Nova Scotia Utility and Review Board
IN THE MATTER OF The Public Utilities Act, R.S.N.S. 1989, c.380, as amended
2020 10-Year System Outlook
NS Power
June 30, 2020
NON-CONFIDENTIAL
2020 10-Year System Outlook NON-CONFIDENTIAL
1 TABLE OF CONTENTS 2 3 1.0 INTRODUCTION ...... 5 4 2.0 LOAD FORECAST ...... 7 5 3.0 GENERATION RESOURCES ...... 11 6 3.1 Existing Generation Resources ...... 11 7 3.1.1 Maximum Unit Capacity Rating Adjustments ...... 13 8 3.1.2 Mersey Hydro ...... 14 9 3.1.3 Wreck Cove Hydro ...... 14 10 3.2 Changes in Capacity ...... 15 11 3.2.1 Tusket Combustion Turbine ...... 15 12 3.2.2 Victoria Junction Combustion Turbine ...... 16 13 3.2.3 Annapolis Tidal ...... 16 14 3.3 Unit Utilization & Investment Strategy ...... 17 15 3.3.1 Evolution of the Energy Mix in Nova Scotia ...... 17 16 3.3.2 Projections of Unit Utilization ...... 19 17 3.3.3 Steam Fleet Retirement Outlook ...... 20 18 4.0 NEW SUPPLY SIDE FACILITIES ...... 21 19 5.0 QUEUED SYSTEM IMPACT STUDIES ...... 22 20 5.1 OATT Transmission Service Queue ...... 23 21 6.0 ENVIRONMENTAL AND EMISSIONS REGULATORY REQUIREMENTS ...... 25 22 6.1 Renewable Electricity Requirements ...... 25 23 6.2 Environmental Regulatory Requirements ...... 28 24 6.3 Upcoming Policy Changes ...... 32 25 7.0 RESOURCE ADEQUACY ...... 33 26 7.1 Operating Reserve Criteria...... 33 27 7.2 Planning Reserve Criteria ...... 34 28 7.3 Capacity Contribution of Renewable Resources in Nova Scotia ...... 36 29 7.3.1 Energy Resource Interconnection Service Connected Resources ...... 37 30 7.4 Load and Resources Review ...... 38 31 8.0 TRANSMISSION PLANNING ...... 41
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32 8.1 System Description ...... 41 33 8.2 Transmission Design Criteria ...... 42 34 8.2.1 Bulk Power System (BPS) ...... 43 35 8.2.2 Bulk Electric System (BES) ...... 43 36 8.2.3 Special Protection Systems (SPS) ...... 44 37 8.2.4 NPCC A-10 Standard Update ...... 44 38 8.3 Transmission Life Extension ...... 46 39 8.4 Transmission Project Approval ...... 46 40 8.5 New Large load Customer Interconnection Requests ...... 47 41 8.6 Wind Integration Stability Study - PSC ...... 48 42 9.0 TRANSMISSION DEVELOPMENT 2020 to 2030 ...... 51 43 9.1 Impact of Proposed Load Facilities ...... 51 44 9.2 129H-Kearney Lake Relocation ...... 52 45 9.3 Transmission Development Plans ...... 52 46 9.4 Western Valley Transmission System – Phase II Study ...... 55 47 10.0 PANDEMIC RESPONSE ...... 56 48 11.0 CONCLUSION ...... 57 49
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1 TABLE OF FIGURES 2 3 Figure 1: Net System Requirement with Future DSM Program Effects (actuals are not weather adjusted) 8 4 Figure 2: Coincident Peak Demand with Future DSM Program Effects ...... 9 5 Figure 3: 2020 Firm Generating Capability for NS Power and IPPs ...... 12 6 Figure 4: Firm Capacity Changes & DSM ...... 15 7 Figure 5: 2005, 2019 Actual, 2021 Forecast Energy Mix ...... 18 8 Figure 6: Peak System Demand Trend ...... 19 9 Figure 7: Combined Transmission & Distribution Advanced Stage Interconnection Queue as of June 17, 10 2020 ...... 22 11 Figure 8: Requests in the OATT Transmission Queue ...... 23 12 Figure 9: RES Compliance Forecast ...... 27 13 Figure 10: Multi-year Greenhouse Gas Emission Limits ...... 28 14 Figure 11: Greenhouse Gas Free Allowances 2019-2022...... 29 15 Figure 12: Emissions (SO2, NOx, Hg) ...... 31 16 Figure 13: NS Power 10 Year Load and Resources Outlook ...... 40 17 Figure 14: NS Power Major Facilities in Service 2020 ...... 41 18
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1 1.0 INTRODUCTION 2 3 In accordance with the 3.4.2.11 Market Rule requirements, this Report provides the 10- 4 Year System Outlook on behalf of the Nova Scotia Power System Operator (NSPSO) for 5 2020. 6 7 The 2020 10-Year System Outlook Report contains the following information: 8 9 • A summary of the Nova Scotia Power Incorporated (NS Power, Company) load 10 forecast and update on the Demand Side Management (DSM) forecast in Section 11 2. 12 13 • A summary of generation expansion anticipated for facilities owned by NS Power 14 and others in Sections 3-5. NS Power’s generation planning for existing Facilities, 15 including retirements as well as investments in upgrades, refurbishment or life 16 extension and new Generating Facilities committed in accordance with previously 17 approved NSPSO system plans. 18 19 • A summary of environmental and emissions regulatory requirements, as well as 20 forecast compliance in Section 6. This Section also includes projections of the 21 level of renewable energy available. 22 23 • A Resource Adequacy Assessment in Section 7. 24 25 • A discussion of transmission planning considerations in Section 8.
1 Nova Scotia Wholesale and Renewable to Retail Electricity Market Rules (as amended 2016 06 10), Market Rule 3.4.2 states, “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 2 • Identification of transmission-related capital projects currently in the 3 Transmission Development Plan in Section 9. 4 5 • A discussion of NS Power’s ongoing COVID-19 pandemic response in Section 6 10. 7 8 Since the 2018 10-Year System Outlook (10YSO) – Integrated Resource Plan (IRP) 9 Action Plan Update, and following the completion of the Generation Utilization and 10 Optimization process, in its letter dated October 5, 20182 the Nova Scotia Utility and 11 Review Board (NSUARB) directed NS Power to undertake an IRP process to be 12 completed in 2020 and outlined several pre-IRP analyses. NS Power has completed the 13 pre-IRP deliverables and is currently undertaking the IRP analysis including workshops 14 with interested participants and is on track to complete the IRP process in 2020. 15 16 As discussed in Section 7.4, the 2020 IRP will evaluate a robust set of future planning 17 scenarios, with modeling assumptions that were created with comprehensive stakeholder 18 input. The 2020 IRP will document capacity expansion/retirement modeling optimization 19 results and associated insights over a 25-year planning horizon (2021-2045). 20 21 As discussed in Section 10, NS Power continues to monitor the ongoing spread of 22 COVID-19 and remains focused on the health and safety of employees, consultants, 23 contractors, and their families. A response team is monitoring the situation, coordinating 24 with authorities, and keeping employees informed via regular business updates. The 25 economic effects of the COVID-19 pandemic and their impact on short and medium-term 26 system planning continue to be evaluated. 27
2 M08059, UARB letter, Generation Utilization and Optimization, October 5, 2018.
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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 customers in the province. The load forecast forms the basis for fuel 5 supply planning, investment planning, and overall operating activities of NS Power. The 6 figures presented in this Report are the same as those filed with the NSUARB in the 2020 7 Load Forecast Report on May 6, 2020 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 the Net System 12 Requirement (NSR). 13 14 Figure 1 shows historical and forecast NSR which includes in-province energy sales plus 15 system losses. Anticipated growth is expected to be driven by increased electric heating 16 in the residential sector as well as industrial growth. This growth will be offset by DSM 17 initiatives and natural energy efficiency improvements outside of structured DSM 18 programs, as well as increased behind-the-meter small scale solar installations. The net 19 result of these inputs is an annual decline of 0.1 percent in NSR compared to a peak 20 demand forecast that remains flat.
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1 Figure 1: Net System Requirement with Future DSM Program Effects (actuals are 2 not weather adjusted) NSR Growth Year (GWh) (%) 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 11,099 0.6 2016 10,809 -2.6 2017 10,873 0.6 2018 11,250 3.5 2019 11,077 -1.5 2020* 11,049 -0.3 2021* 11,081 0.3 2022* 11,134 0.5 2023* 11,176 0.4 2024* 11,228 0.5 2025* 11,185 -0.4 2026* 11,167 -0.2 2027* 11,124 -0.4 2028* 11,096 -0.2 2029* 11,015 -0.7 2030* 10,949 -0.6 3 *Forecast value 4 5 NS Power also forecasts the peak hourly demand for future years. The total system peak 6 is defined as the highest single hourly average demand experienced in a year. It includes 7 both firm and interruptible loads. Due to the weather-sensitive load component in Nova 8 Scotia, the total system peak occurs in the period from December through February.
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1 The peak demand forecast is developed using end-use energy forecasts combined with 2 peak-day weather conditions to generate monthly peak demand forecasts through an 3 estimated monthly peak demand regression model. The peak contribution from large 4 customer classes is calculated from historical coincident load factors for each of the rate 5 classes. AMI-enabled savings of 34 MW are included from 2022 onward. After 6 accounting for the effects of DSM savings, system peak is expected to remain essentially 7 flat on average over the forecast period. 8 9 Figure 2 shows the historical and forecast net system peak. 10 11 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) (%) 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 80 1,993 2,073 2.7 2019 111 1,949 2,060 -0.6 2020* 147 2,098 2,245 8.9 2021* 152 2,085 2,237 -0.3 2022* 159 2,053 2,212 -1.1 2023* 161 2,059 2,220 0.3 2024* 166 2,064 2,230 0.4 2025* 166 2,070 2,236 0.3 2026* 165 2,074 2,240 0.2 2027* 165 2,075 2,240 0.0 2028* 165 2,075 2,240 0.0 2029* 165 2,076 2,240 0.0 2030* 164 2,076 2,240 0.0 12 *Forecast value
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1 As with any forecast, there is a degree of uncertainty around actual future outcomes. In 2 electricity forecasting, much of this uncertainty is due to the impact of variations in 3 weather, energy efficiency program effectiveness, the health of the economy, government 4 policy regarding decarbonization, the impact of electrification, changes in large customer 5 loads, the number of electric appliances and end-use equipment installed, and changes in 6 technology.
7 Other assumptions, including Distributed Energy Resources, the impacts of electrification 8 to enable deep decarbonization, and nearer term effects such as the potential effect of the 9 COVID-19 pandemic on load, are factors being considered in the 2020 IRP.
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1 3.0 GENERATION RESOURCES 2 3 3.1 Existing Generation Resources 4 5 NS Power’s generation portfolio is composed of a mix of fuel and technology types that 6 include coal, petroleum coke, light and heavy oil, natural gas, biomass, wind, tidal and 7 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 Standards 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 these variable resources provide less firm capacity than conventional generation 13 resources. Therefore, the majority of the system requirement for firm capacity is met 14 with NS Power’s conventional units (e.g. coal, gas) while their energy output is being 15 displaced by renewable resources when they are producing energy. This is discussed 16 further in Section 3.3 below. 17 18 Figure 3 lists NS Power’s and IPPs’ verified and forecast firm generating capability for 19 generating stations/systems along with their fuel types up to the filing date of this Report. 20 The changes and additions over the 10 year period to this total capacity are shown in 21 Figure 13 in Section 7.4. 22
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1 Figure 3: 2020 Firm Generating Capability for NS Power and IPPs
Winter Net Plant/System Fuel Type Capacity3 (MW) Avon Hydro 6.4 Black River Hydro 21.4 Lequille System Hydro 23.0 Bear River System Hydro 35.5 Tusket Hydro 2.3 Mersey System Hydro 40.4 St. Margaret’s Bay Hydro 10.3 Sheet Harbour Hydro 10.2 Dickie Brook Hydro 3.6 Wreck Cove Hydro 201.4 Annapolis Tidal4 Hydro 0.0 Fall River Hydro 0.5 Total Hydro 354.9 Tufts Cove 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 607 Coal/Pet Coke & Limestone Point Aconi 168 Sorbent (CFB) Total Steam 1547 Tufts Cove Units 4, 5 & 6 Natural Gas 144 Total Combined Cycle 144 Burnside Light Fuel Oil 132 Tusket5 Light Fuel Oil 0 Victoria Junction6 Light Fuel Oil 33
3 Wind and Hydro are Effective Load Carrying Capability (ELCC) values. Please refer to Section 7.3 for further information. 4 Annapolis assumed to be out of service. Please refer to Section 3.2.3. 5 Tusket CT assumed to be in service by winter 2020-2021. Please refer to Section 3.2.1. 6 As the UARB declined approval of the VJ2 CT Capital Item, the asset has been removed from NS Power’s listing of Firm Generating Capability. For the purposes of this Report the Company has not forecast the firm capacity provided by VJ2 CT. Please refer to Section 3.2.2.
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Winter Net Plant/System Fuel Type Capacity3 (MW) Total Combustion Turbine 165 Independent Power Producers Pre-2001 Renewables 25.8 (IPPs) Post-2001Renewables (firm)7 IPPs 70.6 NS Power wind (firm) 7 Wind 15.3 Community Feed-in Tariff IPPs 34.7 (firm)7 Total IPPs & Renewables 146.4 Total Capacity 2357 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.8 Since 2016, there has been a staged transition from Directory #9 to the 8 requirements of NERC Standard MOD-025-2 Verification and Data Reporting of 9 Generator Real and Reactive Power Capability and Synchronous Condenser Reactive 10 Power Capability. NPCC Directory #9 was retired in October 2019 and NERC MOD- 11 025-2 will provide the ongoing criteria for generator verification and data reporting. 12 13 The Net Operating Capacity of the thermal units and large hydro units covered by the 14 NPCC criteria do not require adjustments at this point. NS Power will continue to refresh 15 unit maximum capacities in the 10-Year System Outlook each year as operational 16 conditions change. 17
7 Energy Resource Interconnection Service (ERIS) and Network Resource Interconnection Service (NRIS) wind projects are assumed to have a firm capacity contribution of 19% as detailed in Section 7.3.1. 8 https://www.npcc.org/Standards/Directories/Forms/Public%20List.aspx
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1 3.1.2 Mersey Hydro 2 3 NS Power continues to assess options to address current concerns on the Mersey Hydro 4 System. Degradation of the powerhouses and water control structures after nearly a 5 century of service has necessitated the need for significant redevelopment work. The 6 Mersey Hydro System is an important part of NS Power’s hydro assets and is responsible 7 for approximately 25 percent of annual domestic hydroelectric production. The 8 Company is preparing a capital application for the redevelopment of the Mersey system 9 for filing with the NSUARB. Further, the 2020 IRP will conduct an economic screening 10 analysis of NS Power’s hydro assets, which will inform candidate economic retirement 11 options in the full IRP Model. This analysis includes the Mersey Hydro System. 12 13 3.1.3 Wreck Cove Hydro 14 15 Wreck Cove Hydro is an important asset for NS Power, providing critical and renewable 16 generation for peak demand periods. With the ability to quickly provide 212 MW of peak 17 capacity from two operating units and average annual generation of 300 GWh, Wreck 18 Cove is NS Power’s largest hydroelectric system. NS Power has submitted a capital 19 application to the NSUARB to perform Life Extension & Modernization (LEM) work for 20 the Wreck Cove Generating Station.9 As part of the scope for the LEM Project, the two 21 unit turbines will be replaced with newly designed turbine runners which will have 22 increased efficiency and a wider operating range over the existing ones. While the change 23 in turbine runners will not change the peak capacity of 212 MW, it will provide a forecast 24 increase of 5 percent to the annual generation from Wreck Cove. If approved, this project 25 will bring the average annual generation at Wreck Cove to 315 GWh per year.
9 M09596, NS Power Wreck Cove Life Extension and Modernization – Unit Rehabilitation and Replacement, CI 13838, February 28, 2020.
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1 3.2 Changes in Capacity 2 3 Figure 4 provides the firm Supply and DSM capacity changes in accordance with the 4 assumption set developed for the 2020 IRP and the 2020 Load Forecast. 5 6 Figure 4: Firm Capacity Changes & DSM New Resources 2020-2029 Net MW DSM Peak reduction 298
Total Demand Side MW Change 298 Projected Over Planning Period
Biomass 43 Tusket CT return to service 33 Maritime Link Import - Base Block 153 Assumed Unit Retirements/Lay-ups10 -148 Tidal Feed-in Tariff (Firm capacity) 2 Total Firm Supply MW Change 83 Projected Over Planning Period 7 8 3.2.1 Tusket Combustion Turbine 9 10 On September 13, 2019, the NSUARB issued its decision to approve the Tusket CT 11 replacement.11 Based on this approval, Tusket CT capacity has been included in this 12 year’s 10-Year System Outlook Report. Tusket CT is expected back in service prior to 13 the end of 2020. As directed by the Board, the 2020 IRP is conducting further analysis on 14 NS Power’s diesel CTs.
10 Retirement of Lingan 2 unit once the Maritime Link Base Block provides firm capacity service. 11 M08812, NSUARB Tusket CT Generator Replacement Decision, CI 51526, September 13, 2019.
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1 3.2.2 Victoria Junction Combustion Turbine 2 3 On March 23, 2020, the NSUARB issued its decision12 to decline approval of the capital 4 work related to VJ2 at this time. The NSUARB stated: 5 6 NS Power may re-apply following the completion of the review of 7 existing CT (oil) resources during the 2020 IRP proceeding or after a 8 comprehensive alternate analysis of all the Company’s oil CTs has been 9 completed.
10 11 Given that the NSUARB has not approved the capital work related to VJ2, for the 12 purposes of this Report, the Company has not forecast the firm capacity provided by VJ2 13 CT. Further analysis of NS Power’s diesel CTs will be undertaken during the 2020 IRP 14 process. 15 16 3.2.3 Annapolis Tidal 17 18 A critical component of the Annapolis Tidal facility has failed, and the site is now 19 offline. NS Power has been assessing the future options for this facility. Work to bring 20 the site online has been put on hold until a final decision related to the future of 21 Annapolis is reached. For the purposes of this report, NS Power has not assumed 22 capacity contribution from this facility.
12 M09560, UARB letter to NS Power re Approval of 2020 Capital Work Order (P-520), March 23, 2020
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1 3.3 Unit Utilization & Investment Strategy 2 3 The Company typically forecasts 10 years of utilization and investment projections in this 4 Report. There are many operational realities, such as the prices of fuel and power or 5 changes in policy, that could trigger a significant shift in the utilization forecast to 6 provide the most economic system dispatch for customers. 7 8 This utility utilization and investment strategy (UUIS) is a product of generation planning 9 and engineering integrating the latest in Asset Management methodology and generation 10 planning techniques in the service of a complex generation operation. It provides an 11 outlook for how NS Power will operate and invest in generation assets, recognizing the 12 trend toward lower utilization along with demands for flexible operation arising from 13 renewables integration, and will continue to be updated annually in the 10YSO in future. 14 As part of the 2020 IRP process, modeling assumptions have been developed in 15 consultation with interested parties. The UUIS analysis has been deferred to the IRP 16 which will be completed later this year. 17 18 3.3.1 Evolution of the Energy Mix in Nova Scotia 19 20 NS Power’s energy production mix has undergone significant changes over the last 15 21 years. Since the implementation of the Renewable Electricity Standards (RES), an 22 increased percentage of energy sales is produced by variable renewable resources such as 23 wind. However, due to their intermittent nature, variable resources provide less firm 24 capacity than conventional generation resources. Therefore, the majority of the system 25 requirement for firm capacity and other ancillary services is met with NS Power’s 26 conventional units (i.e. coal, gas, diesel, hydro) as discussed in Sections 3.1 and 3.2, 27 while the energy output of conventional units is being displaced by renewable resources. 28 Figure 5 below illustrates this change with the actual energy mix from 2005 and 2019 and 29 the 2019 10YSO forecast energy mix for 2021. The IRP process will provide further 30 guidance on the potential energy mix under the robust set of scenarios developed.
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1 Figure 513: 2005, 2019 Actual, 2021 Forecast Energy Mix
2 3 4 As illustrated in Figure 6, NS Power’s firm peak demand has been increasing at a rate of 5 approximately 1 percent per year. After accounting for the effects of DSM savings, the 6 system peak is expected to remain essentially flat on average over the forecast period. 7 Future growth is expected to be mitigated through DSM, AMI-enabled peak reduction 8 strategies, and underlying efficiency improvements. While energy is increasingly being 9 produced by new renewable sources, the capacity required to serve system demand will 10 continue to be served by dispatchable conventional resources together with firm imports. 11 These resources also provide other critical services to the system such as load following.
13 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 Figure 6: Peak System Demand Trend
2 3 4 3.3.2 Projections of Unit Utilization 5 6 NS Power typically prepares a 10-year forecast of projected unit utilization parameters 7 annually in this Report using the Plexos modeling tool and the current assumptions 8 regarding fuel and market prices, load forecast, system constraints, and generating 9 parameters; these assumptions change year over year and the Company adjusts its 10 utilization strategy accordingly. 11 12 The ongoing IRP will provide a more in-depth analysis on unit utilization and as such, 13 this Section will be deferred to the 2020 IRP Report which will be completed this year.
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1 3.3.3 Steam Fleet Retirement Outlook 2 3 In light of federal and provincial requirements for the province to lower its GHG 4 emissions, NS Power will need to decrease its reliance on fossil fuels energy sources. As 5 part of the 2018 Generation Utilization and Optimization process and the current IRP 6 process, NS Power is looking at its thermal fleet and considering retirements for 7 individual units. 8 9 As part of the 2020 IRP NS Power is analyzing updated retirement schedules and the 10 forecast major investment intervals for the units, as well as incorporating the conclusions 11 of the equivalency agreement negotiations for the Federal Coal-fired Generation of 12 Electricity Regulations (as noted in Section 6.3). In the interim, Lingan Unit 2 is planned 13 for retirement following the commencement of the delivery of the Nova Scotia Block of 14 energy and related firm capacity from the Muskrat Falls.
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1 4.0 NEW SUPPLY SIDE FACILITIES 2 3 As of June 17, 2020, NS Power has four Active Transmission Connected Interconnection 4 Requests (67.88 MW) and five Active Distribution Connected Interconnection Requests 5 (9.1 MW) at various stages of interconnection study. The Advanced Stage 6 Interconnection Request Queue is described in Section 5. 7 8 Proponents of transmission projects request Network Resource Interconnection Service 9 (NRIS) or Energy Resource Interconnection Service (ERIS). NRIS refers to a firm 10 transmission interconnection request with the potential requirement for transmission 11 reinforcement upon completion of the System Impact Study (SIS). ERIS refers to an 12 interconnection request for firm service only to the point where transmission 13 reinforcement would be required. Results of the transmission interconnection studies 14 assessing the transmission reinforcement required to support transmission projects will be 15 incorporated into future transmission plans. 16 17 Distribution projects do not receive an NRIS or ERIS designation.
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1 5.0 QUEUED SYSTEM IMPACT STUDIES 2 3 Figure 7 below provides the current combined Transmission and Distribution Advanced 4 State Interconnection Queue. 5 6 Figure 7: Combined Transmission & Distribution Advanced Stage Interconnection 7 Queue as of June 17, 2020 In- Request Service Date Inter- Queue MW MW date Service IR# DD- County connection Type Status Order Summer Winter DD- Type MMM- Point MMM- YY YY 27-Jul- 01-Sep- GIA 1-T 426 Richmond 45.0 45.0 47C Biomass NRIS 12 18 Executed 5-Dec- Cumberla 31-May- GIA 2-T 516 5.0 5.0 37N Tidal NRIS 14 nd 20 Executed 28-Jul- 31-Oct- GIA 3-T 540 Hants 14.1 14.1 17V Wind NRIS 16 23 Executed 26-Sep- Cumberla 01-Nov- GIA 4-T 542 3.78 3.78 37N Tidal NRIS 16 nd 21 Executed 19-Apr- 01-Sep- SIS 5-D 557 Halifax 5.6 5.6 CHP N/A 17 18 Complete 26-Jul- 31-May- GIA in 6-D 569 Digby 0.6 0.6 509V-302 Tidal N/A 19 21 Progress 21-May- Cumberla 15-Jun- GIA in 7-D 568 2.0 2.0 22N-404 Solar N/A 19 nd 21 Progress 16-Jan- 30-Nov- SIS in 8-D 566 Digby 0.7 0.7 509V-301 Tidal N/A 19 20 Progress 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 7 above provides the location 13 and size of the generating facilities currently in the Combined T&D Advanced Stage 14 Interconnection Request Queue.
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1 The Port Hawkesbury Biomass generating unit (63.8 MW gross / 45 MW net output) is 2 presently an ERIS classified resource which will be converted to NRIS following the 3 system upgrades associated with Transmission Service Request 400 which is discussed 4 further is Section 5.1. 5 6 5.1 OATT Transmission Service Queue 7 8 As of June 22, 2020, as shown in Figure 8, there are three ongoing requests in the OATT 9 Transmission Queue and eight additional requests in respect of projects that are complete 10 and in service. 11 12 Figure 8: Requests in the OATT Transmission Queue Requested Project Date & Time of Project Project Number Project In Service Size Status Service Request Type Location Date (MW) 4 TSR July 22, 2011 Point- NS-NB May 2019 330 System Upgrades 400 to-Point in Progress 5 TSR November 28, Point- NB – Jan 1, 2015 4 In Service 401 2013 to-Point Lunenburg Co. 6 TSR November 28, Network Lunenburg Oct 1, 2015 0.4 In Service 402 2013 Co. (1.14) 7 TSR December 4, Point- NB – Oct 1, 2015 7 In Service 403 2013 to-Point Kings Co. 8 TSR December 4, Network Kings Co. Oct 1, 2015 1.25 In Service 404 2013 (2.63) 9 TSR March 27, 2015 Network Riverport Oct 1, 2015 0.56 In Service 405 NS 10 TSR April 27, 2015 Network Antigonish Oct 1, 2015 6.52 In Service 406 NS
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Requested Project Date & Time of Project Project Number Project In Service Size Status Service Request Type Location Date (MW) 11 TSR April 13, 2017 Point- Riverport June 1, 2017 3.0 In Service 407 to-Point NS 12 TSR April 13, 2017 Point- Antigonish June 1, 2017 20 In Service 408 to-Point 13 TSR January 17, Point- NB-NS Jan 1, 2025 800 SIS in Progress 409 2020 to-Point 14 TSR February 10, Point- Woodbine- Jan 1, 2025 500 SIS in Progress 410 2020 to-Point NS 1 2 The completion of system upgrades related to Transmission Service Request 400 requires 3 additional design work and subsequent procurement of materials. 4 5 Studies are being performed to determine the system upgrades necessary for TSR 409 6 and TSR 410.
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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 Standards (RES) include 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 18 19 NS Power has complied with or exceeded the renewable electricity requirement in all 20 applicable years. From 2015 to 2019 the Company served 26.6 percent, 28 percent, 29 21 percent, 30 percent and 30 percent of sales, respectively, using qualifying renewable 22 energy sources. The RES target for 2020 would largely be met by the energy import 23 from the Muskrat Falls hydro project. On March 27, 2020 Nalcor Energy (Nalcor) 24 announced that it temporarily paused construction activities at the Muskrat Falls project 25 site in response to the COVID-19 pandemic.16 Construction and commissioning of the
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. 2020-147 (effective May 5, 2020), N.S. Reg. 74/2020 s. 5(2A). 16 https://muskratfalls.nalcorenergy.com/march-27-2020-covid-19-update-from-nalcor-on-the-muskrat-falls-project/
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1 Muskrat Falls hydro project resumed on May 30, 2020. Nalcor has not provided an 2 updated construction schedule, however, given the risk of a delay in the delivery of the 3 Nova Scotia Block, the Province has permitted NS Power to address this through an 4 alternative compliance plan for 2020 through 2022 under the RES Regulations. 5 6 The RES Compliance Forecast in Figure 9 illustrates the full amount of RES-eligible 7 energy forecast to be available to the Company if the Nova Scotia Block energy flow 8 begins on January 1, 2021.
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1 Figure 9: RES Compliance Forecast
RES Compliance Forecast17 2021 2022 2023 2024 Energy Requirements (GWh) NSR including DSM effects 11,081 11,134 11,176 11,228 Losses 742 749 747 750 Sales 10,339 10,385 10,429 10,478 RES (%) Requirement 40% 40% 40% 40% RES Requirement (GWh) 4,136 4,154 4,172 4,191
Renewable Energy Sources (GWh) NSPI Wind 259 259 259 259 Post 2001 IPPs 757 757 757 757 PH Biomass 290 290 290 290 COMFIT Wind Energy 534 534 534 534 COMFIT Non-Wind Energy 44 44 44 44 Eligible Pre 2001 IPPs 81 81 81 81 Eligible NSPI Legacy Hydro 935 935 935 935 REA procurement (South Canoe/Sable) 357 357 357 357 Compliant Renewable Imports 1,134* 1,134 1,134 1,134
Forecast Renewable Energy (GWh) 4,390 4,389 4,389 4,389 Forecast Surplus or Deficit (GWh) 255 235 218 198 Forecast RES Percentage of Sales 42% 42% 42% 42% 2 *This assumes the full year of Maritime Link energy flow.
17 NSR and Losses are from the 2020 NS Power 10 Year Energy and Demand Forecast, M09707, Exhibit N-1, Table A-1, May 6, 2020.
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1 6.2 Environmental Regulatory Requirements 2 3 The Nova Scotia Greenhouse Gas Emissions Regulations18 specify emission caps for 4 2010-2030, as outlined in Figure 10. The net result is a hard cap reduction from 10.0 to 5 4.5 million tonnes over that 20-year period, which represents a 55 percent reduction in
6 CO2 release over 20 years. Carbon emissions in Nova Scotia from the production of 7 electricity in 2030 are forecast to have decreased by 58 percent from 2005 levels. 8 9 Figure 10: Multi-year Greenhouse Gas Emission Limits Year GHG Cumulative Million tonnes
2014-2016 26.32
2017-2019 24.06
2020 7.5 (annual)
2021-2024 27.5
2025 6 (annual)
2026-2029 21.5
2030 4.5 (annual)
10 11 The Sustainable Development Goals Act19 states Nova Scotia’s goals to achieve 12 province-wide greenhouse gas emission reductions of at least 10 percent below levels 13 emitted in 1990 by 2020, at least 33 percent below the levels that were emitted in 2005 by 14 2030, and a “net zero” by 2050 by balancing greenhouse gas emissions with greenhouse 15 gas removals and other offsetting measures.
18 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. 19 An Act to Achieve Environmental Goals and Sustainable Prosperity, S.N.S. 2019, c. 26, not proclaimed in force.
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1 On January 1, 2019 Nova Scotia’s cap-and-trade program came into effect. The Cap-and- 2 Trade Program Regulations include the annual free allowances for GHG emissions for 3 NS Power. 4 5 Under the GHG cap-and-trade system NS Power is allowed to purchase only 5 percent of 6 GHG credits which will be put up for auction by the province. Nova Scotia Power is 7 forecasting that the GHG credits available for the company to purchase will be 8 approximately 0.1 Mt annually. Although bilateral GHG trades among participants are 9 permitted, NS Power does not anticipate being able to trade significant amounts of GHG 10 credits with other participants. Due to limited GHG credit purchase opportunities, GHG 11 credit purchase will not be the primary means of GHG compliance. The primary means 12 of meeting the caps is a reduction in thermal generation from the existing coal-fired 13 generating units, replaced by non-emitting energy. 14 15 Although the free GHG allowance under the GHG cap-and-trade system was specified 16 for each year from 2019 to 2022 as noted in Figure 11, the allowances can be 17 redistributed in a four-year compliance period between 2019 and 2022 in order to reduce 18 the cost of compliance. NS Power is forecasting GHG release over the GHG cap-and- 19 trade free allowance allocation for 2019 and 2020, and GHG release under the free GHG 20 allocation in 2021 and 2022, as the lowest cost of compliance. 21 22 Figure 11: Greenhouse Gas Free Allowances 2019-2022 Year GHG Free Allowances Million tonnes
2019 6.334
2020 5.517
2021 5.120
2022 5.087
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1 NS Power thermal facilities that meet the CO2 emissions threshold for cap-and-trade 2 (50,000 tonnes) are not required to pay fuel surcharges on fuel consumed for electricity 3 generation. Fuel consumed for on-site activities via mobile equipment is subject to a fuel 4 surcharge under the Cap-and-Trade Regulations. 5 6 As the Port Hawkesbury Biomass facility and the combustion turbine sites do not meet 7 the emissions threshold, fuel consumed on those sites will be subject to fuel surcharges 8 under the Cap and Trade Regulations. 9 10 The Nova Scotia Air Quality Regulations20 specify emission caps for sulphur dioxide
11 (SO2), nitrogen oxides (NOX), and mercury (Hg). These regulations were amended to 12 extend from 2020 to 2030, effective January 1, 2015. The amended regulations replaced
13 annual limits with multi-year caps for the emissions targets for SO2 and NOX. 14
15 The province introduced amendments to the Air Quality Regulations respecting the SO2 16 cap for a three-year period from 2020 to 2022, effective January 21, 2020. The 17 regulations also provide local annual maximums, as well as limits on individual coal units
18 for SO2. The revised emissions requirements are shown below in Figure 12.
20 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. 2020-016 (effective January 21, 2020), N.S. Reg. 8/2020.
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1 Figure 12: Emissions (SO2, NOx, Hg)
Multi-Year SO2 (t) SO2 (t) NOX (t) NOx (t) Hg (kg) Caps Period Annual Max Annual Max 2020 60,900 35 14,955 2021-2022 90,000 14,955 35 68,000 35 2023-2024 56,000
2025 28,000 11,500 35 28,000 11,500 35 2026 – 2029 104,000 44,000
2030 20,000 8,800 30 2
3 By 2030, SO2 emissions from generating electricity will have been reduced by 80 percent
4 from 2005 levels. NOX emissions will have decreased by 73 percent and mercury 5 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. NS Power offered a 12 mercury recovery program, such as recycling light bulbs or other mercury-containing 13 consumer products, which reduced the amount of mercury going into the environment 14 through landfills. The amount of mercury diverted in 2019 resulted in the total amount of 15 credits exceeding the credit target for the program; therefore, NS Power is no longer 16 funding the program as of January 31, 2020. Credits approved by Nova Scotia 17 Environment (NSE) may be used to compensate from the deferred emissions by 2020, 18 and a limited amount of credits approved by NSE (30 kg in 2020, 10 kg per year for 19 subsequent years) may be used for compliance from 2020 to 2029.
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1 6.3 Upcoming Policy Changes 2 3 Until the federal coal phase-out policy changes announced in the fall of 2016,21 NS 4 Power’s operation of and planning for its coal-fired generation units proceeded consistent 5 with the provisions of the Agreement on Equivalency of Federal and Nova Scotia 6 Regulations for the Control of Greenhouse Gas Emissions from Electricity Producers in 7 Nova Scotia (the Equivalency Agreement). The Equivalency Agreement was finalized in 8 May 2014, and effective starting July 2015, contemporaneous with the effective date for 9 the current federal Reduction of Carbon Dioxide Emissions from Coal-Fired Generation 10 of Electricity Regulations. 11 12 In November 2016, the Province of Nova Scotia announced that an agreement-in- 13 principle had been reached with the Government of Canada to develop a new equivalency 14 agreement that will enable the province to move directly from fossil fuels to clean energy 15 sources while allowing Nova Scotia's coal-fired plants to operate at some capacity 16 beyond 2030. The need for this new agreement was driven by amendments proposed by 17 the Federal Government to the Reduction of Carbon Dioxide Emissions from Coal-fired 18 Generation of Electricity Regulations.22 On March 30, 2019 the Renewal of this 19 Equivalency Agreement was published in Canada Gazette I. In the Renewal of the 20 existing Equivalency Agreement, a Quantitative Analysis for the period to 2040 was 21 examined, which has formed the basis for the second Equivalency Agreement. A range of 22 coal closure dates and GHG trajectories is being examined through the Company’s 2020 23 IRP.
21 https://www.canada.ca/en/environment-climate-change/news/2017/11/taking_action_tophase-outcoalpower.html 22 Vol. 152, No. 7 Canada Gazette Part I Ottawa, Saturday, February 17, 2018.
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1 7.0 RESOURCE ADEQUACY 2 3 7.1 Operating Reserve Criteria 4 5 Operating Reserves are resources which can be called upon by system operators on short 6 notice to respond to the unplanned loss of generation or imports. These assets are 7 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 NSUARB. 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 17 Each Balancing Authority shall have thirty-minute reserve available that is 18 at least equal to one half its second contingency loss.23 19 20 In the Interconnection Agreement between Nova Scotia Power Incorporated and New 21 Brunswick System Operator (NBSO),24 NS Power and New Brunswick Power (NB 22 Power) have agreed to share the reserve requirement for the Maritimes Area on the 23 following basis: 24 25 The Ten-Minute Reserve Responsibility, for contingencies within the 26 Maritimes Area, will be shared between the two Parties based on a 12CP 27 [coincident peak] Load-Ratio Share… Notwithstanding the Load-Ratio 28 Share the maximum that either Party will be responsible for is 100 percent 29 of its greatest, on-line, net single contingency, and, NSPI shall be 30 responsible for 50 MW of Thirty-Minute Reserve.
23 https://www.npcc.org/Standards/Directories/Forms/Public%20List.aspx 24 New Brunswick's 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 2 The Ten-Minute Reserve Responsibility formula results in a reserve share of 3 approximately 40 percent of the largest loss-of-source contingency in the Maritimes Area 4 (limited to 10 percent of Maritimes Area coincident peak load). This yields a reserve 5 share requirement for NS Power of approximately 40 percent of 550 MW, or 220 MW, 6 capped at the largest on-line unit in Nova Scotia. When Point Aconi is online, NS Power 7 maintains a ten-minute operating reserve of 168 MW (equivalent to Point Aconi net 8 output), of which approximately 33 MW is held as spinning reserve on the system. 9 Additional regulating reserve is maintained to manage the variability of customer load 10 and generation. The reserve sharing requirement with Maritime Link as the largest 11 source in Nova Scotia will depend on the amount of Maritime Link power used in Nova 12 Scotia. 13 14 7.2 Planning Reserve Criteria 15 16 The Planning Reserve Margin (PRM) is intended to maintain sufficient resources to serve 17 firm customers. Unit forced outages, higher than forecast demand, and lower than 18 forecast wind generation are all conditions that could individually or collectively 19 contribute to a shortfall of dispatchable capacity resources to meet customer demand. 20 21 NS Power is required to comply with the NPCC reliability criteria that have been 22 approved by the NSUARB. These criteria are outlined in NPCC Regional Reliability 23 Reference Directory #1 – Design and Operation of the Bulk Power System25 which states: 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,
25 https://www.npcc.org/Standards/Directories/Forms/Public%20List.aspx
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1 forced outages and deratings, assistance over interconnections with 2 neighboring Planning Coordinator Areas, transmission transfer 3 capabilities, and capacity and/or load relief from available operating 4 procedures. 5 6 The PRM is a long-term planning assumption that is typically updated as part of an IRP 7 process. As part of the pre-IRP study, NS Power engaged Energy+Environmental 8 Economics Consulting, LLC (E3) to undertake a PRM and capacity value study. The 9 study found that in order to meet a 0.1 days/year loss of load expectation (LOLE) target 10 and comply with the NPCC reliability requirements, NS Power should maintain a PRM 11 between 17.8 percent and 21 percent.26 The range in target PRM is due to a higher and 12 lower estimate of operating reserve (OR) requirements for the NS Power system. NS 13 Power is studying the appropriate calculation of its PRM as part of the 2020 IRP. For the 14 purposes of this Report, NS Power has continued to use a 20 percent PRM. 15 16 The PRM provides a basis for the minimum required firm generation NS Power must 17 plan to maintain to comply with NPCC reliability criteria; it does not represent the 18 optimal or maximum required capacity to serve other system requirements such as load- 19 following (ramping capability) and emissions compliance. The optimal capacity 20 requirement is determined through a long-term planning exercise such as the on-going 21 IRP, as discussed in Section 7.4 below.
26 M08929, Energy + Environmental Economics, Planning Reserve Margin and Capacity Value Study for Nova Scotia Power Inc. July 2019 found as Attachment 17 to NS Power’s Pre-IRP Deliverables Report located at https://irp.nspower.ca/documents/pre-irp-deliverables/.
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1 7.3 Capacity Contribution of Renewable Resources in Nova Scotia 2 3 Due to their variability, renewable energy resources (such as wind and solar) are not 4 always available to contribute during peak demand hours. The Effective Load Carrying 5 Capability (ELCC), or “capacity value” of a resource represents the statistical likelihood 6 that it will be available to serve the firm peak demand, and as a result, what percentage of 7 its capacity can be counted on as firm for system planning. Loss of Load Expectation 8 (LOLE) studies are the industry standard used to calculate the ELCC or capacity value of 9 these renewable resources. 10 11 By letter dated October 5, 201827 the NSUARB directed NS Power to complete a number 12 of pre-IRP analyses by July 31, 2019. One of the pre-IRP deliverables directed by the 13 NSUARB was a Capacity Study to calculate the ELCC of wind and other renewable 14 energy generators, both for the existing wind resources as well as potential new 15 resources. The study was undertaken by E328 on behalf of NS Power and the results 16 determined the average ELCC of the wind currently installed on the NS Power system to 17 be 19 percent. The declining marginal ELCC value of adding new wind the NS Power 18 system was determined to be 11 to 9 percent. NS Power has used the 19 percent capacity 19 value of wind for the purposes of this year’s Report and will use these updated values in 20 the system capacity forecast in future 10-Year System Outlook Reports. 21 22 Please refer to Section 7.3.1 regarding the inclusion of ERIS wind resources. 23 24 Municipal load for Berwick, Mahone Bay, Antigonish and Riverport is served by a wind 25 farm owned by Alternative Resource Energy Authority (AREA) and by imports. This
27 M08059, UARB Decision Letter, Generation Utilization and Optimization, October 5, 2018. 28 M08929, Integrated Resource Planning and Generation Utilization and Optimization (P-884) Energy+Environmental Economics, Planning Reserve Margin and Capacity Value Study, July 2019, Attachment 18 to NS Power’s Pre-IRP Final Report at https://irp.nspower.ca/documents/pre-irp-deliverables/
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1 generation is not included in NS Power’s sourced wind generation but contributes to 2 operational considerations of the total amount of wind generation. 3 4 7.3.1 Energy Resource Interconnection Service Connected Resources 5 6 In the 2018 10-Year System Outlook Report, NS Power provided a study to determine 7 the potential capacity contribution of ERIS facilities based on current system 8 configuration and conditions. The study concluded that existing ERIS facilities can 9 operate as though they are NRIS facilities and therefore can contribute to system capacity 10 for the purposes of resource planning at this time without the requirement for additional 11 system upgrades. The transmission system upgrades undertaken to enable the 12 transmission of Maritime Link energy across Nova Scotia contributed to the change to 13 ERIS facility capacity treatment. 14 15 Consistent with this, and for the purposes of reflecting this potential additional capacity 16 in this Report, NS Power has applied a capacity value of 19 percent to existing wind 17 resources, at this time both ERIS and NRIS, in this Report. Please refer to Section 7.3 for 18 further information on the capacity study used to determine the 19 percent. 19 20 This represents a new area for resource planning and remains subject to change. Until 21 these matters are better understood it remains premature to make longer-term resource 22 planning decisions based on this capacity addition. The Company will continue to 23 monitor this resource planning input and will refine the capacity estimates as required. 24 Changes, if necessary, will be incorporated within future 10YSO Reports.
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1 7.4 Load and Resources Review 2 3 The ten-year load and resources outlook in Figure 13 is based on the capacity changes 4 and DSM forecast from Figure 4, and provides details regarding NS Power’s required 5 minimum forecast planning reserve margin equal to 20 percent of the firm peak load. 6 7 The current forecast indicates a capacity deficit. The ongoing 2020 IRP will provide 8 guidance on the optimal resource mix to address any capacity deficits and direct future 9 generation resource decisions. The Company expects to be able to manage through the 10 2020-2021 winter period and can also find near-term solutions for access to firm capacity 11 if required. NS Power will continue to monitor potential deficits or apparent surpluses as 12 forecasts continue to evolve and will adjust decisions accordingly. 13 14 As stated in Section 3.2.2, for the purposes of this Report, the Company has not forecast 15 the 33 MW firm capacity previously provided by VJ2 CT. 16 17 Figure 13 is intended to provide a medium-term outlook of the capacity resources 18 available to the Company compared to expected customer demand, given the most recent 19 assumptions to date. As noted in Section 7.2, the planning reserve margin provides a 20 basis for the minimum required firm generation NS Power must maintain to comply with 21 NPCC reliability criteria; it does not necessarily represent the optimal or maximum 22 required capacity to serve other system requirements such as wind-following (ramping 23 capability) and emissions compliance. In its Final Report submitted to the NSUARB in 24 the Generation Utilization and Optimization proceeding,29 Synapse stated: 25 26 The PRMs provide one high-level measure of the amount of generation 27 capacity relative to the NPCC 20 percent planning reserve margin 28 requirement. PRM is defined as the amount of firm capacity available over
29 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.
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1 the planning peak load. Notably, the NPCC constraint is not the only 2 constraint that dictates how much capacity might be required on the 3 system. Plexos’ ability to model hourly dispatch requirements means that 4 any ramping requirements must be met with adequate capacity. Also, the 5 presence of annual emissions constraints combined with the multi‐fossil‐ 6 fuel environment in which the thermal fleet operates (coal, oil, gas) leads 7 to capacity requirements that could exceed thresholds needed to meet 8 either NPCC reserve or ramping requirements. The integrated aspect of 9 the model (long‐term planning and short‐term dispatch) is intended to 10 allow capture of all these moving parts when optimizing retirement and 11 build decisions.30 12 13 As noted by Synapse, other considerations may dictate the most economic generating 14 capacity for the system; therefore, any surplus capacity in an outlook does not necessarily 15 suggest that any full or partial unit retirement would be possible or optimal, as these units 16 may provide other additional value. The optimal capacity requirements, including 17 addressing a capacity shortfall and the appropriateness of any unit retirements, are being 18 evaluated in the 2020 IRP.
30 Ibid at Section 3.1.
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1 Figure 13: NS Power 10 Year Load and Resources Outlook31 Load and Resources Outlook for NSPI - Winter 2020/2021 to 2029/2030 (All values in MW except as noted) 2020/ 2021/ 2022/ 2023/ 2024/ 2025/ 2026/ 2027/ 2028/ 2029/ 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Firm Peak including effects of A DSM 2,085 2,053 2,059 2,064 2,070 2,074 2,075 2,075 2,076 2,076 B Required Reserve (A x 20%) 417 411 412 413 414 415 415 415 415 415 C Required Capacity (A + B) 2,502 2,464 2,471 2,477 2,484 2,489 2,490 2,490 2,491 2,491
D Existing Resources 2,357 2,357 2,357 2,357 2,357 2,357 2,357 2,357 2,357 2,357 Firm Resource Additions: E Thermal Additions32 -148 43 F Diesel CT33 33 G Tidal34 2 H Hydro35 -101 101 I Maritime Link Import36 153 Total Annual Firm Additions J (E + F + G + H) 38 43 -98 0 101 0 0 0 0 0 Total Cumulative Firm Additions (I + J of the previous K year) 38 81 -17 -17 83 83 83 83 83 83 L Total Firm Capacity (D + J) 2,395 2,438 2,340 2,340 2,441 2,441 2,441 2,441 2,441 2,441
+ Surplus / - Deficit (K - C) -106 -25 -131 -137 -44 -48 -49 -49 -50 -50 Reserve Margin % [(K - A)/A] 15% 19% 14% 13% 18% 18% 18% 18% 18% 18%
31 The 2020 IRP will inform future expansion and retirements. 32 Lingan 2 retirement/lay-up upon commencement of firm capacity service by the Maritime Link Base Block import (-148 MW). 33 Tusket CT is assumed to be available for winter 2020/2021. As discussed in section 3.2.2, the firm capacity provided by VJ2 CT is assumed to be unavailable and is not included in the Existing Resources found on line D. 34 Tidal Feed-in Tariff (Firm capacity) assumed in service 01/01/2023. 35 Wreck Cove life extension modifications - one unit forecast to be unavailable from June 2022 to May 2024. Solutions to any capacity shortfalls will be evaluated including access to firm capacity if required. 36 The Company’s forecast for 2021 still assumes the flow of energy from Muskrat Falls hydro project beginning January 1, 2021. As noted in section 6.1, construction of the project has experienced COVID-related delays, and Nalcor has not provided an updated project schedule.
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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 14. 8 9 Figure 14: NS Power Major Facilities in Service 2020 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25
26 The 345 kV transmission system is approximately 468 km in length and comprises 372 27 km of steel tower lines and 96 km of wood pole lines.
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1 The 230 kV transmission system is approximately 1271 km in length and comprises 47 2 km of steel/laminated structures and 1224 km of wood pole lines. 3 4 The 138 kV transmission system is approximately 1871 km in length and comprises 303 5 km of steel structures and 1568 km of wood pole lines. 6 7 The 69 kV transmission system is approximately 1560 km in length and comprises 12 km 8 of steel/concrete structures and 1548 km of wood pole lines. 9 10 Nova Scotia is interconnected with the New Brunswick electric system through one 345 11 kV and two 138 kV lines providing up to 505 MW of transfer capability to New 12 Brunswick and between 0 and 300 MW of transfer capability from New Brunswick, 13 depending on system conditions. As the New Brunswick system is interconnected with 14 the province of Quebec and the state of Maine, Nova Scotia is integrated into the NPCC 15 bulk power system. 16 17 Nova Scotia is also interconnected with Newfoundland via a 500 MW, +/-200 kV DC 18 Maritime Link tie that was placed into service on January 15, 2018 in preparation for the 19 receipt of capacity and energy from the Muskrat Falls Hydro project and the Labrador 20 Island Link DC tie between Labrador and Newfoundland. The Maritime Link is owned 21 and operated by NSP Maritime Link Inc., a wholly owned subsidiary of Emera 22 Newfoundland & Labrador. 23 24 8.2 Transmission Design Criteria 25 26 Consistent with good utility practice, NS Power utilizes a set of deterministic criteria for 27 its interconnected transmission system that combines protection performance 28 specifications with system dynamics and steady state performance requirements.
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1 The approach used has involved the subdivision of the transmission system into various 2 classifications, each of which is governed by the NS Power System Design Criteria. The 3 criteria require the overall adequacy and security of the interconnected power system to 4 be maintained following a fault on and disconnection of any single system component. 5 6 8.2.1 Bulk Power System (BPS) 7 8 The NS Power bulk transmission system is planned, designed and operated in accordance 9 with North American Electric Reliability Corporation (NERC) Standards and NPCC 10 criteria. NS Power is a member of the NPCC, therefore, those portions of NS Power’s 11 bulk transmission network where single contingencies can potentially adversely affect the 12 interconnected NPCC system are designed and operated in accordance with the NPCC 13 Regional Reliability Directory 1: Design and Operation of the Bulk Power System, and 14 are defined as Bulk Power System (BPS). 15 16 8.2.2 Bulk Electric System (BES) 17 18 On July 1, 2014 the NERC Bulk Electricity System (BES) definition took effect in the 19 United States. The BES definition encompasses any transmission system element at or 20 above 100 kV with prescriptive inclusions and exclusions that further define BES. 21 System Elements that are identified as BES elements are required to comply with all 22 relevant NERC reliability standards. 23 24 NS Power has adopted the NERC definition of the BES and an NS Exception Procedure 25 for elements of the NS transmission system that are operated at 100 kV or higher for 26 which contingency testing has demonstrated no significant adverse impacts outside the 27 local area. The NS Exception Procedure is used in conjunction with the NERC BES 28 definition to determine the accepted NS BES elements and is equivalent to Appendix 5C 29 of the NERC Rules of Procedure.
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1 The BES Definition and NS Exception Procedure were approved by NSUARB Order 2 dated April 6, 2017. 3 4 Under the BES definition and NS Exception Procedure approved by the NSUARB, 5 elements classified as NS BES elements are required to adhere to all relevant NERC 6 standards that have been approved by the NSUARB for use in Nova Scotia. 7 8 8.2.3 Special Protection Systems (SPS) 9 10 Special Protection Systems (SPS) are also referred to as Remedial Action Schemes in 11 NERC documentation. Both terms are valid. 12 13 NS Power also makes use of SPS in conjunction with the Supervisory Control and Data 14 Acquisition (SCADA) system to enhance the utilization of transmission assets. These 15 systems act to maintain system stability and remove equipment overloads, post- 16 contingency, by rejecting generation and/or shedding load. The NS Power system has 17 several transmission corridors that are regularly operated at limits without incident due to 18 these SPS. 19 20 8.2.4 NPCC A-10 Standard Update 21 22 The NPCC Task Force on Coordination of Planning (TFCP) has now completed its 23 revision of Document A-10 and its application, in consultation with the Task Force on 24 Coordination of Operation (TFCO), Task Force on System Protection (TFSP), and Task 25 Force on System Studies (TFSS). The TFCP responded to all comments received in the 26 Open Process and on November 13, 2019 the TFCP approved the revised version of the 27 document and forwarded it to the Reliability Coordinating Committee (RCC) for Full 28 Membership approval.
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1 On November 27, 2019, the Reliability Coordinating Committee (RCC) recommended 2 balloting the Revised NPCC Document A-10 – Classification of Bulk Power System 3 Elements for Full Member approval. In addition, the RCC then approved the Revised 4 NPCC Document A-10 Implementation Plan. 5 6 On March 27, 2020, the NPCC full Member Committee voted to approve the A-10 7 Classification of bulk Power System Elements document as follows: 8 9 In accordance with Section VIII of the Amended and Restated NPCC By- 10 Laws dated January 1st, 2012 the NPCC Full Member Committee has 11 voted to approve the following ballot proposal effective March 27, 2020: 12 13 A-10 Classification of Bulk Power System Elements ---- Revised: 14 15 • Consistent with the recommendations contained in the CP-11 A-10 16 Final Report and approved by the Reliability Coordinating Committee 17 (RCC) revisions to the existing performance based test including 18 improvements to the base case set-up, testing assumptions and the 19 utilization of specific performance requirements to evaluate testing 20 outcomes. 21 22 • An element exclusion process for applicability to Directory#1 23 Design and Operation of the Bulk Power System consisting of both 24 automatic and study based exclusions. 25 26 Document A-10 provides a methodology to identify BPS elements in the interconnected 27 NPCC Region, and all NPCC criteria apply to BPS facilities. Changes to the existing A- 28 10 methodology are not expected to have a material financial impact on NS Power as the 29 revised methodology is not expected to greatly increase the number of BPS elements on 30 NS Power’s transmission system.
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1 8.3 Transmission Life Extension 2 3 NS Power has in place a comprehensive maintenance program on the transmission 4 system focused on maintaining reliability and extending the useful life of transmission 5 assets. The program is centered on detailed transmission asset inspections and associated 6 prioritization of asset replacement (i.e. conductor line, poles, cross-arms, guywires, and 7 hardware replacement). 8 9 Transmission line inspections consist of the following actions: 10 11 • Visual inspection of every line once per year via helicopter, or via ground patrol 12 in locations not practical for helicopter patrols. 13 • Foot patrol of each non-BPS line on a three-year cycle. Where a Lidar survey is 14 requested for a non-BPS line, the survey will replace the foot patrol in that year. 15 • For BPS lines, Lidar surveys every two years out of three, with a foot patrol 16 scheduled for the third year. 17 18 These inspections identify asset deficiencies or damage and confirm the height above 19 ground level of the conductor span while recording ambient temperature. This enables the 20 NSPSO to confirm that the rating of each line is appropriate. 21 22 8.4 Transmission Project Approval 23 24 The transmission plan presented in this document provides a summary of the planned 25 reinforcement of the NS Power transmission system. The proposed investments are 26 required to maintain system reliability and security and comply with System Design 27 Criteria and other standards. NS Power has sought to upgrade existing transmission lines 28 and utilize existing plant capacity, system configurations, and existing rights-of-way and 29 substation sites where economic.
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1 Major projects included in the plan have been included on the basis of a preliminary 2 assessment of need. The projects will be subjected to further technical studies, internal 3 approval at NS Power, and approval by the NSUARB. Projects listed in this plan may 4 change because of final technical studies, changes in the load forecast, changes in 5 customer requirements or other matters determined by NS Power, NPCC/NERC 6 Reliability Standards, or the NSUARB. 7 8 In 2008, the Maine and Atlantic Technical Planning Committee (MATPC) was 9 established to review intra-area plans for regional resource integration and transmission 10 reliability. The MATPC forms the core resource for coordinating input to studies 11 conducted by each member organization and presenting study results, such as evaluation 12 of transmission congestion levels with respect to the total transfer capabilities on the 13 utility interfaces. This information is used as part of assessments of potential upgrades or 14 expansions of the interties. The MATPC has transmission planning representation from 15 NS Power, Maritime Electric Company Ltd., Emera Newfoundland and Labrador, 16 Northern Maine Independent System Administrator (which includes Emera Maine 17 Northern Operating Region and Eastern Maine Electric Cooperative), Newfoundland and 18 Labrador Hydro, and New Brunswick Power (NB Power). NS Power and NB Power 19 jointly conduct annual Area Transmission Reviews for NPCC. 20 21 8.5 New Large load Customer Interconnection Requests 22 23 With the legalization of cannabis in Nova Scotia, NS Power saw a large number of new 24 load requests for commercial grow operations in 2019 in addition to proposed 25 commercial, mining, aquaculture and government projects ranging from 1-15 MVA. As 26 a result, approximately 30 Preliminary Assessments were completed, leading to the 27 completion of eight formal Load Impact Studies and the inclusion of proposed loads in an 28 additional three distribution planning studies as noted in Section 5.1 above. Not all these 29 assessments will translate into near-term load, as some projects have multi-year 30 construction or are not completed.
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1 8.6 Wind Integration Stability Study - PSC 2 3 In its October 5, 2018 letter regarding the IRP and GUO (M08059), the NSUARB issued 4 a directive for NS Power to conduct a study to accomplish the following: 5 6 Establish requirements to allow increased levels of wind on the NSPI 7 system. Two threshold criteria to allow increased levels of cost-effective 8 wind resources are completion of a second 345 kV intertie to New 9 Brunswick, and assessment of NSPI’s Provincial transmission system and 10 related support services (to maintain stability and voltage criteria). NSPI 11 should determine, with specificity, the set of technical improvements 12 required to allow different increments of additional wind on their system. 13 This should include the effect of additional transmission capacity to New 14 Brunswick, the presence of the Maritime Link, and the ability to further 15 increase wind penetration through transmission grid reinforcement. This 16 should also recognize that the introduction of bulk scale battery storage as 17 a possible capacity resource that can provide co-benefits associated with 18 stability and voltage support. 19 20 As part of the pre-IRP deliverables, NS Power engaged Power Systems Consultants 21 (PSC) to carry out a wind integration stability study to determine the system requirements 22 needed to allow increased levels of wind generation in Nova Scotia beyond the current 23 level of approximately 600 MW. The final results from the study37 were provided to 24 stakeholders in July 2019 and filed with the NSUARB on May 22, 2020. The 25 Conclusions and Recommendations from this Report are presented below: 26 27 Conclusions and Recommendations from PSC Study 28 The study results suggest that the existing Nova Scotia power system can 29 support the existing 600 MW of wind generation. In the current state, in 30 order to stay secure for the loss of the New Brunswick tie, at least 3 31 thermal units are required to be online. Even with this measure, when the 32 tie is importing, a large amount of customer load needs to be shed to 33 recover the system frequency during such an event.
37 M08929, NS Power’s Integrated Resource Plan, Khosro Kabiri, PSC North America, Nova Scotia Power Stability Study for Renewable Integration Report, July 24, 2019, Attachment 19 to NS Power’s Pre-IRP Final Report at https://irp.nspower.ca/documents/pre-irp-deliverables/.
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1 The development of the second 345 kV tie to New Brunswick (Onslow to 2 Salisbury) allows the integration of a further 400 MW of wind generation 3 (system installed total of 1000 MW inverter-based generation). 4 Furthermore, it provides an enhanced level of system reliability and 5 security for the Nova Scotia system across a range of operating conditions 6 including storm events. 7 8 The same level of wind generation can be reached with the deployment of 9 synchronous condensers and BESS. However, to avoid all stages of load 10 shedding to be activated following trip of the existing tie to New 11 Brunswick when importing, the synchronous condenser and BESS need to 12 be large (judged by comparison to such installations in other jurisdictions). 13 A 200 MVA synchronous condenser fitted with flywheel and a 200 MW 14 BESS reduce the load shedding to 2 stages out of 6. This option also lacks 15 the ancillary reliability benefits afforded by the second 345 kV tie line. 16 17 Study results indicate that the tie to New Brunswick is of the highest 18 significance to the stability of the NS Power system as the loss of the tie 19 dictates most of the planning and/or operational actions. Strengthening of 20 this tie with a second 345 kV line becomes crucial and should be 21 considered as the first alternative to explore before the introduction of 22 other technological solutions or in tandem with them. Application of 23 synchronous condenser and BESS in addition to the second tie line, would 24 result in more benefits such as an increase in renewable generation and 25 enhanced system security and flexibility. 26 27 In concluding, within the scope of the studies performed in preparing this 28 report, it is recommended that the existing study should be expanded to 29 establish a system security level commensurate with increased wind 30 generation. The defined topology should include the second tie as a 31 starting position so that intuitive studies to establish maximum renewable 32 generation penetration with minimum system reinforcement can be 33 established. 34 35 Further recommendations beyond the introduction of the second tie 36 include: 37 38 • Expand the existing study to check wider system dispatch 39 scenarios and establish requirements in terms of support. 40 • Perform enhanced studies in EMT area to support technical 41 requirement. 42 • Establish how the requirements can be met, such as service 43 provision via specific investments or via grid code changes. 44 • Commission parallel studies to check other areas of possible 45 technical limitations such as power quality.
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1 NS power will use the results of this study in future wind integration studies, inclusive of 2 the impacts of new wind generation technology (i.e. fast regulation response, improved 3 ride-through capability, etc.) on provision of ancillary services typically provided via 4 large thermal generation plants, and of the impact of increased curtailment on existing 5 and proposed wind generation facilities.
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1 9.0 TRANSMISSION DEVELOPMENT 2020 TO 2030 2 3 Investments in transmission infrastructure can be affected by energy policy and the 4 changing sources of energy and capacity. Proposed transmission development plans and 5 projects are subject to reconsideration and alignment with current policy goals. Items 6 described below are current as of the date of this report but are subject to change in future 7 and as a result of the ongoing IRP. 8 9 9.1 Impact of Proposed Load Facilities 10 11 As noted in Section 8.5 of this Report, there are a number of system upgrades required to 12 serve load facilities greater than 1 MW that were proposed in 2019. These projects have 13 precipitated the need for the following system upgrades: 14 15 1. Construction of new 15/20/25 MVA, 138 kV-26 kV substation at 101W-Bowater 16 in 2020. 17 2. Advancement of upgrades to 69 kV line L-5021 supplying the 50 V-Klondike 18 Substation in 2020. 19 3. Construction of a new 25/33/42 MVA, 138 kV-25 kV substation in Stellarton in 20 2020/21. 21 4. Replacement of the 15N-Willow Lane 15/20/25//28 MVA, 69 kV-25 kV 22 transformer 15N-T3 in 2020/21. 23 5. Replacement of the Trenton 15/20/25 MVA, 69 kV-25 kV transformer 50N-T63 24 in 2020/21. 25 6. Installation of a second 25/33/42 MVA, 138 kV-25 kV transformer at 1N-Onslow 26 in 2022. 27 7. Installation of a new 25/33/42 MVA, 138 kV-25 kV substation on Suzie Lake 28 Crescent in 2023.
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1 9.2 129H-Kearney Lake Relocation 2 3 NS Power currently leases the 129H Kearney Lake Road substation property. The lease 4 was last extended on February 27, 2018 and will terminate on December 31, 2022. NS 5 Power has been advised that the property owner intends to develop this site and further 6 lease extensions are not expected at this time. 7 8 As such, in 2021 and 2022 NS Power plans to relocate the 129H-Substation from its 9 present site to two land parcels located across the street that were purchased for this 10 purpose in 1986 and 1988. The new substation will have provision for a second 11 transformer to be installed at a future date. One additional transmission tower will also 12 be installed to extend the 138 kV radial supply (L-6038) to the new site. Work to 13 relocate 129H and retire the existing site must be completed by December 31, 2022. 14 15 9.3 Transmission Development Plans 16 17 Transmission development plans are summarized below. As noted above, these projects 18 are subject to change. For 2020 the majority of the projects listed are included in the 2020 19 Annual Capital Expenditure Plan. Further transmission investment may be identified 20 through the IRP process. In addition, some of the timelines associated with the projects 21 listed in 2020 will be impacted by the NS Power response to the COVID-19 pandemic. 22 23 2020 24 • 2C Port Hastings 138 kV substation will be uprated to meet NPCC BPS standards 25 (carry-over from 2019). 26 • New 12 MVA Mount Hope 69 kV-25 kV substation in Dartmouth (carry-over 27 from 2019). 28 • 5P 25 MVA Mobile Substation Replacement (carry-over from 2019). 29 • Replacement of 15/20/25 MVA Penhorn 69-12.5 kV Transformer 48H-T1 (carry- 30 over from 2019).
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1 • 101W-Port Mersey Expansion to include a new 138 kV-25 kV, 15/20/25 MVA 2 transformer and two feeders (C0011261). 3 • 78W-Martins Brook substation relocation and transformer replacement 4 (C0010956). 5 • Capacitor Bank Breaker replacement at 103H-Lakeside (3 breakers). These are 6 high duty cycle units critical to the operation of the transmission system. 7 • Line structure replacements and upgrades. 8 • Replacement of 9W-B53 support structure. 9 • Replacement of 73W-T1 transformer at Auburndale with a new 138/69-25 kV 10 transformer rated at 15/20/25 MVA. 11 • Replacement of 7.5/10//11.2 MVA Halliburton 69-25 kV Transformer 56N-T1 12 with new 15/20/25 MVA unit due to load growth and voltage conversions from 4 13 kV to 25 kV (CI:52328). 14 • Advancement of upgrades to 69 kV line L-5021 supplying the 50V-Klondike 15 Substation in 2020. 16 • Construction of a new 25/33/42 MVA, 138 kV-25 kV substation in Stellarton in 17 2020/21. 18 • Replacement of the 15N-Willow Lane 15/20/25//28 MVA, 69 kV-25 kV 19 transformer 15N-T3 in 2020/21. 20 • Replacement of the Trenton 15/20/25 MVA, 69 kV-25 kV transformer 50N-T63 21 in 2020/21. 22 • Transmission Right-of-Way Widening 69 kV to reduce the occurrence of edge 23 and off right-of-way tree contacts (Year 5 of 8). 24 • Replace existing 5/5.6 MVA Central Argyle 7.5/10/12.5 MVA unit. 25 • Replace existing 4.5/10/12.5/14 MVA Barrington Passage transformer with 26 15/20/25 MVA unit and add additional feeder circuit. 27 • Replace existing 3/4/4.48 MVA Lower East Pubnico transformer with 7.5/10/12.5 28 MVA unit.
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1 2021 2 • 2021 Transmission Right-of-Way Widening 69 kV to reduce the occurrence of 3 edge and off right-of-way tree contacts (Year 6 of 8). 4 • Relocation of the 129H-Kearney Lake Substation from existing leased property to 5 NS Power property on the other side of Kearney Lake Road (to be completed by 6 December 31, 2022 – end of lease). 7 8 2022 9 • Installation of a second 25/33/42 MVA , 138 kV-25 kV transformer at 1N- 10 Onslow. 11 • Transmission Right-of-Way Widening 69 kV to reduce the occurrence of edge 12 and off right-of-way tree contacts (Year 7 of 8). 13 • Install New 138 kV Supply to 50V-Klondike and replace existing 69-25 kV 14 transformer with new 15/20/25 MVA unit. 15 16 2023 17 • Installation of a new 25/33/42 MVA, 138 kV-25 kV substation on Suzie Lake. 18 • Transmission Right-of-Way Widening 69 kV to reduce the occurrence of edge 19 and off right-of-way tree contacts (Year 8 of 8). 20 21 2026 22 • Replace transformers 62N-T1 and 62N-T2 at end of expected life with a single 23 138/69 kV-25 kV, 15/20/25 MVA transformer. 24 • Add a second 25/33/42 MVA, 138 kV-25 kV transformer at new Stellarton 25 substation. 26 27 2028 28 • Installation of a new 138/69 kV-25 kV, 15/20/25 MVA substation in Lower Truro 29 tapped to Line L-5028. 30
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1 9.4 Western Valley Transmission System – Phase II Study 2 3 A study was initiated in late 2017 to determine the system upgrades needed to address 4 transmission line capacity, clearance, and age issues in the Western Valley over a 15-year 5 transmission planning horizon. In particular, the following 69 kV lines were targeted: 6 7 • L-5531 (13V-Gulch to 15V-Sissiboo) 8 • L-5532 (13V-Gulch to 3W-Big Falls) 9 • L-5535 (15V-Sissiboo to 9W-Tusket) 10 • L-5541 (3W-Big Falls to 50W-Milton) 11 12 The scope of the study is to assess the following four options: 13 14 Option #1 ‐ Restore L-5531, L-5532, L-5535, and L-5541 to 50ºC Temperature 15 Rating 16 Option #2 ‐ Upgrade L-5531, L-5532, L-5535, and L-5541 to 80ºC 17 Temperature Rating 18 Option #3 ‐ Rebuild L-5531, L-5532, L-5535, and L-5541 with 336 ACSR 19 Linnet and 100ºC Temperature rating 20 Option #4 ‐ Rebuild L-5531, L-5532, L-5535, and L-5541 with 556 ACSR 21 Dove and 100ºC Temperature rating (Operate at 69kV) 22 23 Status: Work on the Western Valley Transmission System – Phase II Study was deferred 24 in 2018 and the study is now expected to be completed in Q3 2020. In addition to the four 25 options identified above, the following fifth option has also been added: 26 27 Option #5 ‐ Bypass L-5025, L-5026, L-5531, and L-5535 with a new 138 kV 28 line from 51V-Tremont to new substations at 13V-Gulch and 9W- 29 Tusket
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1 10.0 PANDEMIC RESPONSE 2 3 As a result of the province-wide response to the COVID-19 pandemic, Nova Scotia 4 Power is currently experiencing slight shifts in the timing and ramping of peak load. To 5 date, NS Power has experienced an overall decrease in load of approximately 4 percent. 6 Residential load has increased, but commercial and industrial load have decreased as a 7 result of the COVID-19 pandemic. Weather is still the main driver of load profiles. The 8 effects of the COVID-19 pandemic on load patterns, energy usage, and peak demands 9 will continue to be evaluated as the situation unfolds. 10 11 NS Power has created and enacted system operator contingency plans to ensure health 12 and safety of personnel and continued reliable operation of the power grid. The 13 Company is evaluating contingency plans for T&D and Generation planned work, 14 planned maintenance, and forced outages to proceed conservatively while mitigating 15 short term and longer term reliability risks. Contingency plans are re-evaluated constantly 16 as the COVID-19 pandemic evolves. 17 18 Nova Scotia Power continues to monitor the ongoing spread of COVID-19 and remains 19 focused on the health and safety of employees, consultants, contractors, and their 20 families. A response team is monitoring the situation, coordinating with authorities, and 21 keeping employees informed via regular business updates.
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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 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. 9 10 As discussed in Section 10.0 above, NS Power continues to monitor the ongoing spread 11 of COVID-19. To date, NS Power has experienced an overall decline in load of 12 approximately 4 percent since the implementation of COVID-19 restrictions compared to 13 the same time period in 2019. NS Power continues to monitor the impacts of the 14 pandemic. 15 16 The Company is currently forecasting a slight deficit in firm generation capacity. The 17 Company expects to be able to manage through this upcoming winter period and can also 18 find near-term solutions for access to firm capacity if required. NS Power will continue 19 to monitor potential deficits or apparent surpluses as forecasts continue to evolve and will 20 adjust decisions accordingly. 21 22 The key inputs for Transmission Planning in the ten-year window of this Report include 23 the impact of proposed new load facilities outlined in Section 9.1, transmission of energy 24 to be delivered over the Maritime Link, and continued compliance with Reliability 25 Standards. 26 27 NS Power is currently participating in an Integrated Resource Planning (IRP) exercise as 28 directed by the NSUARB with input from a variety of stakeholders across the province. 29 The ongoing IRP, with its internal and external review of assumptions and results, 30 provides a better avenue to conduct the analysis of the UUIS (as noted in Section 3.3,
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1 above). NS Power will return the Plexos modeling analysis of the UUIS in future 10YSO 2 Reports. 3 4 The outcome of this IRP process in the fall of 2020 will impact and inform future 10YSO 5 Reports and related long-term planning processes.
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