190417

1.0375 40.3 51.3 -26.3 -34.9 1.024 BATHURST -145.1 145.4 -12.9 13.1 199130 141.4 67N-ONSLOW 64.9 199045 -82.9 5.3 -103.6 101S-WOODBIN 0.0 1.003 199120 199042 346.1 79N-HOPWELL 101S-WOODBIN 1.037 26.90.0 36.0 357.9 1.045 199043 1 -51.8 51.9 -5.6 360.4 5.6 53.0 102S-ACONI 26.90.0 19.5 199200 13.7 L8003 -42.4 -36.5 L8004 -75.9 57.1 -85.4 L7015 85.7 120H-BRUSHY 0.0 100.0 L7001 26.9 35.5 1.01 199855 -27.3 199001 -42.1 26.942.3 1 NS_DC_POLE1 21.4 32.9R 19.3 88S-LINGAN_1 -50.0 52.6 100.0 0.2 -13.2 199121 79N-HOPWELL-23.2 -46.3 14.2 -53.4R 1 -19.9 29.5R 1.043 6.1 78.9 199593 0.999 7.3 -41.2 L7002 41.4 0.0 0.98 0.0 359.7 91N-DALHOGEN 199050 119.9 199857 42.0 3C-HASTINGS NS_DC_POLE2 1.000 8.1 -0.1 -13.2 31.9 52.3 -23.2 0.0 -50.0 0.0 -19.6 L7014 20.0 19.6 1.038 199590 -0.6R 4.1 358.2 91N-DALHOUS 6.1 31.9 1.024 -53.4R 2 * 50 Mvar 52.3 -17.0 10.0 0.6 0.999 -59.7 L7018 59.9 -40.6 L7019 2 * 30 Mvar 40.7 -0.2 L7004 0.2 -18.4 18.5 -19.5 L7021 19.5 119.9 1.025 0.980 353.6 14.1 -2.1 -15.8 -8.8 3.6 -13.2 -12.6 13.7 L7011 -32.4 -15.7 8.9 1.041 -7.6 239.4 L7003 7.7 -19.9 L7012 20.0 -19.6 L7022 19.6 199202 -16.6 -14.0 13.6 -32.5 -16.9 10.0 120H-BRSHSVC 199002 199010 88S-LINGAN_2 0.0 -7.9 L7005 7.9 199110 199015 199016 2S-VJ 1.022 1N-ONSLOW 15S-WATRFORD-0.0 0.0 109S-LINWIND 235.2 0.0R -17.8 -13.4 199051 16.0 -0.2 0.2 4.3 -4.3 2C-HASTINGS 199019 -6.7 1 23.2 23.2 1.025 199100 70.7 81S-RESERVE -15.5 12.0 -12.0 -12.0 12.0 -12.0 1.4 -1.6 1.037 49N-MICHGRAN

3.7 -7.5 -7.5 1 1 238.6 1.037 199076 -1.1R 2.0 2.9 -3.0 3.0 1.000 238.5 11.3 3.1 -3.1 2.1 -2.1 6.4 199154 199090 199610 4C-LOCHABER 199075 1.001 14.4 82V-ELMSDALE 50N-TRENTON 93N-GLENDHU 100C-PORCUPN 1 6.4 199423 0.4 0.3 -0.5 0.3 -0.3 2.0 11.4 3.1 109S-LINWIND 1.025 -34.8 L6001 35.1 L6503 37.1 -19.6 L651119.7 28.8 L6552 -28.7 36.8 L6515 -36.5 32.5 L6515 -25.6 25.7 -32.5 70.7 11.3 9.0 2.0 -4.0 1.5 -4.6 -1.7 -3.81.5 -8.1 7.1 -10.0 8.2 -9.7 9.6 199007 1.021 2S-VICTORIA 70.4 1.025 1 6.4 199063 199056 7.5 199003 141.4 199091 22C-CLEVLAND 59C-STPETERS 0.99 88S-LINGAN_3 50N-TRENTON -48.5 0.0 -8.1 4.0 50 Mvar 1.035 9.1 6.5 0.0 2.9 1.5 4.5 199006 7.6 1.041 0.99 88S-LINGAN_B 5.3 L6516 L6533 1.036 1.037 1.038 239.5 1.024 1.025 -0.8 5.0 -16.4 16.4 16.4 143.0 143.1 143.3 3.1 0.8 1.0 0.2 70.7 199053 3.4 -11.1 4.7 -5.5 -5.3 2.9 4.4 80.0 47C-NEW_PAGE 1.01 L6518 1.037 1.035 1.020 199611 -30.8 30.9 0.9 5.1 -2.8R 199057 143.1 142.8 140.7 1.000 1.01 1.01 93N-GLENDHUM -2.9 2.9 67C-WHYC_TAP 199005 -1.5 0.9 199033 199031 199025 14.4 199072 104S-BADDECK 5S-GLEN_TOSH 3S-GANNON_RD 88S-LINGAN_A 1.034 1.4 -2.4 L6534 199112 71.4 1.030 48C-BIOMASS 199004 L6517 -2.0 L6537 2.0 -2.6 2.6 -4.4 L6538 4.4 L6539 9.8 -16.5 16.6 16.6 1N-ONSLOW_B 199111 142.2 199118 1.005 88S-LINGAN_4 4N-TATAMAG 0.0 0.0 -31.1 24.0 0.9 -0.9 199114 1N-ONSLOW_A 199580 34.70.9 -48.6

1 2.1 -3.8 3.4 -4.3 10.3 -12.5 -13.7 5.0 -5.9 -5.7 15N-WILLOWLN 1.01 89N_NUTBTP 8.0 1.2 -1.2 1.2 -0.0 -1.1 2.6 -4.0 0.2 1.020 1.021 140.7 7.3 -29.1 38.1 1.036 199612 14.3 140.8 0.99375 0.1 -0.5 0.5 93N-GLENDHUG 0.6 5.3 199584 1.038 1.041 199026 0.3 13.2 -6.8 1.034 0.99 89N_NUTBG 1.042 199581 71.4 143.3 143.7 3S-GANNON_RD

0.9875 0.4 1.2 2.6 71.9 89N_NUTBHV 49.8 1.028 -39.3 39.3 40.0 L6523 1.036 1.030 1.030 71.5 236.3 1.000 142.2 3.7 1.02535.5

-2.6 14.4

6.7 -6.7 -0.0R -49.8 1.043 1.8 1.0360.989 199613 1.040 1.029 199035 72.0 71.5 0.4 93N-GLENDHU 143.5 142.1 85S-WRK_COVE 1.036 199037 -4.2 4.2 0.9 L6545 -0.9 3.6 71.5 85S-WRECK_2 1.2 199052 -8.1 -1.3 1.0 -3.3 -3.0 -0.2 31.1 -24.0

0.6 0.1 1C-TUPPER

1.019 1.024 50.0 1.036 4.8R 199115 70.3 70.6 143.0 0.9 L6549 -0.9

11N-LAFARGE 0.4 0.1 9.2 -13.5

6.0 2.0 -3.0 -0.2 1 199036 1.8 85S-WRECK_1 0.6 -0.6 -0.3 1.038 0.5 143.3 0.3 199690 1.040 1C-TUPPER0.996 143.5 1.019 24.9 199116 70.3 16N-STEWIAKE 1.6

199054 2.4 6.2 -16.6 47C-NEW_PAGE 1.036 199692 120C-BEARHD 1.000 143.0 Bus - Voltage (kV/pu) 13.8 199691

-17.0-5.4 17.0

17.0 120C-BEARHD Branch - MW/Mvar 1.025 5.4 -4.3R Equipment - MW/Mvar 0.961 100.0%Rate A 0.4 1.050OV 0.970UV kV: <=35.000 <=69.000 <=138.000 <=230.000 <=345.000 >345.000 2021 LIGHT LOAD: 2021LL-2 - FULL WIND ON BACKBONE Total Wind Gen: 207.5 MW Gross Tupper 0.0 MW Gross Wreck Cove 0.0 MW Net NewPage Load 61.9 MW Summer Ratings FROM UPDATE OF 2014 SERIES MMWG 2020 SPRING LIGHT LOAD Gross Lingan 100.0 MW Gross Trenton 80.0 MW Gross Gas Turbine 0.0 MW Gross NewPage Load 61.9 MW Figure ___D-3 SUN, OCT 01 2017 0:29 Gross Pt Aconi 100.0 MW Gross Tuft's Cove 70.0 MW Gross Small Hydro 14.6 MW Total BMPC Load -0.9 MW Includes 70% Distributed Generation Total Gross Gen: 572.1 MW ML HVDC: -100.0 MW Gross Gen + ML: 472.1 MW modeled as Negative Load: -143.0 MW 1 2018 10 Year System Outlook Report Appendix B Page 63 of 84

EEXS: 39.0 MW NB to NE: 805.8 MW EEXEB: 318.4 MW NB to QC: -300.1 MW ML HVDC: 475.0 MW NSX -0.6 MW MAINLAND AT HASTINGS: 202.8 MW CBX 468.6 MW HASTINGS FROM 88S,5S,2S: 326.5 MW ONI 602.6 MW 1.029 199137 199555 71.0 3N-OXFORD FORCE_HV L-7011:134.5 MW ONS 590.5 MW 1.004 5.0 2.9 199138 199147 1 199557 7N-PUGWASH 37N-PARSBORO 0.7 -1.0L IR516_G L-7012: 139.3 MW NB to PEI: 159.2 MW 0.2 4.6 -4.6 1.9 10.2 -14.414.5 1.007 4.0 Nova Scotia New Brunswick 1 199558 L-7011 + L-7012: 273.8 MW 0.4 IR517 4.8 10.4 -10.4 0.1 -0.5 0.1 -3.7 3.5 -3.5 -1.0L 190401 1.026 1.023 1.018 5.6 MEM138 2.0 1.7 -1.8 1 199559 70.8 70.6 0.7 0.0H IR542_G 190075 190150 190197 SACK138 MEM69 1.022 199530 C.COVE 199139 70.5 92N-AMHSTWIN 199531 199533 7.3 -24.2 -34.5 34.8 10N-ABER_ST 92N-AMHSTLV 92N-AMHSTGEN 1.040 199146 199145 1 4.8 -4.8 20.1 0.9875 30N-MACCAN 30N-MACCAN 143.6 -4.3 -30.7 1.025 -30.9 31.0 1.8 -5.9 29.9 -30.4 1.026

-10.2 -1.8 1.032 -7.3 1.036 1.029 354.0 2.3 -2.3 6.6 1

71.2 -64.9 71.5 141.9 155.7 3.5 5.7 0.5 3.5 -2.0R 199136 1.034 0.99 1.027 1.020 1.020 190379 74N-SPRINGHL 71.3 70.9 35.2 0.6 BOR1159 -17.4 17.4 -13.2 13.2 17.5 L6535 -17.5 -17.5 10.1 -10.1 -31.8 32.0 7.3 1.6

-2.2 L6514 0.9 -6.6 L6551 5.9 -6.4 6.0 4.7 -6.3 5.9 29.6 -30.1 36 Mvar 1.040 1.028 143.5 141.9 1.037 1.039 143.1 143.4 199152 190408 1.035 22N-CHURCHST BOR1160 190258 190498 -155.0 L6513 10.9 L6536 21.5 -13.5 -10.9 -5.0 -5.0 5.1 MURRCRNORTON 357.0 0.8 -5.2 3.8 -7.5 -6.8 5.2 1.037 190341 1.034 199135 143.1 HARDRD 62.2 -61.4 59.0 -58.9 3.7

142.7 15.9 199134 -4.6 74N-SPRNGHIL 199125 81N-DEBERT 8.4 67N-ONSLOW -9.8 -11.1 11.9 -12.5 12.6 117.6 199195 0.6 2.3 0.6 1.039 1.040 103H-LAKSIDE 1.033 143.4 143.5 -187.1 4.0 142.6 L8002 188.2 -22.0 13.6 190320 -9.3 -36.7 190402 SALBRY 1.026 MEM345 353.9 0.0 + 37.5 MVar 39.8 190381 -122.1 BR3025 0.0 -117.3 -84.5 -13.1 L8001 13.1 190417

0.9375 39.8 -24.6 -20.6 -42.3 1.041 BATHURST -135.3 135.5 -192.6 194.9 199130 143.7 67N-ONSLOW -54.1 199045 36.0 6.0 -82.6 101S-WOODBIN 1.014 0.0 0.0 199120 199042 349.9 79N-HOPWELL -16.1 101S-WOODBIN 1.031 26.20.0 57.2 355.6 1.023 199043 1 -288.7 289.6 -262.7 353.1 265.8 -103.6 102S-ACONI 26.20.0 13.9 199200 29.6 L8003 -43.7 -31.5 L8004 -35.2 67.8 -105.2 L7015 105.7 120H-BRUSHY 0.0 120.0 26.2 1.01 L7001 56.4 0.0 199855 -2.6 199001 -95.3 26.296.2 1 NS_DC_POLE1 -2.2 11.0R 13.8 -16.1 88S-LINGAN_1 237.5 -105.6 90.0 8.5 -16.1 199121 79N-HOPWELL-13.5 -26.9 14.2 -33.4R 1 -10.8 34.2R 1.027 5.4 75.2 199593 1.013 7.3 -93.3 L7002 94.2 0.0 0.98 354.3 91N-DALHOGEN 199050 121.5 199857 49.5 3C-HASTINGS NS_DC_POLE2 0.990 8.1 8.0 -16.1 31.1 -13.5 0.0 237.5 13.7 L7014 19.8 -13.7 1.024 199590 3.2R 4.1 353.3 91N-DALHOUS 5.4 31.1 1.028 -33.4R 2 * 50 Mvar -7.1 -0.0 0.6 1.013 -135.0 L7018 135.9 -108.2 L7019 2 * 30 Mvar 108.9 -61.4 L7004 62.2 -132.2 134.5 13.1 L7021 -13.1 121.5 1.035 0.990 357.1 14.3 6.2 -16.7 3.8 -6.3 -3.1 -17.7 15.5 L7011 -18.8 -7.5 0.4 1.028 -69.6 236.4 L7003 71.1 -137.5 L7012 139.3 13.7 L7022 -13.7 199202 -2.3 -20.5 10.8 -13.9 -7.1 -0.0 120H-BRSHSVC 199002 199010 88S-LINGAN_2 0.0 -74.1 L7005 74.9 199110 199015 199016 2S-VJ 1.033 1N-ONSLOW 15S-WATRFORD-5.2 5.2 109S-LINWIND 237.7 -0.1R -9.2 -13.8 199051 -39.2 -1.3 1.3 1.1 -1.1 2C-HASTINGS 199019 22.0 1 13.5 13.5 1.026 199100 70.8 81S-RESERVE 23.1 14.0 -14.0 -14.0 8.8 -8.8 -0.4 0.1 1.022 49N-MICHGRAN

-4.8 -6.9 -6.9 1 1 235.0 1.023 199076 -1.0R 2.2 3.4 -4.7 4.6 0.990 235.3 30.8 0.7 -0.7 0.7 -0.7 1.8 199154 199090 199610 4C-LOCHABER 199075 1.000 14.3 82V-ELMSDALE 50N-TRENTON 93N-GLENDHU 100C-PORCUPN 12.81 199423 0.4 -0.5 0.3 0.1 -0.1 0.0 19.9 8.9 109S-LINWIND 1.027 -74.5 L6001 76.0 L6503 82.6 -36.6 L651136.8 21.0 L6552 -20.9 11.7 L6515 -11.7 5.4 L6515 -61.9 62.6 -5.4 70.9 30.8 26.1 6.8 -3.1 19.5 -17.7 -8.3 4.6-6.0 -4.9 3.7 -9.7 6.7 -11.5 11.3 199007 1.029 2S-VICTORIA 71.0 1.018 12.81 199063 199056 15.9 199003 0.0 0.99 140.5 199091 22C-CLEVLAND 59C-STPETERS 88S-LINGAN_3 50N-TRENTON -57.8 16.2 -7.0 6.3 50 Mvar-53.3 0.995 26.5 10.9 2.2 3.8 4.8 21.3 199006 16.0 1.031 0.99 88S-LINGAN_B 10.9 L6516 L6533 1.018 1.018 1.025 237.1 1.029 1.025 -19.7 30.2 -60.3 60.5 60.6 140.5 140.5 141.4 7.9 2.5 2.1 0.6 71.0 199053 3.2 -6.6 -10.3 10.7 12.2 10.2 20.7 130.0 47C-NEW_PAGE 0.99 L6518 1.026 1.028 1.039 199611 -52.1 52.3 3.2 10.6 22.0R 199057 141.5 141.9 143.4 0.990 1.04 1.04 93N-GLENDHUM -10.9 10.9 67C-WHYC_TAP 199005 -5.5 5.5 199033 199031 199025 14.3 199072 104S-BADDECK 5S-GLEN_TOSH 3S-GANNON_RD 88S-LINGAN_A 1.043 -2.3 1.4 L6534 199112 71.9 1.016 48C-BIOMASS 199004 L6517 -19.7 L6537 19.7 -22.4 22.5 -24.7 L6538 24.8 L6539 39.0 -61.5 61.7 61.7 1N-ONSLOW_B 199111 140.2 199118 0.980 88S-LINGAN_4 4N-TATAMAG 45.0 -44.9 -44.9 -48.2 41.3 -8.8 8.8 199114 1N-ONSLOW_A 199580 33.82.5 -58.0

1 0.2 -1.6 0.7 -1.4 6.5 -8.3 -5.4 -9.5 9.7 11.4 15N-WILLOWLN 0.99 89N_NUTBTP 2.6 4.7 -4.7 4.7 5.7R -2.1 -3.1 6.1 -1.9 -1.6 1.039 1.032 143.4 23.4 -30.4 44.2 1.030 199612 14.2 142.5 0.99375 1.0 -1.4 1.4 93N-GLENDHUG 2.7 13.9 199584 1.025 1.028 199026 -1.4 16.7 -9.2 1.027 0.99 89N_NUTBG 1.020 199581 70.8 141.5 141.9 3S-GANNON_RD

1.0113 0.9 4.1 2.8 70.4 89N_NUTBHV 59.7 1.034 -48.9 48.9 50.0 L6523 1.028 1.033 1.010 70.9 237.8 0.961 142.5 6.9 1 34.8

-2.8 13.8

8.2 -8.1 2.3R -59.7 1.022 3.5 1.0330.992 199613 1.030 1.029 199035 70.5 71.3 0.4 93N-GLENDHU 142.1 142.0 85S-WRK_COVE 1.032 199037 -5.3 5.3 1.1 L6545 -1.1 4.8 71.2 85S-WRECK_2 -0.3 199052 -2.6 0.5 -0.8 -6.4 -2.5 -0.7 48.2 -41.2

0.5 1C-TUPPER -0.2

1.020 1.022 60.0 1.021 5.9R 199115 70.4 70.5 140.9 1.1 L6549 -1.1

11N-LAFARGE 1.0 0.0 7.0 -14.0

6.0 2.0 -2.6 -0.7 1 199036 2.2 85S-WRECK_1 0.5 -0.5 -0.0 1.031 1.3 142.3 0.0 199690 1.032 1C-TUPPER0.991 142.4 1.020 24.8 199116 70.4 16N-STEWIAKE 2.7

199054 6.1 1.7 -21.4 47C-NEW_PAGE 1.021 199692 120C-BEARHD 1.000 140.9 Bus - Voltage (kV/pu) 13.8 199691

-22.0-0.5 22.0

22.0 120C-BEARHD Branch - MW/Mvar 1.025 0.5 1.0R Equipment - MW/Mvar 0.990 100.0%Rate A 0.4 1.050OV 0.970UV kV: <=35.000 <=69.000 <=138.000 <=230.000 <=345.000 >345.000 2021 SUMMER PEAK: 2021SUM - FULL WIND ON BACKBONE Total Wind Gen: 303.7 MW Gross Tupper 0.0 MW Gross Wreck Cove 0.0 MW Net NewPage Load 100.3 MW DERIVED FROM UPDATE OF 2014 SERIES MMWG 2020 SUMMER PEAK Gross Lingan 90.0 MW Gross Trenton 130.0 MW Gross Gas Turbine 0.0 MW Gross NewPage Load 145.3 MW Summer Ratings Figure ___D-4 SAT, SEP 30 2017 18:46 Gross Pt Aconi 120.0 MW Gross Tuft's Cove 109.0 MW Gross Small Hydro 74.3 MW Total BMPC Load -0.5 MW Total Gross Gen: 827.0 MW ML HVDC: 475.0 MW Gross Gen + ML: 1302.0 MW 1 2018 10 Year System Outlook Report Appendix B Page 64 of 84

EEXS: 108.8 MW NB to NE: 806.7 MW EEXEB: 444.0 MW NB to QC: -300.1 MW ML HVDC: 475.0 MW NSX 329.5 MW MAINLAND AT HASTINGS: 312.0 MW CBX 679.7 MW HASTINGS FROM 88S,5S,2S: 439.7 MW ONI 951.7 MW 1.024 199137 199555 70.7 3N-OXFORD FORCE_HV L-7011:178.8 MW ONS 608.5 MW 199138 199147 1.000 5.0 199557 2.9 1 7N-PUGWASH 37N-PARSBORO 0.7 -1.0L IR516_G L-7012: 184.6 MW NB to PEI: 159.2 MW 0.2 4.6 -4.6 1.9 10.2 -14.414.5 1.004 4.0 199558 Nova Scotia New Brunswick L-7011 + L-7012: 363.4 MW 1 0.4 IR517 4.8 10.4 -10.4 0.1 -0.5 0.1 -3.7 3.6 -3.5 -1.0L 190401 1.021 1.019 1.014 5.6 199559 MEM138 2.0 1.7 -1.8 1 70.5 70.3 0.7 0.0H IR542_G 190075 190150 190197 SACK138 MEM69 1.019 199530 C.COVE 199139 70.3 92N-AMHSTWIN 199531 199533 10N-ABER_ST 92N-AMHSTLV 92N-AMHSTGEN 7.3 -24.2 -6.7 6.8

199146 199145 1 1.040 4.8 -4.8 20.1 0.9875 30N-MACCAN 30N-MACCAN 143.5 -4.3 -30.7 1.025 -30.9 31.0 1.8 -5.9 24.8 -26.1 1.026 -10.2 -1.8 1.028 -7.3 1.027 2.3 -2.3 6.6 1 1.036 354.0 70.9 3.5 71.5 141.8 -16.9 -45.2 5.8 0.0 3.0 -1.5R 199136 1.029 0.99 1.024 1.019 1.020 190379 74N-SPRINGHL 71.0 70.6 35.1 0.6 BOR1159 43.0 L6535

8.0 -8.0 12.3 -12.2 -42.9 -42.77.3 35.31.6 -35.3 -4.5 4.6

-10.1 L6514 8.8 -14.6 L6551 13.9 -13.9 13.8 13.4 -14.9 14.7 24.8 -25.9 36 Mvar 1.037 1.027 143.2 141.8 1.034 1.037 142.6 143.1 199152 190408 22N-CHURCHST BOR1160 190258 190498 1.033 17.0 L6513 42.4 L6536 -5.6 -70.5 -42.2 26.3 26.2 -26.1 MURRCRNORTON 356.3

17.9 -14.4 13.9 -17.6 -17.1 16.0 1.035 190341 1.030 199135 142.8 HARDRD

3.7 62.2 -61.4 59.0 -58.9 15.9 199134 -15.7 142.1 74N-SPRNGHIL 199125

8.4 19.8 81N-DEBERT 67N-ONSLOW -71.1 -11.2 12.0 -12.5 12.7 2.3 0.6 199195 0.6 1.039 1.040 103H-LAKSIDE 143.4 143.5 1.020 L8002 -183.8 15.1 184.9 -79.6140.7 71.2 190320 -3.7 -40.6 190402 SALBRY MEM345 1.012 349.0 0.0 + 37.5 MVar 190381 -142.2 39.5 BR3025 0.0 71.2 -90.5 260.3 L8001 -257.9

0.925 190417 39.5 -55.5 1.041 BATHURST -45.0 10.6 115.5 199130 143.7 -115.2 -140.3 141.5 67N-ONSLOW -116.5 199045 99.2 -10.8 -76.5 101S-WOODBIN 0.0 1.013 199120 0.0 199042 349.6 79N-HOPWELL -16.1 101S-WOODBIN 1.026 25.30.0 15.4 1.014 199043353.9 1 -475.8 478.4 -361.7 349.7 367.7 -52.9 102S-ACONI 25.30.0 15.9 199200 54.1 L8003 -41.8 -24.4 L8004 2.7 54.5 L7015 120H-BRUSHY 0.0 -159.5 160.6 175.0 25.3 1.01 L7001 15.2 199855 0.0 5.7 199001 25.3 1 -4.6 16.4R -100.5 101.5 NS_DC_POLE1 88S-LINGAN_1 15.7 -16.1 237.5 -54.4 160.0 13.3 -19.6 199121 79N-HOPWELL-58.4 -116.7 14.2 -3.6R 1 -24.0 37.8R 1.011 199593 7.3

-0.5 0.98 66.2 1.027 -98.4 L7002 99.4 0.0 91N-DALHOGEN 348.9 199050 123.3 199857 49.5 3C-HASTINGS NS_DC_POLE2 0.990 8.1 12.8 -19.5 30.4 -58.4 0.0 237.5 -32.5 L7014 19.8 32.5 1.009 199590 6.7R 4.1 347.9 91N-DALHOUS -0.5 30.4 1.032 -3.6R 2 * 50 Mvar -9.9 3.0 0.6 1.027 -142.6 L7018 143.6 -144.1 L7019 2 * 30 Mvar 145.3 -97.9 L7004 99.8 -174.7 178.8 -31.6 L7021 31.7 123.3 1.035 0.990 357.1 14.3 12.7 -21.3 10.6 -10.2 4.3 -17.0 16.8 L7011 -7.6 -8.4 1.6

1.012 L7003 L7012 L7022 -105.3 232.8 108.9 -181.4 184.6 -32.5 32.5 199202 10.5 -0.5 -9.9 3.0 120H-BRSHSVC 8.0 -20.1 199002 199010 88S-LINGAN_2 0.0 -112.5 L7005 114.5 199110 199015 199016 2S-VJ 1.032 1N-ONSLOW 15S-WATRFORD-5.2 5.2 109S-LINWIND 237.3 -0.3R -2.0 -9.5 199051 -48.1 -1.3 1.3 1.1 -1.1 2C-HASTINGS 199019 79.8 1 58.7 58.7 1.025 199100 70.7 81S-RESERVE 27.4 14.0 -14.0 -14.0 8.8 -8.8 -0.4 0.1 1.008 49N-MICHGRAN -14.2 0.7 0.7 1 1 231.8 1.007 199076 -0.9R 2.1 3.3 -4.6 4.5 0.990 199154 231.6 4C-LOCHABER 16.5 0.7 -0.7 0.7 -0.7 1.8 199090 199610 199075 1.000 14.3 82V-ELMSDALE 50N-TRENTON 93N-GLENDHU 100C-PORCUPN 1 9.6 199423 0.4 -0.5 0.3 0.1 -0.1 0.0 19.9 8.9 109S-LINWIND 1.026 -77.4 L6001 79.1 L6503 136.2 -30.8 L651131.0 26.8 L6552 -26.7 17.5 L6515 -17.5 11.2 L6515 -114.0 116.0 -11.1 70.8 16.5 26.1 10.2 -5.6 25.9 -10.8 0.2 4.7-6.3 -3.2 2.2 -7.7 4.9 -9.7 9.5 199007 1.028 2S-VICTORIA 1.007 1 9.6 199063 199056 70.9 199003

0.99 15.8 138.9 0.0 199091 22C-CLEVLAND 59C-STPETERS 88S-LINGAN_3 50N-TRENTON -57.8 16.2 -7.0 6.3 50 Mvar-51.8 0.995 26.5 9.5 2.2 3.3 4.8 21.3 120.0 199006 16.0 0.99 88S-LINGAN_B 1.019 10.9 27.2R L6516 L6533 234.4 1.025 1.013 1.011 1.014 1.028

-32.7 7.9 2.5 2.1 0.6 43.8 -72.2 72.4 72.5 139.8 139.5 139.9 70.9 199053 4.4 -5.0 -12.0 12.9 15.1 10.2 20.7 160.0 47C-NEW_PAGE 0.99 -52.1 L6518 52.3 1.015 1.019 1.039 199611 199057 140.1 140.7 143.4 0.990

3.2 1.04 1.04 10.7 31.2R 93N-GLENDHUM -10.9 10.9 67C-WHYC_TAP 199005 -2.3 2.2 199033 199031 199025 14.3 199072 104S-BADDECK 5S-GLEN_TOSH 3S-GANNON_RD 88S-LINGAN_A 1.038 -2.3 1.4 L6534 199112 71.6 1.012 48C-BIOMASS 199004 L6517 -29.6 L6537 29.7 -32.4 32.5 -34.7 L6538 34.9 L6539 49.2 -73.5 73.9 73.9 1N-ONSLOW_B 199111 139.6 199118 0.978 88S-LINGAN_4 4N-TATAMAG 45.0 -44.9 -44.9 41.3 -18.6 18.7 100.0 199114 1N-ONSLOW_A 199580 33.71.1 -48.2 -58.0 1 15N-WILLOWLN 0.5 -1.6 0.6 -1.2 6.2 -7.4 -3.8 -11.0 11.7 0.99 14.1 89N_NUTBTP 4.4 4.7 -4.7 4.7 11.2R -7.5 -8.5 3.3 -1.2 -2.0 1.039 34.0R 1.030 1.031 143.4 23.4 -30.4 44.2 199612 142.3

0.98125 14.2 1.0 -1.4 1.4 93N-GLENDHUG 2.7 13.9 8.0 199584 199026 -1.4 16.5 -9.0 1.026 1.015 1.019 0.99 89N_NUTBG 3S-GANNON_RD 1.019 199581 70.8 140.0 140.7

4.2 0.9 4.1 4.1 59.7 70.3 0.99875 89N_NUTBHV 1.035 -48.9 48.9 50.0 L6523 1.023 1.018 1.010 70.6 238.0 0.990 6.9 140.5 1 34.8-4.2 14.3

8.0 -7.9 2.5R -59.7 199613 1.020 3.5 1.0320.993 1.023 1.025 199035 93N-GLENDHU 70.4 71.2 0.4 141.1 141.4 85S-WRK_COVE 1.032 L6545 199037 4.8 -5.3 5.3 71.2 1.1 -1.1 85S-WRECK_2 199052 -0.3 -4.4 -3.6

0.5 -0.8 48.2 -2.5 -0.7 -41.2

0.5 1C-TUPPER -0.2

1.021 60.0 1.011

1.019 7.3R 199115 70.3 70.5 139.5 1.1 L6549 -1.1

11N-LAFARGE 1.0 0.0 6.0 -14.0

6.0 2.0 -2.5 -0.7 1 199036 2.2 85S-WRECK_1 -0.5 0.5 0.0 1.024 1.3 141.4 0.0 199690 1.025 1C-TUPPER0.985 141.5 1.019 24.6 199116 70.3 16N-STEWIAKE 2.7

199054 6.1 0.8 -21.4 47C-NEW_PAGE 1.011 199692 120C-BEARHD 1.000 139.5 Bus - Voltage (kV/pu) 13.8 199691

-22.00.4 22.0

22.0 120C-BEARHD Branch - MW/Mvar 1.025 -0.4 2.0R Equipment - MW/Mvar 0.990 100.0%Rate A 0.4 1.050OV 0.970UV kV: <=35.000 <=69.000 <=138.000 <=230.000 <=345.000 >345.000 2021 SUMMER PEAK: 2021SUM-1 - FULL WIND ON BACKBONE Total Wind Gen: 303.7 MW Gross Tupper 0.0 MW Gross Wreck Cove 0.0 MW Net NewPage Load 100.3 MW Summer Ratings DERIVED FROM UPDATE OF 2014 SERIES MMWG 2020 SUMMER PEAK Gross Lingan 260.0 MW Gross Trenton 280.0 MW Gross Gas Turbine 0.0 MW Gross NewPage Load 145.3 MW Figure ___D-5 SAT, SEP 30 2017 19:18 Gross Pt Aconi 175.0 MW Gross Tuft's Cove 92.0 MW Gross Small Hydro 74.3 MW Total BMPC Load -0.5 MW Includes 70% Distributed Generation Total Gross Gen: 1185.0 MW ML HVDC: 475.0 MW Gross Gen + ML: 1660.0 MW modeled as Negative Load: -143.0 MW 1 2018 10 Year System Outlook Report Appendix B Page 65 of 84

EEXS: 33.5 MW NB to NE: 807.1 MW EEXEB: 295.2 MW NB to QC: -300.1 MW ML HVDC: 475.0 MW NSX -99.7 MW MAINLAND AT HASTINGS: 183.7 MW CBX 429.5 MW HASTINGS FROM 88S,5S,2S: 306.9 MW ONI 525.1 MW 1.028 199137 199555 70.9 3N-OXFORD FORCE_HV L-7011:126.5 MW ONS 612.1 MW 199138 199147 1.003 5.0 199557 2.9 1 7N-PUGWASH 37N-PARSBORO 0.7 -1.0L IR516_G L-7012: 131.0 MW NB to PEI: 159.2 MW 0.2 4.6 -4.6 1.9 10.2 -14.414.5 1.006 4.0 199558 Nova Scotia New Brunswick L-7011 + L-7012: 257.4 MW 1 0.4 IR517 4.8 10.4 -10.4 0.1 -0.5 0.1 -3.7 3.5 -3.5 -1.0L 190401 1.025 1.022 1.017 5.6 199559 MEM138 2.0 1.7 -1.8 1 70.7 70.5 0.7 0.0H IR542_G 190075 190150 190197 SACK138 MEM69 1.021 199530 C.COVE 199139 70.5 92N-AMHSTWIN 199531 199533 10N-ABER_ST 92N-AMHSTLV 92N-AMHSTGEN 7.3 -24.2 -42.8 43.2

199146 199145 1 1.040 4.8 -4.8 20.1 0.9875 30N-MACCAN 30N-MACCAN 143.5 -4.3 -30.7 1.025 -30.9 31.0 1.8 -5.9 33.8 -33.7 1.025 -10.2 -1.8 1.031 -7.3 1.027 2.3 -2.3 6.6 1 1.036 353.7 -61.6 71.2 3.5 71.5 141.8 197.1 5.8 0.4 3.3 -1.9R 199136 1.033 0.99 1.026 1.019 1.020 190379 74N-SPRINGHL 71.2 70.8 35.2 0.6 BOR1159 9.5 L6535

-25.4 25.5 -21.2 21.2 -9.5 -9.5 7.3 2.11.6 -2.1 -39.9 40.2

-0.9 L6514 -0.2 -5.5 L6551 4.9 -5.2 4.8 3.4 -5.0 4.5 33.3 -33.3 36 Mvar 1.039 1.027 143.4 141.8 1.036 1.039 143.0 143.3 199152 190408 22N-CHURCHST BOR1160 190258 190498 1.033 -196.0 L6513 0.9 L6536 22.7 4.4 -0.9 -15.0 -15.0 15.0 MURRCRNORTON 356.3

-2.0 -3.7 2.2 -5.9 -5.3 3.8 1.037 190341 1.033 199135 143.1 HARDRD

3.7 62.2 -61.4 59.0 -58.9 15.9 199134 -2.0 142.6 74N-SPRNGHIL 199125 8.4 81N-DEBERT 67N-ONSLOW -10.9 -11.2 12.0 -12.5 12.7 165.7 2.3 0.6 199195 0.6 1.039 1.040 103H-LAKSIDE 1.033 143.4 143.5 1.3 -196.5 -4.0 -4.4 L8002 197.7 142.5 190320 -8.9 -35.8 190402 SALBRY MEM345 1.024 353.4 0.0 + 37.5 MVar 190381 -116.5 39.6 BR3025 0.0 -165.2 -91.9 -94.2 L8001 94.6 190417 39.6 -20.4 0.93125 1.041 BATHURST -5.5 -53.6 -211.2 199130 143.6 211.8 -213.8 216.6 67N-ONSLOW -50.3 199045 35.5 8.8 -79.5 101S-WOODBIN 0.0 1.013 199120 0.0 199042 349.4 79N-HOPWELL -16.1 101S-WOODBIN 1.028 26.20.0 71.2 1.020 199043354.7 1 -244.9 245.6 -243.2 351.9 245.8 -113.5 102S-ACONI 26.20.0 11.3 199200 18.8 L8003 -37.0 -36.1 L8004 -37.2 70.5 L7015 120H-BRUSHY 0.0 -75.5 75.7 90.0 26.2 1.01 L7001 70.2 199855 0.0 -6.4 199001 26.2 1 -0.5 9.9R -97.9 98.8 NS_DC_POLE1 88S-LINGAN_1 11.2 -16.1 237.5 -115.7 80.0 8.4 -15.7 199121 79N-HOPWELL-1.2 -2.4 14.2 -36.6R 1 -8.1 33.5R 1.026 199593 7.3

4.5 0.98 73.0 1.011 -95.8 L7002 96.8 0.0 91N-DALHOGEN 354.0 199050 121.4 199857 49.5 3C-HASTINGS NS_DC_POLE2 0.990 8.1 8.0 -15.7 31.1 -1.2 0.0 237.5 16.0 L7014 19.8 -16.0 1.024 199590 3.1R 4.1 353.3 91N-DALHOUS 4.5 31.1 1.028 -36.6R 2 * 50 Mvar -7.3 0.2 0.6 1.011 -138.6 L7018 139.5 -101.4 L7019 2 * 30 Mvar 101.9 -54.5 L7004 55.1 -124.4 126.5 15.3 L7021 -15.3 121.4 1.035 0.990 357.1 14.3 6.0 -16.0 1.2 -4.0 -5.3 -16.5 13.8 L7011 -19.1 -7.8 0.7

1.028 L7003 L7012 L7022 -62.8 236.4 64.0 -129.4 131.0 16.0 -16.0 199202 9.4 -14.4 -7.3 0.2 120H-BRSHSVC -5.1 -19.1 199002 199010 88S-LINGAN_2 0.0 -66.7 L7005 67.4 199110 199015 199016 2S-VJ 1.034 1N-ONSLOW 15S-WATRFORD-5.2 5.2 109S-LINWIND 237.7 0.0R -11.4 -13.1 199051 -37.3 -1.3 1.3 1.1 -1.1 2C-HASTINGS 199019 4.0 1 1.2 1.2 1.027 199100 70.8 81S-RESERVE 23.1 14.0 -14.0 -14.0 8.8 -8.8 -0.4 0.1 1.021 49N-MICHGRAN -2.3 -6.0 -6.0 1 1 234.9 1.023 199076 -1.0R 2.2 3.5 -4.8 4.7 0.990 199154 235.2 4C-LOCHABER 33.6 0.7 -0.7 0.7 -0.7 1.8 199090 199610 199075 1.000 14.3 82V-ELMSDALE 50N-TRENTON 93N-GLENDHU 100C-PORCUPN 12.71 199423 0.4 -0.5 0.3 0.1 -0.1 0.0 19.9 8.9 109S-LINWIND 1.027 -77.8 L6001 79.4 L6503 69.7 -39.2 L651139.5 18.3 L6552 -18.3 9.1 L6515 -9.0 2.7 L6515 -49.3 49.7 -2.7 70.9 33.6 26.1 7.3 -3.0 16.8 -17.0 -7.9 5.1-6.2 -4.7 3.5 -9.5 6.5 -11.3 11.0 199007 1.029 2S-VICTORIA 1.017 12.71 199063 199056 71.0 199003

0.99 15.9 140.4 0.0 199091 22C-CLEVLAND 59C-STPETERS 88S-LINGAN_3 50N-TRENTON -57.8 16.2 -7.0 6.3 50 Mvar-53.3 0.995 26.5 10.9 2.2 3.8 4.8 21.3 199006 16.1 0.99 88S-LINGAN_B 1.032 10.9 L6516 L6533 237.3 1.025 1.019 1.019 1.025 1.029

-17.9 7.9 2.5 2.1 0.6 28.4 -58.7 58.9 58.9 140.6 140.6 141.5 71.0 199053 2.8 -6.5 -10.4 10.7 12.1 10.2 20.7 90.0 47C-NEW_PAGE 0.99 -52.1 L6518 52.3 1.026 1.029 1.039 199611 199057 141.6 142.0 143.4 0.990

3.2 1.04 1.04 10.6 19.1R 93N-GLENDHUM -10.9 10.9 67C-WHYC_TAP 199005 -5.8 5.7 199033 199031 199025 14.3 199072 104S-BADDECK 5S-GLEN_TOSH 3S-GANNON_RD 88S-LINGAN_A 1.043 -2.3 1.4 L6534 199112 71.9 1.016 48C-BIOMASS 199004 L6517 -18.3 L6537 18.4 -21.1 21.1 -23.3 L6538 23.4 L6539 37.6 -59.8 60.1 60.1 1N-ONSLOW_B 199111 140.2 199118 0.980 88S-LINGAN_4 4N-TATAMAG 45.0 -44.9 -44.9 41.3 -7.4 7.5 199114 1N-ONSLOW_A 199580 33.82.6 -48.2 -58.0 1 15N-WILLOWLN -0.0 -1.4 0.4 -1.2 6.3 -8.1 -5.4 -9.6 9.8 0.99 11.3 89N_NUTBTP 2.4 4.7 -4.7 4.7 5.2R -1.7 -2.7 6.3 -2.2 -1.4 1.040 1.030 1.033 143.5 23.4 -30.4 44.2 199612 142.5

0.99375 14.2 1.0 -1.4 1.4 93N-GLENDHUG 2.7 13.9 199584 199026

1.027 1.026 1.029 0.99 -1.4 16.7 -9.2 89N_NUTBG 199581 70.8 141.6 142.0 3S-GANNON_RD

1.020 1.0113

2.7 0.9 4.1 70.4 89N_NUTBHV 59.7 1.034 -48.9 48.9 50.0 L6523 1.029 1.032 1.010 71.0 237.9 0.961 6.9 142.5 1 34.8-2.7 13.8

8.2 -8.0 2.3R -59.7 199613 1.022 3.5 1.0330.992 1.031 1.030 199035 93N-GLENDHU 70.5 71.3 0.4 142.2 142.1 85S-WRK_COVE 1.032 L6545 199037 4.8 -5.3 5.3 71.2 1.1 -1.1 85S-WRECK_2 199052 -0.3 -2.5 -6.6

0.5 -0.8 48.2 -2.6 -0.7 -41.2

0.5 1C-TUPPER -0.2

1.022 60.0 1.022

1.020 5.8R 199115 70.4 70.5 141.0 1.1 L6549 -1.1

11N-LAFARGE 1.0 0.0 7.1 -14.0

6.0 2.0 -2.6 -0.7 1 199036 2.2 85S-WRECK_1 -0.5 0.5 0.0 1.032 1.3 142.4 0.0 199690 1.033 1C-TUPPER0.992 142.5 1.020 24.8 199116 70.4 16N-STEWIAKE 2.7

199054 6.1 1.8 -21.4 47C-NEW_PAGE 1.022 199692 120C-BEARHD 1.000 141.0 Bus - Voltage (kV/pu) 13.8 199691

-22.0-0.6 22.0

22.0 120C-BEARHD Branch - MW/Mvar 1.025 0.6 1.0R Equipment - MW/Mvar 0.990 100.0%Rate A 0.4 1.050OV 0.970UV kV: <=35.000 <=69.000 <=138.000 <=230.000 <=345.000 >345.000 2021 SUMMER PEAK: 2021SUM-2 - FULL WIND ON BACKBONE Total Wind Gen: 303.7 MW Gross Tupper 0.0 MW Gross Wreck Cove 0.0 MW Net NewPage Load 100.3 MW Summer Ratings DERIVED FROM UPDATE OF 2014 SERIES MMWG 2020 SUMMER PEAK Gross Lingan 80.0 MW Gross Trenton 90.0 MW Gross Gas Turbine 0.0 MW Gross NewPage Load 145.3 MW Figure ___D-6 SAT, SEP 30 2017 20:33 Gross Pt Aconi 90.0 MW Gross Tuft's Cove 88.0 MW Gross Small Hydro 74.3 MW Total BMPC Load -0.5 MW Includes 70% Distributed Generation Total Gross Gen: 726.0 MW ML HVDC: 475.0 MW Gross Gen + ML: 1201.0 MW modeled as Negative Load: -143.0 MW 1 2018 10 Year System Outlook Report Appendix B Page 66 of 84

EEXS: 118.3 MW NB to NE: 806.4 MW EEXEB: 156.0 MW NB to QC: -300.1 MW ML HVDC: -100.0 MW NSX -100.3 MW MAINLAND AT HASTINGS: 100.5 MW CBX 212.8 MW HASTINGS FROM 88S,5S,2S: 221.6 MW ONI 528.8 MW 1.033 199137 199555 71.3 3N-OXFORD FORCE_HV L-7011:87.3 MW ONS 616.4 MW 199138 199147 1.009 5.0 199557 2.9 1 7N-PUGWASH 37N-PARSBORO 0.7 -1.0L IR516_G L-7012: 90.6 MW NB to PEI: 159.1 MW 0.2 4.6 -4.6 1.9 10.2 -14.414.5 1.013 4.0 199558 Nova Scotia New Brunswick L-7011 + L-7012: 177.9 MW 1 0.4 IR517 4.8 10.4 -10.4 0.1 -0.5 0.1 -3.7 3.5 -3.5 -1.0L 190401 1.030 1.028 1.023 5.6 199559 MEM138 2.0 1.6 -1.8 1 71.1 70.9 0.7 0.0H IR542_G 190075 190150 190197 SACK138 MEM69 1.027 199530 C.COVE 199139 70.9 92N-AMHSTWIN 199531 199533 10N-ABER_ST 92N-AMHSTLV 92N-AMHSTGEN 7.3 -24.2 -41.8 42.2

199146 199145 1 1.047 4.8 -4.8 20.1 1 30N-MACCAN 30N-MACCAN 144.5 -4.3 -30.7 1.025 -30.9 31.0 1.8 -5.9 37.9 -37.8 1.025 -10.2 -1.8 1.037 -7.3 1.033 2.3 -2.3 6.6 1 1.030 353.5 -51.9 71.5 3.5 71.1 142.5 198.1 5.7 1.5 4.5 -3.0R 199136 1.038 0.99 1.032 1.022 1.020 190379 74N-SPRINGHL 71.6 71.2 35.3 0.6 BOR1159 11.2 L6535

-23.7 23.7 -19.5 19.5 -11.2 -11.27.3 3.81.5 -3.8 -38.9 39.2

-2.4 L6514 1.2 -6.9 L6551 6.2 -7.7 7.3 5.9 -7.5 7.0 37.4 -37.3 36 Mvar 1.045 1.033 144.3 142.5 1.042 1.045 143.8 144.2 199152 190408 22N-CHURCHST BOR1160 190258 190498 1.029 -197.0 L6513 3.0 L6536 13.2 0.6 -3.0 -12.9 -12.9 12.9 MURRCRNORTON 355.0

2.0 -6.2 4.7 -8.4 -7.8 6.2 1.043 190341 1.038 199135 144.0 HARDRD

3.7 62.1 -61.4 59.0 -58.9 15.9 199134 -6.0 143.3 74N-SPRNGHIL 199125 81N-DEBERT 8.4 67N-ONSLOW -5.9 -10.9 11.6 -12.2 12.3 166.4 2.3 0.6 199195 0.6 1.046 1.047 103H-LAKSIDE 1.034 144.4 144.5 5.4 -196.4 -7.8 -0.6 L8002 197.6 142.6 190320 -8.7 -36.0 190402 SALBRY MEM345 1.025 353.6 0.0 + 37.5 MVar 190381 -115.4 39.3 BR3025 0.0 -165.8 -108.7 -98.6 L8001 99.0 190417

0.9125 39.3 -24.9 1.049 BATHURST 9.7 -67.7 -214.6 199130 144.7 215.1 -214.1 216.9 67N-ONSLOW -54.5 199045 40.2 3.7 -73.8 101S-WOODBIN 0.0 1.012 199120 199042 349.0 79N-HOPWELL 101S-WOODBIN 1.023 26.20.0 75.2 1.015 199043353.0 1 -248.2 248.9 -111.8 350.1 112.4 106.2 102S-ACONI 26.20.0 7.7 199200 11.1 L8003 -29.1 -57.9 L8004 -46.4 69.3 L7015 120H-BRUSHY 0.0 -169.3 170.5 185.0 L7001 26.2 74.1 199855 1.01 9.9 199001 26.2 1 -7.5 15.2R -97.3 98.2 NS_DC_POLE1 88S-LINGAN_1 7.6 -50.0 106.2 80.0 7.7 -15.2 199121 79N-HOPWELL-68.6 -137.1 14.2 -49.1R 1 -9.3 27.4R 1.026 199593 7.3

7.9 0.98 87.0 1.011 -95.3 L7002 96.2 0.0 91N-DALHOGEN 354.1 199050 121.4 199857 49.5 3C-HASTINGS NS_DC_POLE2 0.990 8.1 7.3 -15.2 31.0 -68.6 0.0 -50.0 -74.4 L7014 19.8 74.6 1.026 199590 2.8R 4.1 353.9 91N-DALHOUS 7.9 31.0 1.028 -49.1R 2 * 50 Mvar -12.2 6.7 0.6 1.011 -137.8 L7018 138.7 -86.8 L7019 2 * 30 Mvar 87.2 -39.8 L7004 40.1 -86.3 87.3 -72.2 L7021 72.5 121.4 1.035 0.990 357.1 14.3 5.0 -15.2 -3.2 -0.4 -9.3 -14.2 7.0 L7011 -19.7 -9.1 3.6

1.029 L7003 L7012 L7022 -48.3 236.8 49.0 -89.8 90.6 -74.4 74.5 199202 3.9 -16.6 -12.2 6.7 120H-BRSHSVC -10.2 -16.6 199002 199010 88S-LINGAN_2 0.0 -51.1 L7005 51.5 199110 199015 199016 2S-VJ 1.034 1N-ONSLOW 15S-WATRFORD-5.2 5.2 109S-LINWIND 237.8 -0.0R -15.2 -11.9 199051 -2.3 -1.3 1.3 1.1 -1.1 2C-HASTINGS 199019 7.8 1 69.0 69.0 1.031 199100 71.1 81S-RESERVE 18.8 14.0 -14.0 -14.0 8.8 -8.8 -0.4 0.1 1.022 49N-MICHGRAN -6.3 -7.1 -7.1 1 1 235.1 1.024 199076 -1.3R 2.6 3.8 -5.1 5.0 0.990 199154 235.6 4C-LOCHABER 17.8 0.7 -0.7 0.7 -0.7 1.8 199090 199610 199075 1.000 14.3 82V-ELMSDALE 50N-TRENTON 93N-GLENDHU 100C-PORCUPN 15.91 199423 0.4 -0.5 0.3 0.1 -0.1 0.0 19.9 8.9 109S-LINWIND 1.032 -83.7 L6001 85.7 L6503 115.8 -1.2 L65111.2 56.6 L6552 -56.2 47.0 L6515 -46.4 40.1 L6515 -94.4 95.7 -40.1 71.2 17.8 26.1 9.1 -3.5 24.6 -15.7 -5.4 -1.9-0.7 -10.6 10.8 -16.9 16.3 -21.1 21.0 199007 1.034 2S-VICTORIA 1.017 15.91 199063 199056 71.3 199003

0.99 16.0 140.3 0.0 199091 22C-CLEVLAND 59C-STPETERS 88S-LINGAN_3 50N-TRENTON -57.8 16.2 -7.0 6.3 160.0 50 Mvar-53.3 0.995 26.5 11.3 2.2 3.8 4.8 32.5R 21.3 150.0 199006 16.2 0.99 88S-LINGAN_B 1.034 10.8 14.7R L6516 L6533 237.9 8.2 1.025 1.020 1.019 1.026 1.034 -14.7 7.9 2.5 2.1 0.6 71.3 25.0 -55.8 56.0 56.0 140.8 140.7 141.6 4.2 199053 0.7 -5.0 -11.8 11.9 13.3 10.2 20.7 160.0 47C-NEW_PAGE 0.99 -52.1 L6518 52.3 1.028 1.031 1.044 199611 199057 141.9 142.3 144.1 0.990

3.2 1.04 1.04 10.6 19.6R 93N-GLENDHUM -10.9 10.9 67C-WHYC_TAP 199005 -6.2 6.1 199033 199031 199025 14.3 199072 104S-BADDECK 5S-GLEN_TOSH 3S-GANNON_RD 88S-LINGAN_A 1.046 -2.3 1.4 L6534 199112 72.2 1.019 48C-BIOMASS 199004 L6517 -15.9 L6537 15.9 -18.6 18.6 -20.8 L6538 20.9 L6539 35.1 -56.9 57.1 57.1 1N-ONSLOW_B 199111 140.7 199118 0.981 88S-LINGAN_4 4N-TATAMAG 45.0 -44.9 -44.9 41.3 -5.0 5.0 120.0 199114 1N-ONSLOW_A 199580 33.82.9 -48.2 -58.0 1 15N-WILLOWLN -1.5 0.0 -1.0 0.2 5.0 -6.9 -4.4 -11.1 11.1 0.99 12.5 89N_NUTBTP 2.2 4.7 -4.7 4.7 4.6R -1.0 -2.1 6.6 -3.8 0.1 1.045 29.6R 1.030 1.037 144.1 23.4 -30.4 44.2 199612 143.2

0.9875 14.2 1.0 -1.4 1.4 93N-GLENDHUG 2.7 13.9 8.0 199584 199026

1.030 1.027 1.031 0.99 -1.4 17.8 -10.2 89N_NUTBG

1.005 3S-GANNON_RD 1.026 199581 71.1 141.8 142.3

2.3 0.9 4.1 4.1 70.8 89N_NUTBHV 59.7 1.040 -48.9 48.9 50.0 L6523 1.033 1.032 1.010 71.3 239.1 0.990 6.9 142.5 1 34.8-2.3 14.3

9.2 -9.1 1.3R -59.7 199613 1.028 3.5 1.0360.991 1.034 1.034 199035 93N-GLENDHU 70.9 71.5 0.4 142.7 142.7 85S-WRK_COVE 1.036 L6545 199037 4.8 -5.3 5.3 71.5 1.1 -1.1 85S-WRECK_2 199052 -0.3 -2.2 -7.0

0.5 -0.8 48.2 -2.6 -0.7 -41.2

0.5 1C-TUPPER -0.2

1.028 60.0 1.023

1.025 5.4R 199115 70.7 70.9 141.2 1.1 L6549 -1.1

11N-LAFARGE 1.0 0.0 7.2 -14.0

6.0 2.0 -2.6 -0.7 1 199036 2.2 85S-WRECK_1 -0.5 0.5 0.0 1.035 1.3 142.9 0.0 199690 1.036 1C-TUPPER0.992 143.0 1.025 24.8 199116 70.7 16N-STEWIAKE 2.7

199054 6.1 1.9 -21.4 47C-NEW_PAGE 1.023 199692 120C-BEARHD 1.000 141.1 Bus - Voltage (kV/pu) 13.8 199691

-22.0-0.7 22.0

22.0 120C-BEARHD Branch - MW/Mvar 1.025 0.7 0.9R Equipment - MW/Mvar 0.990 100.0%Rate A 0.4 1.050OV 0.970UV kV: <=35.000 <=69.000 <=138.000 <=230.000 <=345.000 >345.000 2021 SUMMER PEAK: 2021SUM-3 - FULL WIND ON BACKBONE Total Wind Gen: 303.7 MW Gross Tupper 0.0 MW Gross Wreck Cove 0.0 MW Net NewPage Load 100.3 MW Summer Ratings DERIVED FROM UPDATE OF 2014 SERIES MMWG 2020 SUMMER PEAK Gross Lingan 360.0 MW Gross Trenton 310.0 MW Gross Gas Turbine 0.0 MW Gross NewPage Load 145.3 MW Figure ___D-7 SAT, SEP 30 2017 20:55 Gross Pt Aconi 185.0 MW Gross Tuft's Cove 84.0 MW Gross Small Hydro 74.3 MW Total BMPC Load -0.5 MW Includes 70% Distributed Generation Total Gross Gen: 1317.0 MW ML HVDC: -100.0 MW Gross Gen + ML: 1217.0 MW modeled as Negative Load: -143.0 MW 1 2018 10 Year System Outlook Report Appendix B Page 67 of 84

EEXS: 41.5 MW NB to NE: 806.2 MW EEXEB: 55.9 MW NB to QC: -300.1 MW ML HVDC: -100.0 MW NSX -100.6 MW MAINLAND AT HASTINGS: -3.2 MW CBX 31.9 MW HASTINGS FROM 88S,5S,2S: 116.4 MW ONI 203.2 MW 1.029 199137 199555 71.0 3N-OXFORD FORCE_HV L-7011:46.8 MW ONS 291.1 MW 199138 199147 1.005 5.0 199557 2.9 1 7N-PUGWASH 37N-PARSBORO 0.7 -1.0L IR516_G L-7012: 48.8 MW NB to PEI: 159.2 MW 0.2 4.6 -4.6 1.9 10.2 -14.414.5 1.009 4.0 199558 Nova Scotia New Brunswick L-7011 + L-7012: 95.6 MW 1 0.4 IR517 4.8 10.4 -10.4 0.1 -0.5 0.1 -3.7 3.5 -3.5 -1.0L 190401 1.026 1.024 1.019 5.6 199559 MEM138 2.0 1.7 -1.8 1 70.8 70.7 0.7 0.0H IR542_G 190075 190150 190197 SACK138 MEM69 1.024 199530 C.COVE 199139 70.6 92N-AMHSTWIN 199531 199533 10N-ABER_ST 92N-AMHSTLV 92N-AMHSTGEN 7.3 -24.2 -42.0 42.4

199146 199145 1 1.044 4.8 -4.8 20.1 1 30N-MACCAN 30N-MACCAN 144.1 -4.3 -30.7 1.025 -30.9 31.0 1.8 -5.9 33.4 -33.5 1.025 -10.2 -1.8 1.033 -7.3 1.032 2.3 -2.3 6.6 1 1.027 353.7 -56.1 71.3 3.5 70.9 142.4 198.2 5.7 0.9 3.9 -2.4R 199136 1.034 0.99 1.029 1.021 1.020 190379 74N-SPRINGHL 71.3 71.0 35.2 0.6 BOR1159 12.2 L6535

-22.7 22.7 -18.5 18.5 -12.2 -12.27.3 4.81.6 -4.8 -39.1 39.4

-3.3 L6514 2.1 -7.8 L6551 7.2 -8.0 7.7 6.3 -7.8 7.4 32.9 -33.0 36 Mvar 1.042 1.032 143.8 142.4 1.038 1.041 143.3 143.7 199152 190408 22N-CHURCHST BOR1160 190258 190498 1.031 -197.1 L6513 4.2 L6536 17.3 -1.6 -4.2 -11.7 -11.7 11.7 MURRCRNORTON 355.6

3.7 -6.9 5.5 -9.2 -8.5 7.0 1.040 190341 1.035 199135 143.5 HARDRD

3.7 62.2 -61.4 59.0 -58.9 15.9 199134 -7.6 142.8 74N-SPRNGHIL 199125 8.4 81N-DEBERT 67N-ONSLOW -11.2 -10.9 11.7 -12.2 12.4 166.4 2.3 0.6 199195 0.6 1.043 1.044 103H-LAKSIDE 1.028 144.0 144.1 -93.5 7.0 L8002 93.7 -10.0141.9 1.6 190320 -9.4 -46.2 190402 SALBRY MEM345 1.038 358.2 0.0 + 37.5 MVar 190381 -112.7 39.5 BR3025 0.0 -165.8 -98.1 -101.1 L8001 101.6

0.925 190417 39.5 -19.8 1.046 BATHURST 17.8 -76.3 -214.4 199130 144.3 215.0 -214.2 217.1 67N-ONSLOW -33.8 199045 19.1 6.8 -77.3 101S-WOODBIN 0.0 1.012 199120 199042 349.3 79N-HOPWELL 101S-WOODBIN 1.026 26.60.0 48.4 1.020 199043354.1 1 -88.7 88.8 -35.0 352.0 35.1 67.7 102S-ACONI 26.60.0 12.4 199200 3.8 L8003 -31.4 -56.4 L8004 -56.0 62.0 L7015 120H-BRUSHY 0.0 -169.3 170.5 185.0 L7001 26.6 47.7 199855 1.01 8.9 199001 26.6 1 -6.6 16.2R -48.4 48.6 NS_DC_POLE1 88S-LINGAN_1 12.2 -50.0 67.4 160.0 3.7 -16.1 199121 79N-HOPWELL-26.9 -53.8 14.2 -47.6R 1 -16.5 38.9R 1.035 199593 7.3

10.7 0.98 87.8 1.012 -47.4 L7002 47.6 0.0 91N-DALHOGEN 357.2 199050 121.4 199857 49.5 3C-HASTINGS NS_DC_POLE2 0.990 8.1 3.3 -16.1 31.4 -26.9 0.0 -50.0 -20.7 L7014 19.8 20.7 1.033 199590 1.3R 4.1 356.5 91N-DALHOUS 10.7 31.4 1.027 -47.6R 2 * 50 Mvar -4.8 -2.3 0.6 1.012 -68.7 L7018 68.9 -50.5 L7019 2 * 30 Mvar 50.6 -3.1 L7004 3.2 -46.5 46.8 -20.0 L7021 20.0 121.4 1.035 0.990 357.1 14.3 2.4 -19.6 -7.8 2.9 -14.1 -11.6 3.6 L7011 -21.1 -3.9 -3.0

1.036 L7003 L7012 L7022 -11.9 238.2 12.0 -48.5 48.8 -20.7 20.7 199202 2.0 -19.7 -4.8 -2.3 120H-BRSHSVC -16.9 -13.3 199002 199010 88S-LINGAN_2 0.0 -12.3 L7005 12.3 199110 199015 199016 2S-VJ 1.033 1N-ONSLOW 15S-WATRFORD-5.2 5.2 109S-LINWIND 237.6 -0.0R -18.5 -12.3 199051 -5.7 -1.3 1.3 1.1 -1.1 2C-HASTINGS 199019 10.0 1 27.0 27.0 1.027 199100 70.9 81S-RESERVE -11.8 14.0 -14.0 -14.0 8.8 -8.8 -0.4 0.1 1.033 49N-MICHGRAN -7.9 -11.8 -11.8 1 1 237.7 1.032 199076 -1.0R 2.3 3.5 -4.8 4.7 0.990 199154 237.3 4C-LOCHABER 33.8 0.7 -0.7 0.7 -0.7 1.8 199090 199610 199075 1.000 14.3 82V-ELMSDALE 50N-TRENTON 93N-GLENDHU 100C-PORCUPN 15.81 199423 0.4 -0.5 0.3 0.1 -0.1 0.0 19.9 8.9 109S-LINWIND 1.028 -32.0 L6001 32.3 L6503 60.0 -11.0 L651111.0 46.8 L6552 -46.5 37.3 L6515 -36.9 30.6 L6515 -39.8 40.0 -30.6 70.9 33.8 26.1 5.4 -7.6 8.7 -10.3 -1.3 -1.0-1.5 -10.3 10.0 -16.2 14.7 -19.5 19.4 199007 1.030 2S-VICTORIA 1.026 15.81 199063 199056 71.1 199003

0.99 15.9 141.6 199091 22C-CLEVLAND 59C-STPETERS 88S-LINGAN_3 50N-TRENTON -57.8 16.2 -7.0 6.3 50 Mvar 0.995 26.5 11.7 2.2 4.0 4.8 21.3 199006 16.1 0.99 88S-LINGAN_B 1.038 10.8 L6516 L6533 238.7 1.025 1.022 1.022 1.030 1.030

-1.8 7.9 2.5 2.1 0.6 11.9 -44.4 44.5 44.5 141.0 141.0 142.1 71.1 199053 -0.2 -5.4 -11.1 10.9 11.7 10.2 20.7 160.0 47C-NEW_PAGE 0.99 -52.1 L6518 52.3 1.031 1.033 1.039 199611 199057 142.3 142.5 143.4 0.990

3.2 1.04 1.04 10.6 18.7R 93N-GLENDHUM -10.9 10.9 67C-WHYC_TAP 199005 -7.3 7.2 199033 199031 199025 14.3 199072 104S-BADDECK 5S-GLEN_TOSH 3S-GANNON_RD 88S-LINGAN_A 1.047 -2.3 1.4 L6534 199112 72.2 1.020 48C-BIOMASS 199004 L6517 -6.2 L6537 6.2 -8.9 8.9 -11.1 L6538 11.1 L6539 25.1 -45.3 45.4 45.4 1N-ONSLOW_B 199111 140.7 199118 0.982 88S-LINGAN_4 4N-TATAMAG 45.0 -44.9 -44.9 41.3 4.7 -4.7 199114 1N-ONSLOW_A 199580 33.93.4 -48.2 -58.0 1 15N-WILLOWLN -1.9 0.3 -1.2 0.3 4.8 -7.0 -4.9 -10.6 10.2 0.99 11.1 89N_NUTBTP 1.6 4.7 -4.7 4.7 2.7R 0.8 -0.3 7.6 -4.2 0.5 1.040 1.030 1.033 143.5 23.4 -30.4 44.2 199612 142.6

0.9875 14.2 1.0 -1.4 1.4 93N-GLENDHUG 2.7 13.9 199584 199026

1.027 1.031 1.033 0.99 -1.4 16.8 -9.3 89N_NUTBG

1.005 3S-GANNON_RD 1.020 199581 70.9 142.3 142.5

1.9 0.9 4.1 70.4 89N_NUTBHV 59.7 1.034 -48.9 48.9 50.0 L6523 1.031 1.026 1.010 71.1 237.8 0.990 6.9 141.7 1 34.8-1.9 14.3

8.3 -8.1 2.2R -59.7 199613 1.022 3.5 1.0330.992 1.034 1.032 199035 93N-GLENDHU 70.5 71.3 0.4 142.7 142.4 85S-WRK_COVE 1.033 L6545 199037 4.8 -5.3 5.3 71.3 1.1 -1.1 85S-WRECK_2 199052 -0.3 -1.6 -7.9

0.5 -0.8 48.2 -2.6 -0.7 -41.2

0.5 1C-TUPPER -0.2

1.023 60.0 1.026

1.020 5.0R 199115 70.4 70.6 141.6 1.1 L6549 -1.1

11N-LAFARGE 1.0 0.0 7.5 -14.0

6.0 2.0 -2.6 -0.7 1 199036 2.2 85S-WRECK_1 -0.5 0.5 0.0 1.035 1.3 142.8 0.0 199690 1.036 1C-TUPPER0.994 142.9 1.020 24.9 199116 70.4 16N-STEWIAKE 2.7

199054 6.1 2.2 -21.4 47C-NEW_PAGE 1.026 199692 120C-BEARHD 1.000 141.6 Bus - Voltage (kV/pu) 13.8 199691

-22.0-1.0 22.0

22.0 120C-BEARHD Branch - MW/Mvar 1.025 1.0 0.5R Equipment - MW/Mvar 0.990 100.0%Rate A 0.4 1.050OV 0.970UV kV: <=35.000 <=69.000 <=138.000 <=230.000 <=345.000 >345.000 2021 SUMMER PEAK: 2021SUM-3A - FULL WIND ON BACKBONE Total Wind Gen: 303.7 MW Gross Tupper 0.0 MW Gross Wreck Cove 0.0 MW Net NewPage Load 100.3 MW Summer Ratings DERIVED FROM UPDATE OF 2014 SERIES MMWG 2020 SUMMER PEAK Gross Lingan 160.0 MW Gross Trenton 160.0 MW Gross Gas Turbine 0.0 MW Gross NewPage Load 145.3 MW Figure ___D-8 SAT, SEP 30 2017 21:39 Gross Pt Aconi 185.0 MW Gross Tuft's Cove 411.0 MW Gross Small Hydro 74.3 MW Total BMPC Load -0.5 MW Includes 70% Distributed Generation Total Gross Gen: 1294.0 MW ML HVDC: -100.0 MW Gross Gen + ML: 1194.0 MW modeled as Negative Load: -143.0 MW 1 2018 10 Year System Outlook Report Appendix B Page 68 of 84

EEXS: 168.0 MW NB to NE: 3.0 MW EEXEB: 452.6 MW NB to QC: -300.0 MW ML HVDC: 330.0 MW NSX -0.0 MW MAINLAND AT HASTINGS: 371.2 MW CBX 709.0 MW HASTINGS FROM 88S,5S,2S: 433.8 MW ONI 979.1 MW 1.036 199137 199555 71.5 3N-OXFORD FORCE_HV L-7011:156.7 MW ONS 893.6 MW 199138 199147 5.0 199557 3.0 1.012 1 7N-PUGWASH 37N-PARSBORO 0.7 -1.0L IR516_G L-7012: 162.3 MW NB to PEI: 196.7 MW 0.9 5.1 -5.1 2.0 7.3 -14.414.5 1.015 4.0 199558 Nova Scotia New Brunswick L-7011 + L-7012: 319.0 MW 1 0.4 IR517 8.0 10.9 -10.9 0.8 -1.2 0.5 -5.8 3.5 -3.5 -1.0L 190401 1.031 1.030 1.026 5.6 199559 MEM138 2.3 3.0 -3.1 1 190197 71.1 71.1 0.7 0.0H IR542_G 190075 190150 SACK138 MEM69 1.030 199530 C.COVE 199139 71.1 92N-AMHSTWIN 199531 199533 16.9 -56.8 -54.0 54.4 10N-ABER_ST 199145 92N-AMHSTLV 92N-AMHSTGEN 199146 1 1.021 6.0 -6.0 25.0 0.95 30N-MACCAN 30N-MACCAN 141.0 2.5 -30.7 1.025 -30.8 31.0 3.1 -13.0 15.6 -15.4 1.021 1.041 -7.3 -3.1 1.020 2.2 -2.3 8.6 -16.9 1.030 352.1 71.8 140.8 -21.6 71.1 519.7 5.4 9.2 2.0 4.7 -3.1R

199136 1.042 0.975 1.043 1.002 1.000 190379

74N-SPRINGHL 71.9 72.0 0.96875 34.6 0.6 BOR1159 -11.4 11.4 -13.9 13.9 16.8 L6535 -16.8 -16.7 -0.2 0.2 -47.9 48.2 0.0 2.8 17.0

-38.2 10.4 L6514 -11.7 2.5 L6551 -3.2 1.2 -1.5 -2.8 -0.0 -0.4 15.7 -15.8 36 Mvar 1.025 1.019 141.5 140.6 1.026 1.026 141.6 141.6 199152 190408 22N-CHURCHST BOR1160 190258 190498 1.017 -511.9

13.8 53.9 L6513 -27.4 L6536 -13.7 -5.8 -5.8 5.8 MURRCRNORTON 350.9

11.7 7.5 -8.9 3.1 3.8 -5.3 1.024 190341 1.030 199135 141.3 HARDRD 73.8 -72.6 67.2 -66.9 5.7

142.1 74N-SPRNGHIL 19.5 199134 -14.6 199125 26.5 81N-DEBERT 67N-ONSLOW -65.8 -23.1 26.0 -27.0 27.5 390.9 199195 9.0 5.4 1.0 1.030 1.034 103H-LAKSIDE 1.018 142.1 142.8 5.6 L8002 -282.4 140.5 284.8 -54.0 27.5 190320 -11.9 -18.9 190402 SALBRY 1.018 MEM345 351.2

+ 37.5 MVar 190381 -193.9 0.0 BR3025 -387.6 17.4 -38.3 -11.0 L8001 11.0 190417

1.0063 64.0 1.022 BATHURST -29.3 -33.7 -205.1 199130 141.0 205.6 -149.8 151.1 67N-ONSLOW 29.8 199045 -45.0 -31.1 -56.1 101S-WOODBIN 1.025 199120 0.0 199042 353.5 79N-HOPWELL -16.1 101S-WOODBIN 1.023 87.9 1.026 199043353.1 1 -448.4 450.7 -332.9 353.8 337.8 3.9 102S-ACONI 1.4 199200 45.4 L8003 -39.5 -13.2 L8004 -25.3 18.8 L7015 120H-BRUSHY -169.3 170.5 185.0 L7001 86.7 199855 0.0 1.01 -7.9 33.1R 199001 -145.6 147.7 1 NS_DC_POLE1 10.4 -16.1 88S-LINGAN_1 1.4 160.0 199121 165.0 3.9 17.4 -17.0 -59.0 -117.8 14.2 79N-HOPWELL -34.2R 18.8 46.2R 1.026 199593 23.5 52.7 1.016 1.01 7.3 -142.6 L7002 144.7 0.98 353.9 91N-DALHOGEN 199050 199857 121.9 8.1 49.5 3C-HASTINGS NS_DC_POLE2 1.000 16.8 -17.0 -58.9 165.0 -53.2 L7014 20.0 53.3 1.024 199590 3.2R 4.1 353.2 91N-DALHOUS 23.5 1.028 -34.2R 2 * 50 Mvar 0.7 -6.9 0.6 1.016 -206.3 L7018 208.4 -156.3 L7019 2 * 30 Mvar 157.6 -110.2 L7004 112.7 L7021 -153.5 121.9 1.035 156.7 -51.2 51.4 0.990 357.1 14.3 15.7 -14.8 25.0 -24.0 14.7 -24.7 22.6 L7011 -19.8 2.6 -8.8

1.027 L7003 L7012 L7022 -117.1 236.3 121.5 -159.8 162.3 -53.1 53.2 199202 17.4 -13.9 0.7 -6.9 120H-BRSHSVC 20.1 -28.8 199002 199010 88S-LINGAN_2 0.0 -126.2 L7005 128.6 199110 199015 199016 2S-VJ 1.027 1N-ONSLOW 15S-WATRFORD-9.8 9.8 109S-LINWIND 236.3 0.0R 9.4 -17.3 199051 -73.2 -3.0 3.0 21.0 -20.8 2C-HASTINGS 199019

1.01 1.028 54.1 59.3 59.3 81S-RESERVE 9.4 199100 70.9 6.9 -6.5 49N-MICHGRAN 14.0 -14.0 -14.0 4.2 -4.2 1.022 -5.7 -23.1 -23.1 235.2 1 1 1.025 199076 -1.2R 2.5 3.7 -6.7 6.5 1.000 199154 235.8 4C-LOCHABER -24.7 15.6 -15.4 8.2 -8.2 29.0 199090 199610 199075 0.999 14.4 82V-ELMSDALE 50N-TRENTON 93N-GLENDHU 100C-PORCUPN 15.41 199423 0.4 1.9 -1.8 0.2 -0.2 6.8 11.5 5.1 109S-LINWIND 1.029 -104.8 L6001 108.0 L6503 145.7 L6511 30.0 27.7 L6552 -27.7 -0.3 L6515 0.3 -8.5 L6515 -131.2 133.9 -29.8 8.5 71.0 -24.7 62.2 21.5 -9.8 25.0 -4.2 3.3 11.3 -12.9 0.1 -1.1 -7.1 4.0 -11.0 10.8 199007 1.018 2S-VICTORIA 70.2 1.009 15.41 199063 199056 26.0 199003 139.2 0.0 199091 22C-CLEVLAND 59C-STPETERS 0.97 88S-LINGAN_3 50N-TRENTON -57.8 30.4 -2.4 8.2

50 Mvar-51.8 1.02 63.1 12.8 6.2 1.9 7.0 1.026 30.5 150.0 235.9 199006 26.3 0.97 88S-LINGAN_B 14.6 13.2R L6516 L6533 1.015 1.012 1.018 1.034 1.025 -17.3 34.5 -71.3 71.6 71.6 4.1 3.3 1.0

140.1 139.7 140.5 13.2 71.4 199053 6.5 -7.2 -24.6 25.6 28.0 18.4 29.7 160.0 47C-NEW_PAGE 0.98 -7.1 L6518 7.1 1.018 1.020 1.037 199057 140.5 140.8 143.1 0.980 4.4 14.3 18.4R -18.7 18.7 199611 67C-WHYC_TAP 199033 199031 199025 199005 14.1

1.0313 1.0313 -0.4 -0.3 93N-GLENDHUM 199072 104S-BADDECK 5S-GLEN_TOSH 3S-GANNON_RD 88S-LINGAN_A 1.034 -6.7 5.9 L6534 199112 71.3 1.020 48C-BIOMASS 199004 L6517 -74.3 L6537 75.0 -79.8 80.3 43.5 L6538 -43.2 L6539 -15.6 -72.9 73.2 73.3 1N-ONSLOW_B 199111 140.8 199118 0.973 88S-LINGAN_4 4N-TATAMAG 45.0 -44.9 -44.9 -13.4 4.4 -54.7 55.6 160.0 199114 1N-ONSLOW_A 199580 33.64.3 -57.9 1 4.6 -2.9 1.0 0.2 1.3 -2.0 3.4 -23.8 24.7 27.2 15N-WILLOWLN 0.98 89N_NUTBTP 6.1 9.7 -9.6 9.6 -1.5R 5.1 4.1 0.9 11.1 -10.5 1.037 33.8R 1.025 143.1 50.8 -26.8 39.2 1.015 14.0 141.4 0.96875 2.4 -2.6 2.6 4.8 27.5 8.0 199584 1.019 1.020 199026

1.024 0.99 11.0 17.6 -11.6 89N_NUTBG

0.975 3S-GANNON_RD 1.023 199581 70.7 199612 140.7 140.8 1.9 7.7 4.1 1.1 70.6 89N_NUTBHV 59.7 93N-GLENDHUG 1.028 -48.9 48.9 50.0 L6523 1.013 1.018 1.000 69.9 236.4 0.980 140.5 4.6 1 34.5 -1.1 14.1

9.2 -9.1 1.3R -59.7 1.031 0.8 1.0360.991 1.027 1.024 199035 71.2 71.5 0.4 141.8 141.2 85S-WRK_COVE 1.036 199613 L6545 199037 1.2 -6.5 6.5 71.5 93N-GLENDHU -62.1 63.0 85S-WRECK_2 199052 65.0 0.1

-6.2 -0.7 1.5 -1.5 1.3 -4.4 -1.7 1C-TUPPER 13.4 5.3 1.5

1.027 1.033 60.0 1.019

4.3R 4.8R 199115 70.8 71.3 140.6 -61.7 L6549 62.5

11N-LAFARGE 1.1 0.3 7.6 -10.1 65.0 -0.7 1.4 1 4.9R 199036 4.3 85S-WRECK_1 5.3 -5.3 -1.6 1.033 1.2 142.5 1.6 199690 1.048 1C-TUPPER0.985 144.7 1.023 24.6 199116 70.6 16N-STEWIAKE 3.0 8.4 199054 3.1 -19.5 47C-NEW_PAGE 1.019 199692 120C-BEARHD 1.000 140.6 Bus - Voltage (kV/pu) 13.8 199691

-20.0-2.0 20.0 Branch - MW/Mvar

20.0 120C-BEARHD 1.025 2.0 -0.7R Equipment - MW/Mvar 0.973 100.0%Rate A 0.4 1.050OV 0.970UV kV: <=35.000 <=69.000 <=138.000 <=230.000 <=345.000 >345.000 2021 WINTER PEAK: 2021WIN - FULL WIND ON BACKBONE Total Wind Gen: 301.7 MW Gross Tupper 0.0 MW Gross Wreck Cove 130.0 MW Net NewPage Load 20.5 MW Winter Ratings DERIVED FROM UPDATE OF 2014 SERIES MMWG 2020 WINTER PEAK Gross Lingan 320.0 MW Gross Trenton 310.0 MW Gross Gas Turbine 15.0 MW Gross NewPage Load 65.5 MW Figure ___D-9 FRI, SEP 29 2017 21:51 Gross Pt Aconi 185.0 MW Gross Tuft's Cove 250.0 MW Gross Small Hydro 177.7 MW Total BMPC Load -0.7 MW Includes 70% Distributed Generation Total Gross Gen: 1665.4 MW ML HVDC: 330.0 MW Gross Gen + ML: 1995.4 MW modeled as Negative Load: -143.0 MW 1 2018 10 Year System Outlook Report Appendix B Page 69 of 84

EEXS: 154.4 MW NB to NE: 0.6 MW EEXEB: 471.6 MW NB to QC: -300.0 MW ML HVDC: 330.0 MW NSX 150.9 MW MAINLAND AT HASTINGS: 472.2 MW CBX 845.3 MW HASTINGS FROM 88S,5S,2S: 390.2 MW ONI 1112.9 MW 1.038 199137 199555 71.6 3N-OXFORD FORCE_HV L-7011:143.3 MW ONS 876.1 MW 199138 199147 5.0 199557 3.0 1.014 1 7N-PUGWASH 37N-PARSBORO 0.7 -1.0L IR516_G L-7012: 148.5 MW NB to PEI: 197.0 MW 0.9 5.1 -5.1 2.0 7.3 -14.414.5 1.017 4.0 199558 Nova Scotia New Brunswick L-7011 + L-7012: 291.8 MW 1 0.4 IR517 8.0 10.9 -10.9 0.8 -1.2 0.5 -5.8 3.5 -3.5 -1.0L 190401 1.033 1.032 1.028 5.6 199559 MEM138 2.3 3.0 -3.1 1 190197 71.2 71.2 0.7 0.0H IR542_G 190075 190150 SACK138 MEM69 1.032 199530 C.COVE 199139 71.2 92N-AMHSTWIN 199531 199533 16.9 -56.8 -41.8 42.0 10N-ABER_ST 199145 92N-AMHSTLV 92N-AMHSTGEN 199146 1 1.024 6.0 -6.0 25.0 0.95 30N-MACCAN 30N-MACCAN 141.4 2.5 -30.7 1.025 -30.8 31.0 3.1 -13.0 11.8 -12.3 1.023 1.043 -7.3 -3.1 1.024 2.2 -2.3 8.6 -16.9 1.034 352.8 71.9 141.3 -41.6 71.3 434.6 5.4 9.2 2.4 5.1 -3.5R

199136 1.044 0.975 1.045 1.003 1.000 190379

74N-SPRINGHL 72.0 72.1 0.96875 34.6 0.6 BOR1159 -0.1 0.1 -2.6 2.6 28.1 L6535 -28.1 -28.0 11.0 -11.0 -36.0 36.1 0.0 2.8 17.0

-38.3 7.2 L6514 -8.6 -0.6 L6551 -0.2 -2.2 2.0 0.9 -3.8 3.4 12.1 -12.8 36 Mvar 1.028 1.023 141.8 141.1 1.028 1.028 141.8 141.9 199152 190408 22N-CHURCHST BOR1160 190258 190498 1.024 -429.2

27.8 48.6 L6513 -52.8 L6536 -27.7 8.2 8.2 -8.2 MURRCRNORTON 353.3

19.1 3.5 -4.6 -1.2 -0.5 -1.0 1.026 190341 1.032 199135 141.6 HARDRD 73.9 -72.7 67.3 -67.1 5.7

142.4 74N-SPRNGHIL 19.5 199134 -19.3 199125 26.5 81N-DEBERT 67N-ONSLOW -54.3 -22.8 25.6 -26.6 27.2 304.5 199195 9.0 5.4 1.0 1.033 1.037 103H-LAKSIDE 142.5 143.1 1.016 L8002 -271.2 10.3 140.2 273.4 -79.7 53.2 190320 -9.8 -22.9 190402 SALBRY 1.018 MEM345 351.2

+ 37.5 MVar 190381 -202.3 0.0 BR3025 -302.5 18.7 -38.6 114.5 L8001 -114.1 190417

1.0063 38.1 1.025 BATHURST -49.3 -8.6 -88.5 199130 141.5 88.6 -124.3 125.2 67N-ONSLOW 4.3 199045 -24.0 -33.1 -59.2 101S-WOODBIN 1.027 199120 0.0 199042 354.4 79N-HOPWELL -16.1 101S-WOODBIN 1.028 55.1 1.029 199043354.6 1 -497.4 500.2 -367.1 354.9 373.2 21.6 102S-ACONI 5.6 199200 61.1 L8003 -46.8 -6.6 L8004 -14.9 18.9 L7015 120H-BRUSHY -169.3 170.5 185.0 L7001 54.3 199855 0.0 1.01 -7.8 33.0R 199001 -144.9 147.0 1 NS_DC_POLE1 10.3 -16.1 88S-LINGAN_1 5.5 160.0 199121 165.0 21.6 19.5 -19.2 -66.6 -133.1 14.2 79N-HOPWELL -29.3R 18.9 46.5R 1.024 199593 23.2 53.5 1.018 1.01 7.3 -141.9 L7002 144.0 0.98 353.4 91N-DALHOGEN 199050 199857 122.2 8.1 49.5 3C-HASTINGS NS_DC_POLE2 1.000 18.9 -19.1 -66.6 165.0 -55.9 L7014 20.0 56.0 1.021 199590 3.8R 4.1 352.1 91N-DALHOUS 23.2 1.029 -29.3R 2 * 50 Mvar 1.8 -8.0 0.6 1.018 -205.5 L7018 207.5 -181.0 L7019 2 * 30 Mvar 182.8 -135.4 L7004 139.1 L7021 -140.6 122.2 1.035 143.3 -53.8 54.0 0.990 357.1 14.3 18.8 -17.9 31.3 -27.9 19.2 -21.5 20.7 L7011 -21.4 3.8 -9.9

1.025 L7003 L7012 L7022 -141.7 235.7 148.2 -146.4 148.5 -55.9 56.0 199202 15.8 -16.2 1.8 -8.0 120H-BRSHSVC 27.4 -26.1 199002 199010 88S-LINGAN_2 0.0 -152.7 L7005 156.2 199110 199015 199016 2S-VJ 1.027 1N-ONSLOW 15S-WATRFORD-9.8 9.8 109S-LINWIND 236.3 -0.0R 14.6 -11.7 199051 -86.3 -3.0 3.0 21.0 -20.8 2C-HASTINGS 199019

1.01 1.028 79.9 67.0 67.0 81S-RESERVE 10.9 199100 70.9 6.9 -6.5 49N-MICHGRAN 14.0 -14.0 -14.0 4.2 -4.2 1.021 -9.5 -22.3 -22.3 234.9 1 1 1.023 199076 -1.3R 2.5 3.7 -6.7 6.6 1.000 199154 235.2 4C-LOCHABER -78.3 15.6 -15.4 8.2 -8.2 29.0 199090 199610 199075 0.998 14.4 82V-ELMSDALE 50N-TRENTON 93N-GLENDHU 100C-PORCUPN 11.41 199423 0.4 1.9 -1.8 0.2 -0.2 6.8 11.5 5.1 109S-LINWIND 1.029 -101.2 L6001 104.2 L6503 155.0 L6511 50.1 7.7 L6552 -7.7 -20.3 L6515 20.4 -28.6 L6515 -140.1 143.2 -49.6 28.6 71.0 -78.3 62.2 22.0 -11.3 27.8 -3.3 4.6 14.2 -14.4 1.6 -2.9 -5.3 2.6 -9.6 9.4 199007 1.018 2S-VICTORIA 70.2 1.009 11.41 199063 199056 26.0 199003 139.3 0.0 199091 22C-CLEVLAND 59C-STPETERS 0.97 88S-LINGAN_3 50N-TRENTON -57.8 30.4 -2.4 8.2

50 Mvar-51.6 1.02 63.1 12.7 6.2 2.0 7.0 1.027 30.5 150.0 236.3 199006 26.3 0.97 88S-LINGAN_B 14.8 17.0R L6516 L6533 8.2 1.015 1.013 1.022 1.035 1.025 -8.3 25.2 -63.3 63.5 63.5 4.1 3.3 1.0

13.2 71.4 140.1 139.8 141.1 4.2 199053 5.2 -7.4 -25.1 25.7 27.6 18.4 29.7 165.0 47C-NEW_PAGE 0.98 59.9 L6518 -59.7 1.022 1.024 1.037 199057 141.1 141.3 143.1 0.957 4.4 14.5 22.1R -18.7 18.7 199611 67C-WHYC_TAP 199033 199031 199025 199005 13.8

1.0375 1.0375 4.6 -4.4 93N-GLENDHUM 199072 104S-BADDECK 5S-GLEN_TOSH 3S-GANNON_RD 88S-LINGAN_A 1.037 -6.6 5.9 L6534 199112 71.6 1.018 48C-BIOMASS 199004 L6517 -67.5 L6537 68.1 -72.9 73.2 50.5 L6538 -50.1 L6539 -22.5 -64.7 65.0 65.0 1N-ONSLOW_B 199111 140.5 199118 0.973 88S-LINGAN_4 4N-TATAMAG 45.0 -44.9 -44.9 -80.5 -71.7 -48.1 48.8 160.0 199114 1N-ONSLOW_A 199580 33.64.2 -57.9 1 4.6 -3.5 1.6 -0.8 0.9 -1.1 4.6 -24.4 25.0 27.0 15N-WILLOWLN 0.98 89N_NUTBTP -3.9 9.7 -9.6 9.6 -6.7R 10.4 9.3 -3.9 10.1 -10.5 1.037 34.1R 1.025 143.1 50.7 -26.8 39.2 1.015 14.0 141.4 0.9625 2.4 -2.6 2.6 4.8 27.5 8.0 199584 1.024 1.023 199026 10.9 18.3 -12.3 1.026 0.99 89N_NUTBG 3S-GANNON_RD 1.028 199581 70.8 199612 141.3 141.2 1.9 7.7 4.1 1.1 59.7 70.9 0.96875 89N_NUTBHV 93N-GLENDHUG 1.028 -48.9 48.9 50.0 L6523 1.014 1.016 1.000 70.0 236.4 0.980 140.2 4.6 1 34.5 -1.1 14.1

9.9 -9.8 0.6R -59.7 1.036 0.8 1.0380.990 1.029 1.024 199035 71.5 71.6 0.4 142.1 141.3 85S-WRK_COVE 1.038 199613 L6545 199037 1.2 -6.5 6.5 71.6 93N-GLENDHU -62.1 63.0 85S-WRECK_2 199052 65.0 0.1 4.1 -1.5 1.3 4.5 -0.0 0.8 80.5 1C-TUPPER 72.0 5.3 1.5

1.030 1.037 60.0 1.029

4.3R 4.1R 199115 71.1 71.5 142.0 -61.7 L6549 62.5

11N-LAFARGE 1.1 0.3 9.1 -10.1 65.0 6.0 2.0 -0.0 0.7 33.3R 150.0 1 4.1R 199036 4.3 85S-WRECK_1 5.3 -5.3 -1.6 1.034 1.2 142.7 1.6 199690 1.049 1C-TUPPER0.988 144.8 1.027 24.7 199116 70.9 16N-STEWIAKE 3.0 8.4 199054 4.5 -19.5 47C-NEW_PAGE 1.028 199692 120C-BEARHD 1.000 141.9 Bus - Voltage (kV/pu) 13.8 199691

-20.0-3.5 20.0 Branch - MW/Mvar

20.0 120C-BEARHD 1.025 3.5 -2.1R Equipment - MW/Mvar 0.968 100.0%Rate A 0.4 1.050OV 0.970UV kV: <=35.000 <=69.000 <=138.000 <=230.000 <=345.000 >345.000 2021 WINTER PEAK: 2021WIN-1 - FULL WIND ON BACKBONE, NSX 150 Total Wind Gen: 301.7 MW Gross Tupper 150.0 MW Gross Wreck Cove 130.0 MW Net NewPage Load 20.5 MW Winter Ratings DERIVED FROM UPDATE OF 2014 SERIES MMWG 2020 WINTER PEAK Gross Lingan 320.0 MW Gross Trenton 315.0 MW Gross Gas Turbine 15.0 MW Gross NewPage Load 65.5 MW Figure D-10___ FRI, SEP 29 2017 22:56 Gross Pt Aconi 185.0 MW Gross Tuft's Cove 267.0 MW Gross Small Hydro 177.7 MW Total BMPC Load -0.7 MW Includes 70% Distributed Generation Total Gross Gen: 1837.4 MW ML HVDC: 330.0 MW Gross Gen + ML: 2167.4 MW modeled as Negative Load: -143.0 MW 1 2018 10 Year System Outlook Report Appendix B Page 70 of 84

EEXS: 231.5 MW NB to NE: 0.3 MW EEXEB: 543.8 MW NB to QC: -300.0 MW ML HVDC: 330.0 MW NSX 150.5 MW MAINLAND AT HASTINGS: 446.0 MW CBX 856.1 MW HASTINGS FROM 88S,5S,2S: 511.9 MW ONI 1123.1 MW 1.036 199137 199555 71.5 3N-OXFORD FORCE_HV L-7011:186.0 MW ONS 886.7 MW 199138 199147 1.012 5.0 199557 3.0 1 7N-PUGWASH 37N-PARSBORO 0.7 -1.0L IR516_G L-7012: 192.2 MW NB to PEI: 196.9 MW 0.9 5.1 -5.1 2.0 7.3 -14.414.5 1.016 4.0 199558 Nova Scotia New Brunswick L-7011 + L-7012: 378.3 MW 1 0.4 IR517 8.0 10.9 -10.9 0.8 -1.2 0.5 -5.8 3.5 -3.5 -1.0L 190401 1.030 1.031 1.026 5.6 199559 MEM138 2.3 3.0 -3.1 1 71.1 71.1 0.7 0.0H IR542_G 190075 190150 190197 SACK138 MEM69 1.030 199530 C.COVE 199139 71.1 92N-AMHSTWIN 199531 199533 10N-ABER_ST 92N-AMHSTLV 92N-AMHSTGEN 16.9 -56.8 -42.0 42.3

199146 199145 1 1.023 6.0 -6.0 25.0 0.95 30N-MACCAN 30N-MACCAN 141.2 2.5 -30.7 1.025 -30.8 31.0 3.1 -13.0 11.3 -11.8 1.023 -7.3 -3.1

1.041 -16.9 2.2 -2.3 8.6 1.032 1.023 352.8 -39.8 71.8 5.4 71.2 141.2 434.6 9.2 2.1 4.8 -3.2R

199136 1.042 0.975 1.043 1.002 1.000 190379

74N-SPRINGHL 71.9 72.0 0.96875 34.6 0.6 BOR1159 27.6 L6535

-0.5 0.5 -3.1 3.1 -27.6 -27.5 10.62.8 -10.5 -36.2 36.4

0.0 17.0

-38.2 6.8 L6514 -8.2 -1.0 L6551 0.3 -2.4 2.1 1.1 -3.9 3.5 11.7 -12.3 36 Mvar 1.026 1.022 141.6 141.0 1.026 1.027 141.6 141.7 199152 190408 22N-CHURCHST BOR1160 190258 190498 1.023 -429.1 L6513 27.2 L6536 46.8 -51.6 -27.1 7.6 7.6 -7.6 MURRCRNORTON 353.0

19.7 3.1 -4.2 -1.5 -0.9 -0.7 1.025 190341 1.030 199135 141.4 HARDRD

5.7 73.9 -72.7 67.3 -67.0 19.5 199134 -20.0 142.1 74N-SPRNGHIL 199125 26.5 81N-DEBERT 67N-ONSLOW -52.2 -22.9 25.8 -26.7 27.3 304.4 5.4 1.0 199195 9.0 1.032 1.036 103H-LAKSIDE 142.4 143.0 1.013 L8002 -276.3 11.0 278.7 -78.6139.8 52.1 190320 -8.0 -23.2 190402 SALBRY MEM345 1.014 349.8

+ 37.5 MVar 190381 -202.6 0.0 BR3025 -302.5 19.7 -38.5 115.3 L8001 -114.8 190417

1.0063 36.1 1.024 BATHURST -54.6 -2.8 -88.0 199130 141.3 88.1 -124.3 125.2 67N-ONSLOW -0.8 199045 -18.9 -34.3 -57.9 101S-WOODBIN 1.027 199120 0.0 199042 354.3 79N-HOPWELL -16.1 101S-WOODBIN 1.027 64.4 1.027 199043354.2 1 -521.9 525.0 -402.8 354.3 410.1 40.1 102S-ACONI 5.9 199200 66.1 L8003 -46.9 -0.3 L8004 -1.4 10.6 L7015 120H-BRUSHY -169.3 170.5 185.0 L7001 63.5 199855 0.0 1.01 -8.9 199001 1 11.4 34.2R -146.0 148.1 NS_DC_POLE1 88S-LINGAN_1 5.8 -16.1 165.0 40.1 160.0 20.9 -20.1 199121 79N-HOPWELL-61.2 -122.2 14.2 -14.5R 10.6 45.2R 199593 1.020 1.01 7.3

20.6 0.98 47.2 1.025 -143.0 L7002 145.1 91N-DALHOGEN 352.0 199050 123.0 199857 49.5 3C-HASTINGS NS_DC_POLE2 1.000 8.1 20.2 -20.0 -61.1 165.0 -97.5 L7014 20.0 97.9 1.016 199590 4.9R 4.1 350.7 91N-DALHOUS 20.6 1.030 -14.5R 2 * 50 Mvar 0.7 -4.8 0.6 1.025 -207.1 L7018 209.2 -176.2 L7019 2 * 30 Mvar 178.0 -130.6 L7004 134.1 -181.5 186.0 -94.1 L7021 94.5 123.0 1.035 0.990 357.1 14.3 20.6 -19.0 32.3 -29.2 21.5 -24.6 24.6 L7011 -12.6 4.3 -8.4

1.020 L7003 L7012 L7022 -136.8 234.6 142.9 -188.8 192.2 -97.5 97.8 199202 18.3 -5.4 0.7 -4.8 120H-BRSHSVC 29.1 -28.9 199002 199010 88S-LINGAN_2 0.0 -147.7 L7005 151.1 199110 199015 199016 2S-VJ 1.026 1N-ONSLOW 15S-WATRFORD-9.8 9.8 109S-LINWIND 236.0 0.0R 16.9 -15.2 199051 -86.1 -3.0 3.0 21.0 -20.8 2C-HASTINGS 199019 78.8 1.01 61.5 61.5 1.028 199100 70.9 81S-RESERVE 13.1 14.0 -14.0 -14.0 4.2 -4.2 6.9 -6.5 1.018 49N-MICHGRAN -10.2 -20.1 -20.1 1 1 234.1 1.018 199076 -1.2R 2.4 3.7 -6.7 6.5 1.000 199154 234.2 4C-LOCHABER -29.0 15.6 -15.4 8.2 -8.2 29.0 199090 199610 199075 0.999 14.4 82V-ELMSDALE 50N-TRENTON 93N-GLENDHU 100C-PORCUPN 13.01 199423 0.4 1.9 -1.8 0.2 -0.2 6.8 11.5 5.1 109S-LINWIND 1.029 -102.5 L6001 105.6 L6503 155.4 -39.0 L651139.3 18.4 L6552 -18.4 -9.6 L6515 9.6 -17.8 L6515 -140.5 143.6 17.8 71.0 -29.0 62.2 23.0 -11.8 27.0 -2.2 5.7 14.0-14.9 3.1 -4.3 -3.6 0.5 -7.5 7.3 199007 1.017 2S-VICTORIA 1.006 13.01 199063 199056 70.2 199003

0.97 26.0 138.9 0.0 199091 22C-CLEVLAND 59C-STPETERS 88S-LINGAN_3 50N-TRENTON -57.8 30.4 -2.4 8.2 160.0 50 Mvar-51.3 1.02 63.1 11.8 6.2 1.6 7.0 1.018 32.6R 30.5 150.0 234.2 199006 26.3 0.97 88S-LINGAN_B 14.7 19.8R L6516 L6533 8.2 1.025 1.011 1.007 1.012 1.034

-27.6 4.1 3.3 1.0 45.3 -80.6 81.0 81.0

13.2 71.4 139.5 139.0 139.7 4.2 199053 8.0 -6.2 -24.7 26.2 29.2 18.4 29.7 165.0 47C-NEW_PAGE 0.98 -7.1 L6518 7.1 1.012 1.015 1.037 199057 139.7 140.1 143.2 0.980 4.4 14.4 24.4R -18.7 18.7 199611 67C-WHYC_TAP 199033 199031 199025 199005 14.1

1.0375 1.0375 1.7 -2.4 93N-GLENDHUM 199072 104S-BADDECK 5S-GLEN_TOSH 3S-GANNON_RD 88S-LINGAN_A 1.036 -6.7 5.9 L6534 199112 71.5 1.016 48C-BIOMASS 199004 L6517 -82.1 L6537 83.0 -87.8 88.3 35.5 L6538 -35.2 L6539 -7.7 -82.3 82.8 82.8 1N-ONSLOW_B 199111 140.3 199118 0.971 88S-LINGAN_4 4N-TATAMAG 45.0 -44.9 -44.9 4.4 -62.2 63.4 160.0 199114 1N-ONSLOW_A 199580 33.53.3 -13.4 -57.9 1 15N-WILLOWLN 4.1 -1.7 -0.3 1.8 1.6 -2.8 2.4 -23.8 25.1 0.98 28.2 89N_NUTBTP 7.1 9.7 -9.6 9.6 1.7R 2.0 1.0 -0.9 12.0 -10.0 1.038 32.8R 1.015 1.024 143.2 50.8 -26.8 39.2 141.4 0.9625 2.4 -2.6 2.6 14.0 4.8 27.5 8.0 199584 199026 11.0 17.8 -11.8 1.025 1.013 1.016 0.99 89N_NUTBG 3S-GANNON_RD 1.024 199581 70.7 199612 139.8 140.2

2.1 1.9 7.7 4.1 59.7 70.7 0.96875 89N_NUTBHV 93N-GLENDHUG 1.029 -48.9 48.9 50.0 L6523 1.013 1.013 1.000 69.9 236.6 0.980 4.6 139.8 1 34.5-2.1 14.1

9.4 -9.3 1.1R -59.7 1.032 0.8 1.0370.991 1.025 1.023 199035 71.2 71.5 0.4 141.4 141.1 85S-WRK_COVE 1.036 199613 L6545 199037 1.2 -6.5 6.5 71.5 93N-GLENDHU -62.1 63.0 85S-WRECK_2 199052 65.0

0.1 0.1 -7.2 -4.4

-1.5 1.3 13.4 -1.7 2.5

5.3 1.5 1C-TUPPER

1.034 60.0 1.013

1.028 5.3R 5.8R 199115 70.9 71.4 139.8 -61.7 L6549 62.5

11N-LAFARGE 1.1 0.3 6.8 -10.1 65.0 -1.7 2.4 1 5.9R 199036 4.3 85S-WRECK_1

5.3-5.3 -1.6 1.031 1.2 142.3 1.6 199690 1.048 1C-TUPPER0.983 144.6 1.024 24.6 199116 70.7 16N-STEWIAKE 3.0

199054 8.4 2.3 -19.5 47C-NEW_PAGE 1.013 199692 120C-BEARHD 1.000 139.8 Bus - Voltage (kV/pu) 13.8 199691

-20.0-1.3 20.0

20.0 120C-BEARHD Branch - MW/Mvar 1.025 1.3 0.1R Equipment - MW/Mvar 0.975 100.0%Rate A 0.4 1.050OV 0.970UV kV: <=35.000 <=69.000 <=138.000 <=230.000 <=345.000 >345.000 2021 WINTER PEAK: 2021WIN-1A - FULL WIND ON BACKBONE, Total Wind Gen: 301.7 MW Gross Tupper 0.0 MW Gross Wreck Cove 130.0 MW Net NewPage Load 20.5 MW Winter Ratings Gross Lingan 480.0 MW Gross Trenton 315.0 MW Gross Gas Turbine 15.0 MW Gross NewPage Load 65.5 MW D-11 DERIVED FROM UPDATE OF 2014 SERIES MMWG 2020 WINTER PEAK Figure ___ SAT, SEP 30 2017 8:58 Gross Pt Aconi 185.0 MW Gross Tuft's Cove 257.0 MW Gross Small Hydro 177.7 MW Total BMPC Load -0.7 MW Includes 70% Distributed Generation Total Gross Gen: 1837.4 MW ML HVDC: 330.0 MW Gross Gen + ML: 2167.4 MW modeled as Negative Load: -143.0 MW 1 2018 10 Year System Outlook Report Appendix B Page 71 of 84

EEXS: 128.0 MW NB to NE: -0.7 MW EEXEB: 395.3 MW NB to QC: -300.0 MW ML HVDC: 330.0 MW NSX -100.8 MW MAINLAND AT HASTINGS: 326.4 MW CBX 621.9 MW HASTINGS FROM 88S,5S,2S: 387.2 MW ONI 895.9 MW 1.033 199137 199555 71.3 3N-OXFORD FORCE_HV L-7011:141.1 MW ONS 911.2 MW 199138 199147 1.009 5.0 199557 3.0 7N-PUGWASH 37N-PARSBORO 0.7 -1.0L IR516_G L-7012: 146.2 MW NB to PEI: 196.4 MW 0.9 5.1 -5.1 2.0 7.3 -14.414.5 1.012 4.0 199558 Nova Scotia New Brunswick L-7011 + L-7012: 287.4 MW 0.4 IR517 8.0 10.9 -10.9 0.8 -1.2 0.5 -5.8 3.5 -3.5 -1.0L 190401 1.028 1.028 1.023 5.6 199559 MEM138 2.3 3.0 -3.2 71.0 70.9 0.7 0.0H IR542_G 190075 190150 190197 SACK138 MEM69 1.027 199530 C.COVE 199139 70.9 92N-AMHSTWIN 199531 199533 10N-ABER_ST 92N-AMHSTLV 92N-AMHSTGEN 16.9 -56.8 -62.1 62.6

199146 199145 1 1.018 6.0 -6.0 25.0 0.95 30N-MACCAN 30N-MACCAN 140.5 2.5 -30.7 1.025 -30.8 31.0 3.1 -13.0 18.0 -17.2 1.019 -7.3 -3.1 -16.9

1.038 -9.4 2.2 -2.3 8.6 1.026 1.017 351.7

71.7 5.5 70.8 140.4 562.6 9.2 1.5 4.2 -2.6R

199136 1.040 0.975 1.040 1.001 1.000 190379

74N-SPRINGHL 71.7 71.8 0.96875 34.5 0.6 BOR1159 9.3 L6535

-18.8 18.8 -21.3 21.4 -9.3 -9.3 -7.62.8 7.6 -55.8 56.2

0.0 17.0

-38.0 12.4 L6514 -13.6 4.3 L6551 -5.0 3.4 -3.8 -5.2 2.3 -2.7 18.0 -17.6 36 Mvar 1.023 1.016 141.1 140.2 1.023 1.023 141.2 141.2 199152 190408 22N-CHURCHST BOR1160 190258 190498 1.013 -553.4 L6513 4.6 L6536 56.5 -10.8 -4.6 -14.9 -15.0 15.0 MURRCRNORTON 349.5

6.8 10.2 -11.6 5.8 6.4 -7.8 1.021 190341 1.028 199135 140.9 HARDRD

5.7 73.7 -72.5 67.1 -66.8 19.5 199134 -10.5 141.8 74N-SPRNGHIL 199125 26.5 81N-DEBERT 67N-ONSLOW -67.1 -23.4 26.3 -27.3 27.9 435.7 5.4 1.0 199195 9.0 1.027 1.032 103H-LAKSIDE 1.019 141.8 142.4 -290.6 1.6 L8002 293.2 -37.3140.6 10.8 190320 -12.1 -17.3 190402 SALBRY MEM345 1.019 351.4

+ 37.5 MVar 190381 -187.5 0.0 BR3025 -431.6 16.4 -38.1 -95.1 L8001 95.5 190417

1.0063 74.1 1.019 BATHURST -10.1 -49.2 -283.2 199130 140.6 284.2 -178.4 180.3 67N-ONSLOW 45.5 199045 -55.6 -27.0 -53.7 101S-WOODBIN 1.022 199120 0.0 199042 352.6 79N-HOPWELL -16.1 101S-WOODBIN 1.020 104.8 1.023 199043351.8 1 -406.1 408.0 -291.6 352.8 295.4 -17.3 102S-ACONI -2.4 199200 32.2 L8003 -32.7 -21.6 L8004 -34.6 26.3 L7015 120H-BRUSHY -169.3 170.5 185.0 L7001 103.3 199855 0.0 1.01 -6.9 199001 1 9.4 32.1R -147.2 149.3 NS_DC_POLE1 88S-LINGAN_1 -2.4 -16.1 165.0 -17.3 160.0 16.5 -15.9 199121 79N-HOPWELL-58.2 -116.3 14.2 -45.7R 26.3 45.1R 199593 1.027 1.01 7.3

24.3 0.98 54.3 1.010 -144.2 L7002 146.3 91N-DALHOGEN 354.3 199050 121.2 199857 49.5 3C-HASTINGS NS_DC_POLE2 1.000 8.1 15.9 -15.9 -58.2 165.0 -28.2 L7014 20.0 28.2 1.026 199590 2.6R 4.1 353.9 91N-DALHOUS 24.3 1.028 -45.7R 2 * 50 Mvar -2.4 -4.5 0.6 1.010 -208.5 L7018 210.6 -144.4 L7019 2 * 30 Mvar 145.6 -98.1 L7004 100.1 -138.5 141.1 -27.2 L7021 27.2 121.2 1.035 0.990 357.1 14.3 14.3 -13.1 20.2 -20.2 10.3 -23.7 21.0 L7011 -22.3 -1.3 -5.5

1.030 L7003 L7012 L7022 -105.4 236.9 108.9 -144.2 146.2 -28.1 28.2 199202 16.2 -17.2 -2.4 -4.5 120H-BRSHSVC 14.5 -27.6 199002 199010 88S-LINGAN_2 0.0 -113.3 L7005 115.3 199110 199015 199016 2S-VJ 1.028 1N-ONSLOW 15S-WATRFORD-9.8 9.8 109S-LINWIND 236.5 0.0R 4.8 -17.3 199051 -64.8 -3.0 3.0 21.0 -20.8 2C-HASTINGS 199019 37.4 1.01 58.5 58.5 1.029 199100 71.0 81S-RESERVE 7.1 14.0 -14.0 -14.0 4.2 -4.2 6.9 -6.5 1.024 49N-MICHGRAN -2.1 -24.0 -23.9 1 1 235.5 1.027 199076 -1.4R 2.7 3.9 -6.9 6.7 1.000 199154 236.3 4C-LOCHABER -20.8 15.6 -15.4 8.2 -8.2 29.0 199090 199610 199075 0.997 14.4 82V-ELMSDALE 50N-TRENTON 93N-GLENDHU 100C-PORCUPN 15.81 199423 0.4 1.9 -1.8 0.2 -0.2 6.8 11.5 5.1 109S-LINWIND 1.030 -108.4 L6001 111.8 L6503 140.9 -23.5 L651123.6 34.1 L6552 -34.0 6.0 L6515 -6.0 -2.2 L6515 -126.6 129.1 2.2 71.1 -20.8 62.2 22.3 -9.7 23.5 -4.5 2.8 9.3-11.2 -2.0 1.2 -9.5 6.4 -13.4 13.2 199007 1.019 2S-VICTORIA 1.010 15.81 199063 199056 70.3 199003

0.97 26.1 139.3 0.0 199091 22C-CLEVLAND 59C-STPETERS 88S-LINGAN_3 50N-TRENTON -57.8 30.4 -2.4 8.2 50 Mvar-52.0 1.02 63.1 13.2 6.2 2.1 7.0 1.029 30.5 150.0 236.7 199006 26.4 0.97 88S-LINGAN_B 14.7 11.0R L6516 L6533 1.025 1.017 1.014 1.021 1.036

-11.4 4.1 3.3 1.0 28.4 -68.7 69.0 69.0 140.3 139.9 141.0 13.2 71.5 199053 5.3 -7.1 -24.5 25.4 27.6 18.4 29.7 160.0 47C-NEW_PAGE 0.98 -7.1 L6518 7.1 1.022 1.023 1.038 199057 141.0 141.2 143.3 0.980 4.4 14.4 16.5R -18.7 18.7 199611 67C-WHYC_TAP 199033 199031 199025 199005 14.1

1.0313 1.0313 -1.5 0.7 93N-GLENDHUM 199072 104S-BADDECK 5S-GLEN_TOSH 3S-GANNON_RD 88S-LINGAN_A 1.035 -6.6 5.9 L6534 199112 71.4 1.021 48C-BIOMASS 199004 L6517 -65.8 L6537 66.3 -71.1 71.5 42.6 L6538 -42.3 L6539 -14.7 -70.2 70.6 70.6 1N-ONSLOW_B 199111 140.9 199118 0.973 88S-LINGAN_4 4N-TATAMAG 45.0 -44.9 -44.9 4.4 -46.4 47.1 80.0 199114 1N-ONSLOW_A 199580 33.64.7 -13.4 -57.9 1 15N-WILLOWLN 3.5 -2.6 0.7 0.1 1.7 -2.5 2.8 -23.7 24.5 0.98 26.8 89N_NUTBTP 5.6 9.7 -9.6 9.6 -3.1R 6.8 5.7 1.8 8.8 -9.4 1.038 27.6R 1.015 1.026 143.3 50.8 -26.8 39.2 141.6 0.96875 2.4 -2.6 2.6 14.0 4.8 27.5 8.0 199584 199026

1.025 1.023 1.023 0.99 11.0 17.8 -11.8 89N_NUTBG

0.975 3S-GANNON_RD 1.025 199581 70.7 199612 141.1 141.2

0.7 1.9 7.7 4.1 70.7 89N_NUTBHV 59.7 93N-GLENDHUG 1.029 -48.9 48.9 50.0 L6523 1.015 1.019 1.000 70.0 236.6 0.980 4.6 140.7 1 34.5-0.7 14.1

9.4 -9.3 1.1R -59.7 1.033 0.8 1.0370.991 1.030 1.025 199035 71.2 71.5 0.4 142.1 141.5 85S-WRK_COVE 1.036 199613 L6545 199037 1.2 -6.5 6.5 71.5 93N-GLENDHU -57.2 58.0 85S-WRECK_2 199052 60.0 0.1 -5.7 -4.4 -2.6

-1.5 1.3 13.4 -0.9 1.0

5.3 1.5 1C-TUPPER

1.034 60.0 1.022

1.028 3.8R 4.0R 199115 70.9 71.4 141.0 -56.8 L6549 57.6

11N-LAFARGE 1.1 0.3 8.0 -10.1 60.0 -0.9 1.0 1 4.0R 199036 4.3 85S-WRECK_1

5.3-5.3 -1.6 1.035 1.2 142.8 1.6 199690 1.049 1C-TUPPER0.986 144.8 1.024 24.6 199116 70.7 16N-STEWIAKE 3.0

199054 8.4 3.5 -19.5 47C-NEW_PAGE 1.022 199692 120C-BEARHD 1.000 141.0 Bus - Voltage (kV/pu) 13.8 199691

-20.0-2.5 20.0

20.0 120C-BEARHD Branch - MW/Mvar 1.025 2.5 -1.1R Equipment - MW/Mvar 0.971 100.0%Rate A 0.4 1.050OV 0.970UV kV: <=35.000 <=69.000 <=138.000 <=230.000 <=345.000 >345.000 2021 WINTER PEAK: 2021WIN-2 - FULL WIND ON BACKBONE Total Wind Gen: 301.7 MW Gross Tupper 0.0 MW Gross Wreck Cove 120.0 MW Net NewPage Load 20.5 MW Winter Ratings Gross Lingan 240.0 MW Gross Trenton 310.0 MW Gross Gas Turbine 15.0 MW Gross NewPage Load 65.5 MW D-12 DERIVED FROM UPDATE OF 2014 SERIES MMWG 2020 WINTER PEAK Figure ___ SAT, SEP 30 2017 11:10 Gross Pt Aconi 185.0 MW Gross Tuft's Cove 233.0 MW Gross Small Hydro 177.7 MW Total BMPC Load -0.7 MW Includes 70% Distributed Generation Total Gross Gen: 1558.4 MW ML HVDC: 330.0 MW Gross Gen + ML: 1888.4 MW modeled as Negative Load: -143.0 MW 1 2018 10 Year System Outlook Report Appendix B Page 72 of 84

EEXS: 218.9 MW NB to NE: -0.2 MW EEXEB: 331.8 MW NB to QC: -300.0 MW ML HVDC: -100.0 MW NSX -100.3 MW MAINLAND AT HASTINGS: 372.7 MW CBX 604.4 MW HASTINGS FROM 88S,5S,2S: 288.3 MW ONI 878.5 MW 1.035 199137 199555 71.4 3N-OXFORD FORCE_HV L-7011:92.2 MW ONS 893.4 MW 199138 199147 1.010 5.0 199557 3.0 7N-PUGWASH 37N-PARSBORO 0.7 -1.0L IR516_G L-7012: 95.9 MW NB to PEI: 196.5 MW 0.9 5.1 -5.1 2.0 7.3 -14.414.5 1.014 4.0 199558 Nova Scotia New Brunswick L-7011 + L-7012: 188.2 MW 0.4 IR517 8.0 10.9 -10.9 0.8 -1.2 0.5 -5.8 3.5 -3.5 -1.0L 190401 1.030 1.029 1.024 5.6 199559 MEM138 2.3 3.0 -3.2 71.1 71.0 0.7 0.0H IR542_G 190075 190150 190197 SACK138 MEM69 1.029 199530 C.COVE 199139 71.0 92N-AMHSTWIN 199531 199533 10N-ABER_ST 92N-AMHSTLV 92N-AMHSTGEN 16.9 -56.8 -61.7 62.2

199146 199145 1 1.020 6.0 -6.0 25.0 0.95 30N-MACCAN 30N-MACCAN 140.7 2.5 -30.7 1.025 -30.8 31.0 3.1 -13.0 18.3 -17.5 1.019 -7.3 -3.1

1.040 -16.9 2.2 -2.3 8.6 1.028 1.018 351.7 -11.0 71.8 5.5 70.9 140.5 562.6 9.2 1.8 4.4 -2.9R

199136 1.041 0.975 1.042 1.002 1.000 190379

74N-SPRINGHL 71.9 71.9 0.96875 34.6 0.6 BOR1159 10.1 L6535

-18.0 18.0 -20.6 20.6 -10.1 -10.1 -6.92.8 6.9 -55.4 55.9

0.0 17.0

-38.1 12.7 L6514 -13.8 4.6 L6551 -5.2 3.5 -3.8 -5.2 2.4 -2.8 18.3 -17.9 36 Mvar 1.024 1.017 141.3 140.3 1.025 1.025 141.4 141.4 199152 190408 22N-CHURCHST BOR1160 190258 190498 1.014 -553.4 L6513 5.5 L6536 58.0 -12.6 -5.5 -14.0 -14.0 14.0 MURRCRNORTON 349.7

6.6 10.3 -11.7 6.0 6.6 -8.0 1.022 190341 1.029 199135 141.1 HARDRD

5.7 73.7 -72.5 67.1 -66.9 19.5 199134 -10.3 142.0 74N-SPRNGHIL 199125 26.5 81N-DEBERT 67N-ONSLOW -68.9 -23.3 26.2 -27.2 27.8 435.7 5.4 1.0 199195 9.0 1.028 1.033 103H-LAKSIDE 1.021 141.9 142.5 -281.8 1.3 L8002 284.2 -39.1140.9 12.6 190320 -13.6 -18.0 190402 SALBRY MEM345 1.022 352.6

+ 37.5 MVar 190381 -186.8 0.0 BR3025 -431.6 15.5 -38.2 -96.4 L8001 96.8 190417

1.0063 75.8 1.020 BATHURST -5.2 -54.2 -283.8 199130 140.8 284.8 -178.3 180.2 67N-ONSLOW 49.8 199045 -59.9 -26.0 -54.8 101S-WOODBIN 1.022 199120 199042 352.7 79N-HOPWELL 101S-WOODBIN 1.021 87.5 1.024 199043352.1 1 -361.5 362.9 -229.3 353.3 231.6 165.9 102S-ACONI -0.3 199200 23.9 L8003 -30.7 -31.4 L8004 -47.0 20.8 L7015 120H-BRUSHY -169.3 170.5 185.0 L7001 86.2 199855 1.01 -7.6 199001 1 10.0 32.7R -145.4 147.4 NS_DC_POLE1 88S-LINGAN_1 -0.3 -50.0 165.9 160.0 15.8 -15.8 199121 79N-HOPWELL-66.9 -133.6 14.2 -38.9R 20.8 43.8R 199593 1.030 1.01 7.3

27.3 0.98 62.1 1.016 -142.4 L7002 144.4 91N-DALHOGEN 355.4 199050 122.0 199857 49.5 3C-HASTINGS NS_DC_POLE2 1.000 8.1 15.2 -15.8 -66.8 -50.0 -118.3 L7014 20.0 118.8 1.030 199590 2.0R 4.1 355.3 91N-DALHOUS 27.3 1.027 -38.9R 2 * 50 Mvar 4.0 -6.7 0.6 1.016 -205.9 L7018 207.9 -153.7 L7019 2 * 30 Mvar 155.0 -107.6 L7004 109.9 -91.1 92.2 -114.0 L7021 114.7 122.0 1.035 0.990 357.1 14.3 13.5 -13.1 22.2 -21.5 10.9 -22.4 15.1 L7011 -26.7 8.3 -11.0

1.033 L7003 L7012 L7022 -114.7 237.6 118.8 -95.0 95.9 -118.2 118.7 199202 12.1 -23.6 4.0 -6.7 120H-BRSHSVC 16.2 -26.6 199002 199010 88S-LINGAN_2 0.0 -123.3 L7005 125.5 199110 199015 199016 2S-VJ 1.028 1N-ONSLOW 15S-WATRFORD-9.8 9.8 109S-LINWIND 236.3 -0.0R 5.6 -15.3 199051 -65.5 -3.0 3.0 21.0 -20.8 2C-HASTINGS 199019 39.2 1.01 67.3 67.3 1.029 199100 71.0 81S-RESERVE 5.9 14.0 -14.0 -14.0 4.2 -4.2 6.9 -6.5 1.027 49N-MICHGRAN -1.8 -26.4 -26.3 1 1 236.1 1.030 199076 -1.4R 2.6 3.9 -6.8 6.7 1.000 199154 237.0 4C-LOCHABER -84.0 15.6 -15.4 8.2 -8.2 29.0 199090 199610 199075 0.998 14.4 82V-ELMSDALE 50N-TRENTON 93N-GLENDHU 100C-PORCUPN 18.51 199423 0.4 1.9 -1.8 0.2 -0.2 6.8 11.5 5.1 109S-LINWIND 1.030 -106.1 L6001 109.4 L6503 139.6 -39.7 L651140.0 17.7 L6552 -17.7 -10.3 L6515 10.3 -18.5 L6515 -125.4 127.8 18.5 71.1 -84.0 62.2 21.3 -9.4 24.0 -5.5 1.8 12.1-13.1 -0.6 -0.6 -7.8 4.8 -11.8 11.6 199007 1.019 2S-VICTORIA 1.012 18.51 199063 199056 70.3 199003

0.97 26.1 139.6 0.0 199091 22C-CLEVLAND 59C-STPETERS 88S-LINGAN_3 50N-TRENTON -57.8 30.4 -2.4 8.2 160.0 50 Mvar-52.2 1.02 63.1 13.7 6.2 2.3 7.0 1.034 31.2R 30.5 150.0 237.9 199006 26.4 0.97 88S-LINGAN_B 14.7 9.4R L6516 L6533 8.2 1.025 1.019 1.017 1.026 1.036

-2.3 4.1 3.3 1.0 19.0 -50.1 50.2 50.3

13.2 71.5 140.6 140.3 141.7 4.2 199053 4.5 -7.5 -28.5 28.7 30.0 18.4 29.7 160.0 47C-NEW_PAGE 0.98 59.9 L6518 -59.7 1.026 1.027 1.038 199057 141.6 141.7 143.3 0.980 4.4 14.4 15.1R -18.7 18.7 199611 67C-WHYC_TAP 199033 199031 199025 199005 14.1

1.0313 1.0313 1.2 -1.1 93N-GLENDHUM 199072 104S-BADDECK 5S-GLEN_TOSH 3S-GANNON_RD 88S-LINGAN_A 1.036 -6.6 5.9 L6534 199112 71.5 1.022 48C-BIOMASS 199004 L6517 -75.2 L6537 75.9 -80.7 81.1 71.6 L6538 -70.8 L6539 -42.8 -51.4 51.6 51.6 1N-ONSLOW_B 199111 141.1 199118 0.974 88S-LINGAN_4 4N-TATAMAG 45.0 -44.9 -44.9 -71.7 -55.5 56.4 160.0 199114 1N-ONSLOW_A 199580 33.65.2 -80.5 -57.9 1 15N-WILLOWLN 8.4 -6.6 4.7 -3.5 -2.9 4.8 11.7 -28.1 28.2 0.98 29.7 89N_NUTBTP -2.3 9.7 -9.6 9.6 -8.4R 12.2 11.1 -0.4 15.1 -14.3 1.038 31.3R 1.015 1.026 143.3 50.7 -26.8 39.2 141.5 0.96875 2.4 -2.6 2.6 14.0 4.8 27.5 8.0 199584 199026

1.026 1.028 1.024 0.99 10.9 18.2 -12.2 89N_NUTBG

0.975 3S-GANNON_RD 1.027 199581 70.8 199612 141.8 141.3

0.2 1.9 7.7 4.1 70.9 89N_NUTBHV 59.7 93N-GLENDHUG 1.030 -48.9 48.9 50.0 L6523 1.013 1.022 1.000 69.9 236.9 0.980 4.6 141.0 1 34.5-0.2 14.1

9.8 -9.7 0.7R -59.7 1.035 0.8 1.0380.990 1.029 1.023 199035 71.4 71.6 0.4 141.9 141.2 85S-WRK_COVE 1.038 199613 L6545 199037 1.2 -6.5 6.5 71.6 93N-GLENDHU -76.6 78.0 85S-WRECK_2 199052 80.0 2.5 0.1 1.0 80.5 -1.5 1.3 72.0 3.2 -0.3

5.3 1.5 1C-TUPPER

1.036 60.0 1.032

1.030 3.4R 4.5R 199115 71.1 71.5 142.4 -76.1 L6549 77.4

11N-LAFARGE 1.1 0.3 9.6 -10.1 80.0 6.0 2.0 3.2 -0.4 28.5R 150.0 1 4.5R 199036 4.3 85S-WRECK_1

5.3-5.3 -1.6 1.033 1.2 142.5 1.6 199690 1.049 1C-TUPPER0.989 144.7 1.026 24.7 199116 70.8 16N-STEWIAKE 3.0

199054 8.4 4.9 -19.5 47C-NEW_PAGE 1.031 199692 120C-BEARHD 1.000 142.3 Bus - Voltage (kV/pu) 13.8 199691

-20.0-3.9 20.0

20.0 120C-BEARHD Branch - MW/Mvar 1.025 3.9 -2.5R Equipment - MW/Mvar 0.967 100.0%Rate A 0.4 1.050OV 0.970UV kV: <=35.000 <=69.000 <=138.000 <=230.000 <=345.000 >345.000 2021 WINTER PEAK: 2021WIN-3 - FULL WIND ON BACKBONE Total Wind Gen: 301.7 MW Gross Tupper 150.0 MW Gross Wreck Cove 160.0 MW Net NewPage Load 20.5 MW Winter Ratings Gross Lingan 480.0 MW Gross Trenton 310.0 MW Gross Gas Turbine 15.0 MW Gross NewPage Load 65.5 MW D-13 DERIVED FROM UPDATE OF 2014 SERIES MMWG 2020 WINTER PEAK Figure ___ SAT, SEP 30 2017 12:24 Gross Pt Aconi 185.0 MW Gross Tuft's Cove 250.0 MW Gross Small Hydro 177.7 MW Total BMPC Load -0.7 MW Includes 70% Distributed Generation Total Gross Gen: 2005.4 MW ML HVDC: -100.0 MW Gross Gen + ML: 1905.4 MW modeled as Negative Load: -143.0 MW 1 2018 10 Year System Outlook Report Appendix B Page 73 of 84

2017 NRIS Wind Study

Appendix E

Steady State Results

2018 10 Year System Outlook Report Appendix B Page 74 of 84 Elements Load Flow Contingencies 2021 Load Flow Cases Studied

Station Load Flow SPS Bkr line Bus Var Gen Xfmr 2021WIN (Normal) 2021WIN-1 (NSX:150MW) 2021WIN-1a (NSX:150MW) 2021WIN-2 (NSX:-100MW) 2021WIN-3 (NSX:-100MW NS-NL: 100MW) 2021SUM (Normal) 2021SUM-1 (NSX:330MW) 2021SUM-2 (NSX:-100MW) 2021SUM-3 (NSX:-100MW NS-NL: 100MW) 2021SUM-3a (NSX:-100MW NS-NL: 100MW) 2021LL (Normal) 2021LL-1 (NSX:330MW) 2021LL-2 (NSX:-100MW) x 88S, 88S-710 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 88S, 88S-711 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 88S, 88S-712 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 88S, 88S-713 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 88S, 88S-720 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 88S, 88S-721 - ok ok ok ok ok ok ok ok ok ok ok ok ok 88S x 88S, 88S-722 - ok ok ok ok ok ok ok ok ok ok ok ok ok 230kV 88S, 88S-723, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 88S, 88S-723, G8 G8 BBU ------x 88S, L-7014 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 88S, L-7021, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 88S, L-7022, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 88S, 88S-T71 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S, 101S-701, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S, 101S-702, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S, 101S-703 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S, 101S-704, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S, 101S-705, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok 101S x 101S, 101S-706, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok 230kV x 101S, 101S-711, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S, 101S-712 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S, 101S-713 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S, L-7011, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S, L-7012, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S, L-7015 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S, 101S-811 - ok ------ok ok ok 101S, 101S-812, G0 - ok ok - ok ok ok ok ok ok ok ok ok ok x 101S, 101S-812, G5 G5 CBX Lo - - ok ------101S, 101S-812, G6 G6 CBX Hi ------101S, 101S-813, G0 - ok ok - ok ok ok ok ok ok ok ok ok ok x 101S, 101S-813, G5 G5 CBX Lo - - ok ------101S, 101S-813, G6 G6 CBX Hi ------101S x 101S, 101S-814 - ok ok ok ok ok ok ok ok ok ok ok ok ok 345kV x 101S, 101S-816 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S, ML-POLE1 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S, ML-BIPOLE - ok ok ok ok ok ok ok ok ok ok ok It. Limit ok 101S, L-8004, G0 - ok ok - ok ok ok ok ok ok ok ok ok ok x 101S, L-8004, G5 G5 CBX Lo - - ok ------101S, L-8004, G6 G6 CBX Hi ------x x 101S, 101S-T81 - ok ok ok ok ok ok ok ok ok ok ok ok ok

E - 1

2018 10 Year System Outlook Report Appendix B Page 75 of 84 Elements Load Flow Contingencies 2021 Load Flow Cases Studied

Station Load Flow SPS Bkr line Bus Var Gen Xfmr 2021WIN (Normal) 2021WIN-1 (NSX:150MW) 2021WIN-1a (NSX:150MW) 2021WIN-2 (NSX:-100MW) 2021WIN-3 (NSX:-100MW NS-NL: 100MW) 2021SUM (Normal) 2021SUM-1 (NSX:330MW) 2021SUM-2 (NSX:-100MW) 2021SUM-3 (NSX:-100MW NS-NL: 100MW) 2021SUM-3a (NSX:-100MW NS-NL: 100MW) 2021LL (Normal) 2021LL-1 (NSX:330MW) 2021LL-2 (NSX:-100MW) x 2C, L-6515 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 2C, L-6516 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 2C, L-6517 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 2C, L-6518 - ok ok ok ok ok ok ok ok ok ok ok ok ok 2C 2C, L-6537, G0 - ok ok ok ok - ok ok ok ok ok ok ok ok 138kV x 2C, L-6537, G20 WC L6538 o/l - - - - ok ----- 2C, 2C-B61, G0 - ok ok ok ok - ok ok ok ok ok ok ok ok x 2C, 2C-B61, G20 WC L6538 o/l - - - - ok ------x 2C, 2C-B62 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 3C, 3C-710, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 3C, 3C-711, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 3C, 3C-712, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 3C, 3C-713, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 3C, 3C-714, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok 3C x 3C, 3C-715, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok 230kV x 3C, 3C-716, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 3C, 3C-720, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 3C, L-7003, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 3C, L-7004, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 3C, L-7005, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 3C, 3C-T71 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 1N, 1N-600 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 1N, 1N-601 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 1N, 1N-613 - ok ok ok ok ok ok ok ok ok ok ok ok ok 1N x 1N, L-6001 - ok ok ok ok ok ok ok ok ok ok ok ok ok 138kV x 1N, L-6503 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 1N, L-6513 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 1N, 1N-B61 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 1N, 1N-B62 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 67N, 67N-701, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 67N, 67N-702, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 67N, 67N-703, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 67N, 67N-704, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 67N, 67N-705, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 67N, 67N-706, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 67N, 67N-710, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok 67N x 67N, 67N-711, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok 230kV x 67N, 67N-712, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 67N, 67N-713, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 67N, L-7001 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 67N, L-7002 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 67N, L-7018 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 67N, L-7019 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 67N, 67N-T71 - ok ok ok ok ok ok ok ok ok ok ok ok ok

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2018 10 Year System Outlook Report Appendix B Page 76 of 84 Elements Load Flow Contingencies 2021 Load Flow Cases Studied

Station Load Flow SPS Bkr line Bus Var Gen Xfmr 2021WIN (Normal) 2021WIN-1 (NSX:150MW) 2021WIN-1a (NSX:150MW) 2021WIN-2 (NSX:-100MW) 2021WIN-3 (NSX:-100MW NS-NL: 100MW) 2021SUM (Normal) 2021SUM-1 (NSX:330MW) 2021SUM-2 (NSX:-100MW) 2021SUM-3 (NSX:-100MW NS-NL: 100MW) 2021SUM-3a (NSX:-100MW NS-NL: 100MW) 2021LL (Normal) 2021LL-1 (NSX:330MW) 2021LL-2 (NSX:-100MW) 67N, 67N-811, G0 - ok -- ok ok ok - ok ok ok ok ok ok x 67N, 67N-811, G5 G5 ONI Lo - ok ok --- ok ------67N, 67N-811, G6 G5 ONI Hi ------x 67N, 67N-812 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 67N, 67N-813 - ok ok ok ok ok ok ok ok ok ok ok ok ok 67N, 67N-814, G0 - ok -- ok ok ok - ok ok ok ok - ok x 67N, 67N-814, NSX1 G9 NSX Lo - ok ok ------67N, 67N-814, NSX2 G9 NSX Hi ------ok - - - - It. Limit - 67N, 67N-815, G0 - ok -- ok ok ok - ok ok ok ok - ok 67N x 67N, 67N-815, NSX1 G9 NSX Lo - ok ok ------345kV 67N, 67N-815, NSX2 G9 NSX Hi ------ok - - - - It. Limit - 67N, 67N-816, G0 - ok -- ok ok ok - ok ok ok ok ok ok x 67N, 67N-816, G5 G5 ONI Lo - ok ok --- ok ------67N, 67N-816, G6 G6 ONI Hi ------67N, L-8001, G0 - ok -- ok ok ok - ok ok ok ok - ok x 67N, L-8001, G5 G9 NSX Lo - ok ok ------67N, L-8001, G6 G9 NSX Hi ------ok - - - - It. Limit - x 67N, L-8002 - ok ok ok ok ok ok ok ok ok ok ok ok ok x x 67N, 67N-T81 - ok ok ok ok ok ok ok ok ok ok ok ok ok 79N, 79N-601 - ok ok - ok ok ok ok ok ok ok ok ok ok x 79N, 79N-601, G5 G5 CBX Lo - - ok ------79N, 79N-601, G6 G6 CBX Hi ------79N 79N, 79N-606 - ok ok - ok ok ok ok ok ok ok ok ok ok 138kV x 79N, 79N-606, G5 G5 CBX Lo - - ok ------79N, 79N-606, G6 G6 CBX Hi ------x 79N, L-6507 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 79N, L-6508 - ok ok ok ok ok ok ok ok ok ok ok ok ok 79N, 79N-803, G0 - ok ok - ok ok ok ok ok ok ok ok ok ok x 79N, 79N-803, G5 G5 CBX Lo - - ok ------79N, 79N-803, G6 G6 CBX Hi ------79N, 79N-810, G0 - ok ok - ok ok ok ok ok ok ok ok ok ok x 79N, 79N-810, G5 G5 CBX Lo - - ok ------79N 79N, 79N-810, G6 G6 CBX Hi ------345kV 79N, L-8003, G0 - ok -- ok ok ok - ok ok ok ok ok ok x 79N, L-8003, G5 G5 ONI Lo - ok ok --- ok ------79N, L-8003, G6 G6 ONI Hi ------79N, 79N-T81, G0 - ok ok - ok ok ok ok ok ok ok ok ok ok x x 79N, 79N-T81, G5 G5 CBX Lo - - ok ------79N, 79N-T81, G6 G6 CBX Hi ------x 91N, 91N-701 - ok ok ok ok ok ok ok ok ok ok ok ok ok 91N x 91N, 91N-702 - ok ok ok ok ok ok ok ok ok ok ok ok ok 230kV x 91N, 91N-703 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 91N, 91N-B71 - ok ok ok ok ok ok ok ok ok ok ok ok ok

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2018 10 Year System Outlook Report Appendix B Page 77 of 84 Elements Load Flow Contingencies 2021 Load Flow Cases Studied

Station Load Flow SPS Bkr line Bus Var Gen Xfmr 2021WIN (Normal) 2021WIN-1 (NSX:150MW) 2021WIN-1a (NSX:150MW) 2021WIN-2 (NSX:-100MW) 2021WIN-3 (NSX:-100MW NS-NL:100MW) 2021SUM (Normal) 2021SUM-1 (NSX:330MW) 2021SUM-2 (NSX:-100MW) 2021SUM-3 (NSX:-100MW NS-NL:100MW) 2021SUM-3a (NSX:-100MW NS-NL:100MW) 2021LL (Normal) 2021LL-1 (NSX:330MW) 2021LL-2 (NSX:-100MW) x DCT, L-6507][L-6508 - ok ok ok ok ok ok ok ok ok ok ok ok ok x DCT, L-6534][L-7021 - ok ok ok ok ok ok ok ok ok ok ok ok ok DCT, L-7003][L-7004, G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok DCT x DCT, L-7003][L-7004, G3 G4 BBU 1 ------x DCT, L-7008][L-7009 - ok ok ok ok ok ok ok ok ok ok ok ok ok x DCT, L-7009][L-8002 - ok ok ok ok ok ok ok ok ok ok ok ok ok

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2018 10 Year System Outlook Report Appendix B Page 78 of 84

2017 NRIS Wind Study

Appendix F

Stability Results

2018 10 Year System Outlook Report Appendix B Page 79 of 84 2016 BPS/BES Elements 2021 Dynamics Contingencies Contingencies Studied

Station Dynamics SPS Bkr Var line Bus Gen Xfmr 2021WIN (Normal) 2021WIN-1 (NSX:150MW) 2021WIN-1a (NSX:150MW) 2021WIN-2 (NSX:-100MW) 2021WIN-3 (NSX:-100MW) 2021SUM (NSX:0MW, NLX: 475MW) 2021SUM-1 (NSX:330MW, NLX: 475MW) 2021SUM-2 (NSX:-100MW, NLX: 475MW) 2021SUM-3 (NSX:-100MW, NLX: -100MW) 2021SUM-3a (NSX:-100MW, NLX: -100MW) 2021LL (NSX: 0MW, NLX: 475MW) 2021LL-1 (NSX:330MW, NLX: 475MW) 2021LL-2 (NSX:-100MW, NLX: -100MW) x 88S BBU 88S-713 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 88S BBU 88S-720 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 88S BBU 88S-721 - ok ok ok ok ok ok ok ok ok ok ok ok ok 88S x 88S BBU 88S-722 - ok ok ok ok ok ok ok ok ok ok ok ok ok 230kV x 88S BBU 88S-723 G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 88S L7014 3PH Fault - ok ok ok ok ok ok ok ok ok ok ok ok ok x 88S L7021 3PH Fault - ok ok ok ok ok ok ok ok ok ok ok ok ok x 88S L7022 3PH Fault - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S BBU 101S-701 G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S BBU 101S-702 G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S BBU 101S-706 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S BBU 101S-712 - ok ok ok ok ok ok ok ok ok ok ok ok ok 101S x 101S L7011 3PH Fault G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok 230kV x 101S L7012 3PH Fault G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S L7014 3PH Fault - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S L7021 3PH Fault - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S L7022 3PH Fault - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S BBU 101S-811 - ok ok ok ok ok ok ok ok ok ok ok ok ok 101S BBU 101S-812 G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S BBU 101S-812 G5 G5 CBX Lo ------101S BBU 101S-812 G6 G6 CBX Hi ------101S BBU 101S-813 G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok 101S x 101S BBU 101S-813 G5 G5 CBX Lo ------345kV 101S BBU 101S-813 G6 G6 CBX Hi ------x 101S, MLBIPOLE - ok ok ok ok ok ok ok ok ok ok ok ok ok 101S L8004 3PH Fault G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 101S L8004 3PH Fault G5 G5 CBX Lo ------101S L8004 3PH Fault G6 G6 CBX Hi ------2C 138kV x 2C BUS 2C-B62 3PH Fault - ok ok ok ok ok ok ok ok ok ok ok ok ok x 3C BBU 3C-711 G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok 3C x 3C BBU 3C-715 G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok 230kV x 3C L7005 3PH Fault G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 3C L7012 3PH Fault G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 1N BKR 1N-600 1P - ok ok ok ok ok ok ok ok ok ok ok ok ok x 1N BKR 1N-601 - ok ok ok ok ok ok ok ok ok ok ok ok ok 1N x 1N BBU 1N-613 - ok ok ok ok ok ok ok ok ok ok ok ok ok 138kV x 1N L6001 3PH Fault - ok ok ok ok ok ok ok ok ok ok ok ok ok x 1N L6503 3PH Fault - ok ok ok ok ok ok ok ok ok ok ok ok ok x 1N L6513 3PH Fault - ok ok ok ok ok ok ok ok ok ok ok ok ok

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2018 10 Year System Outlook Report Appendix B Page 80 of 84 2016 BPS/BES Elements 2021 Dynamics Contingencies Contingencies Studied

Station Dynamics SPS Bkr Var line Bus Gen Xfmr 2021WIN (Normal) 2021WIN-1 (NSX:150MW) 2021WIN-1a (NSX:150MW) 2021WIN-2 (NSX:-100MW) 2021WIN-3 (NSX:-100MW) 2021SUM (NSX:0MW, NLX: 475MW) 2021SUM-1 (NSX:330MW, NLX: 475MW) 2021SUM-2 (NSX:-100MW, NLX: 475MW) 2021SUM-3 (NSX:-100MW, NLX: -100MW) 2021SUM-3a (NSX:-100MW, NLX: -100MW) 2021LL (NSX: 0MW, NLX: 475MW) 2021LL-1 (NSX:330MW, NLX: 475MW) 2021LL-2 (NSX:-100MW, NLX: -100MW) x 67N BBU 67N-711 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 67N BBU 67N-712 - ok ok ok ok ok ok ok ok ok ok ok ok ok 67N x 67N BBU 67N-713 - ok ok ok ok ok ok ok ok ok ok ok ok ok 230kV x 67N L7005 3PH Fault G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok 67N BBU 67N-811 G0 - ok -- ok ok ok - ok ok ok ok ok ok x 67N L7005 3PH Fault G3 - - ok ok ------67N BBU 67N-811 G5 G5 ONI Lo - ok ok --- ok ------x 67N L7018 3PH Fault - ok ok ok ok ok ok ok ok ok ok ok ok ok 67N BBU 67N-811 G6 G5 ONI Hi ------x 67N BBU 67N-813 - ok ok ok ok ok ok ok ok ok ok ok ok ok 67N BBU 67N-814 G0 - ok -- ok ok ok - ok ok ok ok - ok x 67N BBU 67N-814 NSX1 G9 NSX Lo - ok ok ------67N BBU 67N-814 NSX2 G9 NSX Hi ------ok ---- ok - 67N 67N L8001 3PH Fault G0 - ok -- ok ok ok - ok ok ok ok - ok 345kV 67N L8001 3PH Fault NSX1 G9 NSX Lo - ok ok ------x 67N L8001 3PH Fault NSX2 G9 NSX Hi ------ok ---- ok - 67N L8001 3PH Fault NSI G10 NSI ------x 67N L8002 3PH Fault - ok ok ok ok ok ok ok ok ok ok ok ok ok 67N L8003 3PH Fault G0 - ok -- ok ok ok - ok ok ok ok ok ok x 67N L8003 3PH Fault G5 G5 ONI Lo - ok ok --- ok ------67N L8003 3PH Fault G6 G6 ONI Hi ------79N BBU 79N-601 G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok 79N x 79N BBU 79N-601 G5 G5 CBX Lo ------138kV 79N BBU 79N-601 G6 G6 CBX Hi ------x 79N L6507 3PH Fault - ok ok ok ok ok ok ok ok ok ok ok ok ok 79N BBU 79N-803 G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 79N BBU 79N-803 G5 G5 CBX Lo ------79N BBU 79N-803 G6 G6 CBX Hi ------79N BBU 79N-810 G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 79N BBU 79N-810 G5 G5 CBX Lo ------79N BBU 79N-810 G6 G6 CBX Hi ------79N L8003 3PH Fault G0 - ok -- ok ok ok - ok ok ok ok ok ok 79N x 79N L8003 3PH Fault G5 G5 ONI Lo - ok ok --- ok ------345kV 79N L8003 3PH Fault G6 G6 ONI Hi ------79N L8004 3PH Fault G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 79N L8004 3PH Fault G5 G5 CBX Lo ------79N L8004 3PH Fault G6 G6 CBX Hi ------79N T81 HV Fault G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 79N T81 HV Fault G5 G5 CBX Lo ------79N T81 HV Fault G6 G6 CBX Hi ------

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2018 10 Year System Outlook Report Appendix B Page 81 of 84 2016 BPS/BES Elements 2021 Dynamics Contingencies Contingencies Studied

Station Dynamics SPS Bkr Var line Bus Gen Xfmr 2021WIN (Normal) 2021WIN-1 (NSX:150MW) 2021WIN-1a (NSX:150MW) 2021WIN-2 (NSX:-100MW) 2021WIN-3 (NSX:-100MW) 2021SUM (NSX:0MW, NLX:475MW) 2021SUM-1 (NSX:330MW, NLX:475MW) 2021SUM-2 (NSX:-100MW, NLX:475MW) 2021SUM-3 (NSX:-100MW, NLX:-100MW) 2021SUM-3a (NSX:-100MW, NLX:-100MW) 2021LL (NSX:0MW, NLX:475MW) 2021LL-1 (NSX:330MW, NLX:475MW) 2021LL-2 (NSX:-100MW, NLX:-100MW) x DCT L6507][L6508 79N - ok ok ok ok ok ok ok ok ok ok ok ok ok x DCT L6534][L7021 - ok ok ok ok ok ok ok ok ok ok ok ok ok Dbl Cct x DCT L7003][L7004 G0 - ok ok ok ok ok ok ok ok ok ok ok ok ok TOWERS x DCT L7008][L7009 - ok ok ok ok ok ok ok ok ok ok ok ok ok x DCT L7009][L8002 - ok ok ok ok ok ok ok ok ok ok ok ok ok x 410N L3006 3PH Fault - ok ok ok ok ok ok ok ok ok ok ok ok ok NB 410N x 410N L8001 3PH Fault - ok ok ok ok ok ok ok ok ok ok ok ok ok

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2018 10 Year System Outlook Report Appendix B Page 82 of 84

2017 NRIS Wind Study

Appendix G

Stability Results 2021LL Cases

2018 10 Year System Outlook Report Appendix B Page 83 of 84

2017 NRIS Wind Study

Appendix H

Stability Results 2021SUM Cases

2018 10 Year System Outlook Report Appendix B Page 84 of 84

2017 NRIS Wind Study

Appendix I

Stability Results 2021WIN Cases