Northeast Power Coordinating Council Reliability Assessment For Summer 2016

Transcription

1 Northeast Power Coordinating Council Reliability Assessment For Summer 2016 FINAL REPORT April 28, 2016 Conducted by the NPCC CO 12 & CP 8 Working Groups

2 TABLE OF CONTENTS 1. EXECUTIVE SUMMARY... 1 SUMMARY OF FINDINGS INTRODUCTION DEMAND FORECASTS FOR SUMMER SUMMARY OF RELIABILITY COORDINATOR FORECASTS RESOURCE ADEQUACY NPCC SUMMARY FOR SUMMER MARITIMES NEW YORK ONTARIO GENERATION RESOURCE CHANGES WIND AND SOLAR CAPACITY ANALYSIS BY RELIABILITY COORDINATOR AREA TRANSMISSION ADEQUACY AREA TRANSMISSION ADEQUACY ASSESSMENT AREA TRANSMISSION OUTAGE ASSESSMENT OPERATIONAL READINESS FOR SUMMER 2016 SOLAR TERRESTRIAL DISPATCH FORECAST OF GEOMAGNETICALLY INDUCED CURRENT POST SEASONAL ASSESSMENT AND HISTORICAL REVIEW SUMMER 2015 POST SEASONAL ASSESSMENT RELIABILITY ASSESSMENTS OF ADJACENT REGIONS FOR A COMPREHENSIVE REVIEW OF THE RELIABILITYFIRST CORPORATION SEASONAL RESOURCE AND DEMAND, AND TRANSMISSION ASSESSMENT, GO TO: CP SUMMER MULTI AREA PROBABILISTIC RELIABILTY ASSESSMENT EXECUTIVE SUMMARY APPENDIX I SUMMER 2016 EXPECTED LOAD AND CAPACITY FORECASTS TABLE AP 1 NPCC SUMMARY TABLE AP 2 MARITIMES TABLE AP 3 NEW ENGLAND TABLE AP 4 NEW YORK TABLE AP 5 ONTARIO TABLE AP 6 QUÉBEC APPENDIX II LOAD AND CAPACITY TABLES DEFINITIONS APPENDIX III SUMMARY OF TOTAL TRANSFER CAPABILITY UNDER FORECASTED SUMMER CONDITIONS APPENDIX IV DEMAND FORECAST METHODOLOGY RELIABILITY COORDINATOR AREA METHODOLOGIES APPENDIX V NPCC OPERATIONAL CRITERIA, AND PROCEDURES... 88

3 APPENDIX VI WEB SITES APPENDIX VII REFERENCES APPENDIX VIII CP SUMMER MULTI AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION... 93

4 The information in this report is provided by the CO 12 Operations Planning Working Group of the NPCC Task Force on Coordination of Operation (TFCO). Additional information provided by Reliability Councils adjacent to NPCC. The CO 12 Working Group members are: Michael Courchesne Rod Hicks Kyle Ardolino (Chair) Wei Yang Frank Peng Mathieu Labbé Mila Milojevic Paul Roman Andreas Klaube ISO New England New Brunswick Power System Operator New York ISO New York ISO Independent Electricity System Operator Hydro Québec TransÉnergie Nova Scotia Power Inc. Northeast Power Coordinating Council Northeast Power Coordinating Council

5 1. Executive Summary This report is based on the work of the NPCC CO 12 Operations Planning Working Group and focuses on the assessment of reliability within NPCC for the 2016 Summer Operating Period. Portions of this report are based on work previously completed for the NPCC Reliability Assessment for the Summer 2015 Operating Period 1. Moreover, the NPCC CP 8 Working Group on the Review of Resource and Transmission Adequacy provides a seasonal multi area probabilistic reliability assessment. Results of this assessment are included as a chapter later in this report and supporting documentation is provided in Appendix VIII. Aspects that the CO 12 Working Group has examined to determine the reliability and adequacy of NPCC for the season are discussed in detail in the respective report sections. The following Summary of Findings addresses the significant points of the report discussion. The findings discussed herein are based on projections of electric demand requirements, available generation resources and the most current transmission configurations. This report evaluates NPCC s and the associated Balancing Authority (BA) areas ability to deal with the differing resource and transmission configurations within the NPCC region and the associated Balancing Authority areas preparations to deal with the possible uncertainties identified in this report. Summary of Findings The forecasted coincident peak demand for NPCC occurring during the peak week (week beginning July 3, 2016) 2 is 106,390 MW, as compared to 107,440 MW forecasted during the summer 2015 peak week. Unless otherwise noted, all forecasted demand is a normal (50/50) peak forecast. The coincident peak demand during the summer of 2015 was 100,883 MW, occurring on July 29. The capacity outlook indicates a forecasted Net Margin for that week of 15,008 MW. This equates to a net margin of 14.1 percent in terms of the 106,390 MW forecasted peak demand. The week with the minimum forecasted Net Margin of 12,786 MW (or 12.3 percent) available to NPCC is the week beginning June 5, The NPCC Assessments can be downloaded from the NPCC website 2 Load and Capacity Forecast Summaries for NPCC, Maritimes, ISO NE, NYISO, IESO, and HQ are included in Appendix I. NPCC Reliability Assessment Summer 2016 Page 1 of 93 Northeast Power Coordinating Council Inc.

6 The largest forecasted NPCC Net Margin for the 2016 Summer Operating Period of 35.4 percent occurs during the week beginning May 1, 2016 During the NPCC forecasted peak week of July 3, 2016, the Area forecasted net margins in terms of forecasted demand ranges from approximately 2.8 percent in New England to 49.7 percent in the Maritimes. When comparing the peak week from the previous summer (July 5, 2015) to this summer s expected peak week (July 3, 2016) the NPCC installed capacity has increased by 1,382 MW to 158,494 MW. No delays are forecasted for the commissioning of new resources. However, any unplanned delays will not materially impact the overall net margin projections for NPCC. The Maritimes Area has forecasted a summer 2016 peak demand of 3,606 MW for the week beginning May 1 with a projected net margin of 1,282 MW (35.6 percent). When compared to the summer 2015 peak demand forecast it is a decrease of 142 MW ( 3.79 percent). Hydro Quebec has an outage scheduled on their Madawaska HVDC for refurbishment and New Brunswick has routine maintenance outages scheduled on both of the Eel River HVDC circuits, one circuit down one at a time. Both the Madawaska and Eel River outages will lower the transfer capability in either direction between New Brunswick and Québec, but are not expected to impact the system reliability of the Maritimes (Please refer to Table 8 for MW reductions and timelines). Transmission upgrades on the 345 kv system as well as the planned Point Lepreau outage will affect the transfer capabilities between New Brunswick and New England (Please refer to Table 8 for MW reductions and timelines). New England forecasts a net summer peak demand of 26,704 MW 3 for the week beginning July 17, 2016, with a projected net margin of 754 MW (2.8 percent). The forecast is 6 MW less than the 2015 summer forecast of 26,710 MW and takes into account the demand reductions associated with energy efficiency, load management and distributed generation. The 2016 summer net demand forecast is based on updated historical load, current weather data, results of Passive Demand Response initiatives and forecasted impact of behind the meter photovoltaic (PV) resources located on the distribution system. Natural gas 3 Load Forecast assumes Peak Load Exposure of 26,704 MW, to be reported in the 2016 CELT Report, and does include a Passive Demand Response adjustment of 1,839 MW. The most recent copy of the CELT report can be found at ne.com/system planning/system plans studies/celt NPCC Reliability Assessment Summer 2016 Page 2 of 93 Northeast Power Coordinating Council Inc.

7 pipeline construction and maintenance is expected to occur throughout the summer capacity period and adequate natural gas pipeline capacity is anticipated throughout the summer, provided gas supply and transportation is scheduled within each pipeline s posted capability and natural gas supplies are available from the East. New England will continue Gas Electric coordination and communication efforts in order to maintain situational awareness. The NYISO anticipates adequate resources to meet demand for the summer 2016 season. The current summer 2016 peak forecast is 33,360 MW and was updated in March It is lower than the previous year s forecast by 207 MW (0.62 percent). The lower forecasted growth in energy usage can largely be attributed to the projected impact of existing statewide energy efficiency programs and the growing impact of distributed behind the meter energy resources. These include retail photovoltaic, combined heat and power (CHP), anaerobic digester gas (ADG), fuel cells, and energy storage. Anticipated net margins for the summer peak period (June through August) range from 615 MW to 872 MW (1.8 to 2.6 percent). The IESO anticipates adequate resources to meet demand for the Summer 2016 Operating Period. The forecasted Ontario Summer Peak is 22,587 MW for normal weather and 24,598 MW for extreme weather, both occur during the week beginning July 3, The minimum net margin observed during the summer assessment period is 1,418 MW, or 6.4 percent during the week beginning June 26, The 2016 summer forecast is 404 MW lower than the 2015 summer forecast. This is due to conservation, time of use rates and the Industrial Conservation Initiative (ICI) exerting downward pressure on peak summer demands. Also, the combined effects of conservation savings and distribution connected generation is expected to offset any economic and population growth. For the summer of 2016, the competitive market based demand response (DR) auction in Ontario procured MW of capacity. The Québec Area forecasted summer peak demand (excluding April, May and September) is 20,724 MW during the week beginning August 14, with a forecasted net margin of 10,130 MW (49 percent). For summer 2016, Installed Capacity will total 45,484 MW for the Québec Area. Since last summer, La Romaine 1 (270 MW) has been commissioned as well as 379 MW of new wind generation. Hydro generation adjustments have also increased the Installed Capacity by 22 MW. No particular resource adequacy problems are forecasted and the Québec area expects to be able to provide assistance to other areas, if needed, up to the transfer capability available. NPCC Reliability Assessment Summer 2016 Page 3 of 93 Northeast Power Coordinating Council Inc.

8 The results of the CO 12 and CP 8 Working Groups studies indicate that NPCC and the associated Balancing Authority Areas have adequate generation and transmission capabilities for the upcoming Summer Operating Period. Necessary strategies and procedures are in place to deal with operational problems and emergencies as they may develop. However, the resource and transmission assessments in this report are mere snapshots in time and base case studies. Continued vigilance is required to monitor changes to any of the assumptions that can potentially alter the findings in this report. NPCC Reliability Assessment Summer 2016 Page 4 of 93 Northeast Power Coordinating Council Inc.

9 2. Introduction The NPCC Task Force on Coordination of Operation (TFCO) established the CO 12 Operations Planning Working Group to conduct overall assessments of the reliability of the generation and transmission system in the NPCC Region for the Summer Operating Period (defined as the months of May through September) and the Winter Operating Period (defined as the months of December through March). The Working Group may occasionally study other operating periods or specific conditions as requested by the TFCO. For the 2016 Summer Operating Period, 4 the CO 12 Working Group: Examined historical summer operating experiences and assessed their applicability for this period. Examined the existing emergency operating procedures available within NPCC and reviewed recent operating procedure additions and revisions. The NPCC CP 8 Working Group has done a probabilistic assessment of the implementation of operating procedures for the 2016 Summer Operating Period. The results and conclusions of the CP 8 assessment are included as chapter 9 in this report and the full report is included as Appendix VIII. Reported potential sensitivities that may impact resource adequacy on a Reliability Coordinator (RC) Area basis. These sensitivities may include temperature variations, wind generation capacity, in service delays of new generation, load forecast uncertainties, evolving load response measures, fuel availability, system voltage and generator reactive capability limits. Reviewed the capacity margins for normal and extreme system load forecasts, while accounting for bottled capacity within the NPCC. Reviewed inter Area and intra Area transmission adequacy, including new transmission projects, upgrades or derates and potential transmission problems. Reviewed the operational readiness of the NPCC region and actions to mitigate potential problems. Coordinated data and modeling assumptions with the NPCC CP 8 Working Group, and documented the methodology of each Reliability Coordinator area in its projection of load forecasts. 4 For the purpose of this report, the Summer Operating Period evaluation will include operating conditions from week beginning May 1, 2016 through the week beginning September 11, NPCC Reliability Assessment Summer 2016 Page 5 of 93 Northeast Power Coordinating Council Inc.

10 Coordinated with other parallel seasonal operational assessments, including the NERC Reliability Assessment Subcommittee (RAS) Seasonal Assessments. NPCC Reliability Assessment Summer 2016 Page 6 of 93 Northeast Power Coordinating Council Inc.

11 3. Demand Forecasts for Summer 2016 The non coincident forecasted peak demand for NPCC over the 2016 Summer Operating Period is 106,981 MW. The coincident peak demand of 106,390 MW is expected during the week beginning July 3, Demand and Capacity forecast summaries for NPCC, Maritimes, New England, New York, Ontario, and Québec are included in Appendix I. Ambient weather conditions are the single most important variable impacting the demand forecasts during the summer months. As a result, each Reliability Coordinator is aware that the summer peak demand could occur during any week of the summer period as a result of these weather variables. Historically the peak demands and temperatures between New England and New York can have a high degree of correlation due to the relative locations of their respective load centers. Depending upon the extent of the weather system and duration, there is potential for the Ontario peak demand to be coincident with New England and New York. It should also be noted that the non coincident peak demand calculation is impacted primarily by the fact that the Maritimes and Québec experience late spring demands influenced by heating loads that occur during the defined Summer Operating Period. The impact of ambient weather conditions on load forecasts can be demonstrated by various means. The Maritimes and IESO represent the resulting load forecast uncertainty in their respective Areas as a mathematical function of the base load. The NYISO and ISO NE use a weather index that relates air temperature, wind speed and humidity to the load response and increases the load by a MW factor for each degree above the base value. TransÉnergie, the Québec system operator, updates forecasts on an hourly basis within a 12 day horizon based on information on local weather, wind speed, cloud cover, sunlight incidence and type and intensity of precipitation over nine regions of the Québec Balancing Authority Area. While the peak demands appear to be confined to the operating weeks in late June through July, each Area is aware that reduced margins could occur during any week of the operating period as a result of weather variables and / or higher than normal outage rates. The method each Reliability Coordinator uses to determine the peak forecast demand and the associated load forecast uncertainty relating to weather variables is described in Appendix IV. Below is a summary of all Reliability Coordinator forecasts. NPCC Reliability Assessment Summer 2016 Page 7 of 93 Northeast Power Coordinating Council Inc.

12 Summary of Reliability Coordinator Forecasts Maritimes Summer 2016 Forecasted Peak: 3,606 MW (normal) and 3,857 MW (extreme), week beginning May 1, 2016 Summer 2015 Forecasted Peak: 3,748 MW, week beginning April 26, 2015 Summer 2015 Actual Peak: 3,688 MW, on April 29, 2015 at HE8 EDT Figure 3 1: Maritimes Summer 2016 Weekly Demand Profile NPCC Reliability Assessment Summer 2016 Page 8 of 93 Northeast Power Coordinating Council Inc.

13 New England Summer 2016 Forecasted Peak: 26,704 MW (normal) and 29,042 MW (extreme), week beginning July 17, 2016 Summer 2015 Forecasted Peak: 26,710 MW (normal) and 29,060 MW (extreme), week beginning July 19, 2015 Summer 2015 Real Time Peak: 24,398 MW, on July 20, 2015 at hour ending 17:00 EDT Figure 3 2: New England Summer 2016 Weekly Demand Profile NPCC Reliability Assessment Summer 2016 Page 9 of 93 Northeast Power Coordinating Council Inc.

14 New York Summer 2016 Forecasted Peak: 33,360 MW (normal) and 35,647 MW (extreme) during the months of June through August, 2016 Summer 2015 Forecasted Peak: 33,567 MW (normal) and 35,862 MW (extreme) during the months of June through August, 2015 Summer 2015 Actual Peak: 31,138 MW on July 29, 2015 at HB16 EDT Figure 3 3: New York Summer 2016 Weekly Demand Profile NPCC Reliability Assessment Summer 2016 Page 10 of 93 Northeast Power Coordinating Council Inc.

15 Ontario Summer 2016 Forecasted Peak: 22,587 MW (normal) and 24,598 (extreme), week beginning July 3, 2016 Summer 2015 Forecasted Peak: 22,991 MW (normal) and 24,814 (extreme), week beginning July 5, 2015 Summer 2015 Actual Peak: 22,516 MW, on July 28, 2015 at HE17 EST Figure 3 4: Ontario Summer 2016 Weekly Demand Profile NPCC Reliability Assessment Summer 2016 Page 11 of 93 Northeast Power Coordinating Council Inc.

16 Québec Summer 2016 Forecasted Peak: 20,724 MW, (normal) and 21,327 MW (extreme) week beginning August 14, 2016 Summer 2015 Forecasted Peak: 21,090 MW, (normal) and 21,936 MW (extreme) week beginning August 9, 2015 Summer 2015 Actual Peak: 20,766 MW, on August 19, 2015 at 18h00 EST Figure 3 5: Québec Summer 2016 Weekly Demand Profile NPCC Reliability Assessment Summer 2016 Page 12 of 93 Northeast Power Coordinating Council Inc.

17 4. Resource Adequacy NPCC Summary for Summer 2016 The assessment of resource adequacy indicates the week with the highest coincident NPCC demand is the week beginning July 3, 2016 (106,390 MW). Detailed Projected Load and Capacity Forecast Summaries specific to NPCC and each Area are included in Appendix I. Table AP 1, Appendix I reflects the NPCC normal load and capacity summary for the 2016 Summer Operating Period. Appendix I, Tables AP 2 through AP 6, contain the normal load forecast and capacity summary for each NPCC Reliability Coordinator. Each entry in Table 4 1 is simply the aggregate of the corresponding entry for the five NPCC Reliability Coordinators. It summarizes the load and capacity situation for the peak week beginning July 3, 2016 compared to the Summer 2015 forecasted peak week (week beginning July 5, 2015). Table 4 1: Comparison of Resource Adequacy between the Summer 2016 and 2015 Forecasts All values in MW 2016 Forecast 2015 Forecast Difference Installed Capacity 158, ,112 1,382 *Net Interchange with areas outside NPCC 775 1, Total Capacity 159, , Demand 106, ,440 1,050 Interruptible load 2,860 2, Maintenance/Derate 23,368 23, Required Reserve 8,950 8, Unplanned Outages 8,413 8, Net Margin 15,008 14, Bottled Capacity QC/Maritimes to NPCC 5,746 3,606 2,140 Revised Net Margin 9,262 10,548 1,286 Week Beginning 3 Jul 16 5 Jul 15 NPCC Reliability Assessment Summer 2016 Page 13 of 93 Northeast Power Coordinating Council Inc.

18 The Revised Net Margin for the 2016 summer capacity period is a decrease from the previous summer assessment. This adjustment can be attributed to the bottling of resources in the Quebec Area, despite the increased installed capacity total for the NPCC area. The following sections detail the summer 2016 capacity analysis for each Reliability Coordinator and the NPCC region. Maritimes The Maritimes Area declared installed capacity is scheduled to be operational for the summer period; the net margins calculated include derates for variable generation (wind and hydro flows), ambient temperatures and scheduled out of service generation. Imports into the Maritimes Area are not included unless they have been confirmed released capacity from their source. Therefore, unless forced generator outages were to occur, there would not be any further reduction in the net margin. As part of the planning process, dual fueled units will have sufficient supplies of heavy fuel oil (HFO) on site to enable sustained operation in the event of natural gas supply interruptions. Table 1.1 conveys the Maritimes anticipated operable capacity margins for the normal and extreme load forecasts of the summer assessment period during the Maritimes forecasted peak week. Table 4 2: Maritimes Operable Capacity for 2016 Summer 2016 Normal Forecast Extreme Forecast Installed Capacity 7,795 7,795 Net Interchange 0 0 Total Capacity 7,795 7,795 Demand Response (+) Known Maintenance & Derates ( ) 2,089 2,089 Operating Reserve Requirement ( ) Unplanned Outages ( ) Peak Load Forecast 3,606 3,859 Operating Margin (MW) 1,282 1,031 Operating Margin (%) New England New England conducts an Installed Capacity and Operable Capacity assessment comparison recognizing normal peak demand forecasts to determine New England NPCC Reliability Assessment Summer 2016 Page 14 of 93 Northeast Power Coordinating Council Inc.

19 capacity margins. In determining the capacity margins, adjustments may be made to the available capacity based on operating experience. An example would be to adjust the available capacity from natural gas fired generation during pipeline maintenance and construction. The capacity margin is evaluated two ways. The first method is based on the resources obligation from the Forward Capacity Market, referred to as the Capacity Supply Obligation (CSO). The CSO is a generator s obligation to satisfy New England s Installed Capacity Requirement (ICR) through a Forward Capacity Auction (FCA). The second method is based on the resource s actual Seasonal Claimed Capability (SCC). The SCC is recognized as a generator s maximum output established through seasonal audits and reflected as capacity throughout this report, utilized in Table 4 1, Table 4 3, Table 4 4 and Appendix 1; AP 1 and AP 3 Tables. Table 4 3: New England Installed and Operable Capacity for Normal Forecast Normal Demand Forecast 17 Jul 2016 Operable Capacity + Non Commercial Capacity 29,734 30,247 Net Interchange (+) 1,062 1,062 Total Capacity 30,796 31,309 Peak Normal Demand Forecast 26,704 26,704 CSO Interruptible Load (+) Known Maintenance + Derates ( ) Operating Reserve Requirement MW ( ) 2,305 2,305 Unplanned Outages and Gas at Risk( ) 2,100 2,100 Operable Capacity Margin MW Operable Capacity Margin % SCC Furthermore, New England performs an Installed Capacity and Operable Capacity assessment comparison recognizing extreme demand forecasts to further evaluate New England capacity risks. This broadened approach helps Operations identify potential capacity concerns for the upcoming capacity period and prepare for severe demand conditions. The analysis in Table 1.3 below, shows the further reduction in Operable Capacity Margin recognizing these factors. The Net Interchange in these capacity assessment only takes into account capacity that has cleared in capacity markets, which is much lower than actual transmission transfer capabilities. If extreme summer forecast conditions materialize, New England will need to rely on import capabilities from NPCC Reliability Assessment Summer 2016 Page 15 of 93 Northeast Power Coordinating Council Inc.

20 neighboring Areas, as well as an implementation of Emergency Operating Procedures (EOPs). These actions are anticipated to provide sufficient energy or load relief to cover the operable capacity deficiency identified in the Extreme Demand Forecast. Table 4 4: New England Installed and Operable Capacity for Extreme Forecast Extreme Demand Forecast 17 Jul 2016 Operable Capacity + Non Commercial Capacity 29,734 30,247 Net Interchange (+) 1,062 1,062 Total Capacity 30,796 31,309 Peak Extreme Demand Forecast 29,042 29,042 CSO Interruptible Load (+) Known Maintenance + Derates ( ) Operating Reserve Requirement MW ( ) 2,305 2,305 Unplanned Outages and Gas at Risk( ) 2,100 2,100 Operable Capacity Margin MW 2,097 1,584 Operable Capacity Margin % SCC New York New York determines its operating margin by comparing the normal seasonal peak forecast with the projected Installed Capacity adjusted for seasonal operating factors. Installed Capacity is based on seasonal Dependable Maximum Net Capability (DMNC), tested seasonally, for all traditional thermal and large hydro generators. Wind generators are counted at nameplate for Installed Capacity and seasonal derates are applied. Net Interchange is based on Unforced Capacity Deliverability Rights (UDR), which is capacity provided by controllable transmission projects, that provide a transmission interface to the NYCA. Interruptible Load includes Emergency Demand Response Programs and Special Case Resources. Known Maintenance and Derates includes generator maintenance outages known at the time of this writing and derates for renewable resources such as wind, hydro, solar and refuse, based on historical performance data. The NPCC Operating Reserve Requirement for New York is one anda half times the largest single generating source contingency in the NYCA. In November 2015, the NYISO began procuring operating reserve of two times (2,620 MW) the largest single generating source contingency to ensure compliance with a New York State NPCC Reliability Assessment Summer 2016 Page 16 of 93 Northeast Power Coordinating Council Inc.

21 Reliability Council Rule. Unplanned Outages are based on expected availability of all generators in the NYCA based on historic availability. Historic availability factors in all forced outages include those due to weather and availability of fuel. The values in Table 1.4 are anticipated quantities as of the time of publishing this report. Finalized values are available in the NYISO Load & Capacity Data Gold Book 5 published annually in late April. Table 4 5: New York Operable Capacity Forecast Summer 2016 Normal Forecast Extreme Forecast Installed Capacity 38,535 38,535 Net Interchange 1,769 1,769 Total Capacity 40,304 40,304 Demand Response (+) 1,325 1,325 Known Maintenance & Derates ( ) 1,245 1,245 Operating Reserve Requirement ( ) 2,620 2,620 Unplanned Outages ( ) 3,532 3,532 Peak Load Forecast 33,360 35,647 Operating Margin (MW) 872 1,415 Operating Margin (%) Ontario The Ontario reserve requirement is expected to be met for the summer months of 2016 under normal weather conditions. However, as indicated in Table 1.5., a negative operating margin is observed under the extreme peak demand forecast scenario. This adequacy assessment was made without including potential imports from IESO s neighboring entities (capability of 5,200 MW) and thus should not seen as a cause for concern. Ontario expects to have a sizeable portion of its nuclear fleet (up to 5,000 MW) on outage at the beginning of the summer but the bulk of these units will be made available well in advance of the forecasted 2016 summer peaks. 5 Planning Data and Reference Docs NPCC Reliability Assessment Summer 2016 Page 17 of 93 Northeast Power Coordinating Council Inc.

22 Table 4 6: Ontario Operable Capacity Forecast Summer 2016 Normal Forecast Extreme Forecast Installed Capacity 36,427 36,427 Net Interchange 0 0 Demand Response Total Capacity 36,427 36,427 Known Maintenance & Derates 10,117 10,117 Operating Reserve Requirement 1,632 1,632 Unplanned Outages 1,303 1,303 Peak Load Forecast 22,587 24,598 Operating Margin (MW) 1, Operating Margin (%) The forecast energy production capability of the Ontario generators is calculated on a month by month basis. Monthly energy production capabilities for the Ontario generators are provided by market participants or calculated by the IESO. They account for fuel supply limitations, scheduled and forced outages and deratings as well as environmental and regulatory restrictions. The results in Table 1.6 indicate that occurrences of unserved energy are not expected over the summer 2016 period. Based on these results it is anticipated that Ontario will be energy adequate for the normal weather scenario for the review period. Table 4 7: Ontario Energy Production Capability Forecast by Month Month Forecast Energy Production Capability (GWh) Forecast Energy Demand (GWh) May ,488 10,530 June ,025 11,376 July ,587 11,847 Aug ,770 11,712 Sept ,345 10,875 NPCC Reliability Assessment Summer 2016 Page 18 of 93 Northeast Power Coordinating Council Inc.

23 Québec The Québec area anticipates adequate resources to meet demand for the 2016 summer season. The current 2016 peak forecast is 20,724 MW and the forecasted operating margin is 10,130 MW for the peak week, beginning August 14. This includes known maintenance and derates of 9,874 MW, including scheduled generator maintenance and hydraulic, as well as mechanical, restrictions and wind generator derating. The following table shows the factors included in the operating margin calculation. Table 4 8: Adequacy projections for Summer 2016 Summer 2016 Normal Load Forecast (MW) Extreme Load Forecast (MW) Installed Capacity 45,484 45,484 Net Interchange (+) 2,056 2,056 Demand Response (+) 0 0 Total Capacity 43,428 43,428 Known Maintenance & Derates ( ) 9,874 9,874 Operating Reserve Requirement ( ) 1,500 1,500 Unplanned Outages ( ) 1,200 1,200 Peak Load Forecast 20,724 21,327 Operating Margin 10,130 9,527 Operating Margin (%) Québec area's energy requirements are met for the greatest part by hydro generating stations located on different river systems and scattered over a large territory. The major plants are backed by multi annual reservoirs (water reserves lasting more than one year). A single year of low water inflow cannot adversely impact the reliability of energy supply. However, a series of a few consecutive dry years may require some operating measures such as the reduction of exports or capacity purchase from neighbouring areas. To assess its energy reliability, Hydro Québec has developed an energy criterion stating that sufficient resources should be available to go through a sequence of two consecutive years of low water inflows totalling 64 TWh, or a sequence of four NPCC Reliability Assessment Summer 2016 Page 19 of 93 Northeast Power Coordinating Council Inc.

24 years totalling 98 TWh, and having a 2 percent probability of occurrence. The use of operating measures and the hydro reservoirs should be managed accordingly. Reliability assessments based on this criterion are presented three times a year to the Québec Energy Board. Such documents can be found on the Régie de l Énergie du Québec website energie.qc.ca/audiences/suivis/suivi_hqd_d _CriteresFiabilite.html NPCC Reliability Assessment Summer 2016 Page 20 of 93 Northeast Power Coordinating Council Inc.

25 Error! Not a valid bookmark self reference. below summarizes projected capacity and margins by Reliability Coordinator area. Appendix I shows these projections for the entire summer operation period. Table 4 9: Summary of Projected Capacity by Reliability Coordinator Area Measure Week Beginning Sundays Installed Capacity MW Net Interchange MW Total Capacity MW Demand Forecast MW Interrupt. Load MW Known Maint./ Derat. MW Required Operating Reserve MW Unplanned Outages MW Net Margin MW NPCC NPCC Peak Week 3 Jul , , ,390 2,860 23,368 8,950 8,413 15,008 Maritimes Area Peak Week 1 May 16 7, ,795 3, , ,282 New England Lowest Net Margin 1 May 16 7, ,795 3, , ,282 NPCC Peak 3 Jul 16 7, ,801 3, , ,630 Area Peak Week 17 Jul 16 30,247 1,062 31,309 26, ,305 2, Lowest Net Margin 5 Jun 16 30, ,088 26, ,305 2, NPCC Peak Week 3 Jul 16 30,247 1,062 31,309 26, ,305 2, New York Area Peak Week 5 Jun 16 38,535 1,769 40,304 33,360 1,325 1,529 2,620 3, Lowest Net Margin 5 Jun 16 38,535 1,769 40,304 33,360 1,325 1,529 2,620 3, NPCC Peak Week 3 Jul 16 38,535 1,769 40,304 33,360 1,325 1,245 2,620 3, Ontario Area Peak Week 3 Jul 16 36, ,427 22, ,117 1,632 1,303 1,462 Lowest Net Margin 26 Jun 16 36, ,427 22, ,365 1,635 1,463 1,418 NPCC Peak Week 3 Jul 6 36, ,427 22, ,117 1,632 1,303 1,462 Québec Area Peak Week 1 May 16 45,484 1,976 43,508 23, ,866 1,500 1,200 4,790 Lowest Net Margin 1 May 16 45,484 1,976 43,508 23, ,866 1,500 1,200 4,790 NPCC Peak Week 3 Jul 16 45,484 2,056 43,428 20, ,966 1,500 1,200 10,304 NPCC Reliability Assessment Summer 2016 Page 21 of 93 Northeast Power Coordinating Council Inc.

26 Generation Resource Changes The following table lists the recent and anticipated generation resource additions, changes and retirements. Table 4 10: Resource Changes from Summer 2015 through Summer 2016 Area Generation Facility Nameplate Capacity (MW) Fuel Type In Service Date Maritimes COMFIT 6.7 Biomass Q New England COMFIT 2.0 Tidal Q COMFIT 47.3 Wind Q Cape Sharpe 4.0 Tidal Q Total Addition 60 Various Adjustments 15 Wind / Biomass Net Change 75 Oakfield II Wind 148 Wind Q Passadumkeag Windpark 43 Wind Q Future Gen Wind Farm 8 Wind Q WED Coventry 1 6 Wind 15 Wind Q NECCO Cogen 5 Natural Gas Q Harrington Street PV Project (QF) Total Retirement 0 Total Addition 229 Various Adjustments 308 Net Change Solar Q NPCC Reliability Assessment Summer 2016 Page 22 of 93 Northeast Power Coordinating Council Inc.

27 Area Generation Facility Nameplate Capacity (MW) Fuel Type In Service Date New York Bowline 2 (uprate) 374 Nat Gas Q Astoria GTs 8, 10 & Oil/Kerosene Q Huntley Bit Coal Q Huntley Bit Coal Q Dunkirk Bit Coal Q Ravenswood Kerosene/Nat Gas Q Ravenswood Nat Gas Q Ravenswood Kerosene/Nat Gas Q Total Addition 374 Subtractions 683 Net DMNC Adjustments 144 Net Change 165 NPCC Reliability Assessment Summer 2016 Page 23 of 93 Northeast Power Coordinating Council Inc.

28 Area Generation Facility Nameplate Capacity (MW) Fuel Type In Service Date Ontario Nuclear adjustments 31 Nuclear Q Thunder Bay G3 Biomass Conversion 153 Biomass Q Adelaide Wind Power Project 40 Wind Q Dufferin Wind Farm 91.3 Wind Q Goshen Wind Energy Centre 102 Wind Q Grand Renewable Energy Park Wind Q Adelaide Wind Energy Centre 60 Wind Q Bornish Wind Energy Centre 73.5 Wind Q Jericho Wind Energy Centre 150 Wind Q Grand Renewable Energy Park 100 Solar Q Emarald Energy from Waste 14.7 Biomass Q Goulais Wind Farm 25 Wind Q West Windsor Power 8 Gas Q Iroquois Falls Improvement 23 Hydro Q Thunder Bay Condensing Turbine Project 40 Biomass Q K2 Wind Project 270 Wind Q Kingston Solar 100 Solar Q Bow Lake Phase 1 20 Wind Q Bow Lake Phase 2b 40 Wind Q Cedar Point Wind Power Project Phase II 100 Wind Q Northland Power Solar Abitibi 10 Solar Q Northland Power Solar Empire 10 Solar Q Northland Power Solar Martin's Meadows 10 Solar Q Northland Power Solar Long Lake 10 Solar Q NPCC Reliability Assessment Summer 2016 Page 24 of 93 Northeast Power Coordinating Council Inc.

29 Area Generation Facility Nameplate Capacity (MW) Fuel Type In Service Date Grand Valley Wind Farms (Phase 3) 40 Wind Q Armow Wind 180 Wind Q Grand Bend Wind Farm 99.3 Wind Q Green Electron Power Plant 298 Gas Q Gitchi Animki (White River) Generating Station Total Retirement 53 Total Addition 2,266.5 Net Change 2, Hydro Q Québec La Romaine Hydro Q Wind Additions 379 Wind Q Generation Adjustments 22 Hydro Q Total Retirement 0 Total Addition 649 Net Change 671 Maritimes There are generation projects of new capacity scheduled to be put in service during this summer assessment period that total 60 MW. The additions include one wind project of 47.3 MW, one biomass project of 6.7 MW and two tidal projects that total 6.0 MW. All of these new additions are scheduled to be in service by the week of June 5, New England Following the 2015 Summer Assessment period, new generation improvements include multiple wind resources (Oakfield Wind II, Passadumkeag, Future Gen Wind Farm, and WED Coventry) with nameplates totaling 214 MW. Harrington Street PV, a 10 MW PV resource and NECCO Cogen, a 5 MW (natural gas) resource are expected to become commercial in the Summer 2016 Operating Period. New England capacity Net Total is 11 MW less than the 2015 summer assessment, reflecting renewable resource derates as NPCC Reliability Assessment Summer 2016 Page 25 of 93 Northeast Power Coordinating Council Inc.

30 well as maximum generator output values for all generators, established through the Seasonal Claimed Capability audits conducted within New England. New York Since the summer 2015 season, several changes to generation in New York have occurred. Retirements totaling 619 MW nameplate have occurred with an additional 64 MW nameplate expected to retire or mothball in Q Of these retirements, 536 MW were coal fired units. Ontario By the end of the summer 2016 assessment period, the total capacity in Ontario is expected to increase by 2,213.5 MW compared to the total installed capacity at the end of the 2015 summer assessment period. When looking specifically at the 2016 summer assessment timeframe, the expected increase in capacity is 836 MW (based on effective values), which includes: 479 MW of wind, 40 MW of solar, 19 MW of hydro generation and 298 MW of gas generation. This equates to an operable capacity of 391 MW. Québec For the summer 2016 Assessment, nameplate wind capacity of the Québec area has reached 3,260 MW, a 379 MW increase since the last summer assessment. La Romaine 1 Hydro Generating Station, 270 MW, have been successfully commissioned by the end of As the Québec area is winter peaking, generation project commissioning is usually scheduled during autumn in preparation for the following winter peak period. NPCC Reliability Assessment Summer 2016 Page 26 of 93 Northeast Power Coordinating Council Inc.

31 Fuel Infrastructure by Reliability Coordinator area The following figures depict installed generation resource profiles for each Reliability Coordinator area and for the NPCC Region by fuel supply infrastructure as projected for the NPCC coincident peak week. Figure 4 1: Installed Generation Fuel Type by Reliability Coordinator Area NPCC Reliability Assessment Summer 2016 Page 27 of 93 Northeast Power Coordinating Council Inc.

32 Figure 4 22: Installed Generation Fuel Type for NPCC NPCC Reliability Assessment Summer 2016 Page 28 of 93 Northeast Power Coordinating Council Inc.

33 Wind and Solar Capacity Analysis by Reliability Coordinator Area For the upcoming 2016 Summer Operating Period, wind and solar capacity accounts for approximately 6.38 percent of the total NPCC Capacity during the coincident peak load. This accounts for 6.04 percent wind and.34 percent solar. Reliability Coordinators have distinct methods of accounting for both of these types of generation. The Reliability Coordinators continue to develop their knowledge regarding the operation of wind and solar generation in terms of capacity forecasting and utilization factor. The table below illustrates the nameplate wind capacity in NPCC for the 2016 Summer Operating Period. The Maritimes, IESO, NYISO and Québec areas include the entire nameplate capacity in the Installed Capacity section of the Load and Capacity Tables and use a derate value in the Known Maintenance/Constraints section to account for the fact that some of the capacity will not be online at the time of peak. ISO NE reduces the nameplate capacity and includes this reduced capacity value directly in the Installed Capacity section of the Load and Capacity Table. Please refer to Appendix II, for information on the derating methodology used by each of the NPCC Reliability Coordinators. The table below also illustrates the nameplate solar capacity in NPCC for the 2016 Summer Operating Period. The IESO and NYISO include the entire nameplate capacity in the Installed Capacity section of the Load and Capacity Tables and use a derate value in the Known Maintenance/Constraints section to account for the fact that some of the capacity will not be online at the time of peak. ISO NE reduces the nameplate capacity and includes this reduced capacity value directly into the Installed Capacity section of the Load and Capacity Table. Please refer to Appendix II for information on the derating methodology used by each of the NPCC Reliability Coordinators. NPCC Reliability Assessment Summer 2016 Page 29 of 93 Northeast Power Coordinating Council Inc.

34 Table 4 11: NPCC Wind and Solar Capacity Reliability Coordinator Nameplate Wind Capacity (MW) Wind Capacity After Applied Derating Factor (MW) Nameplate Solar Capacity (MW) Solar Capacity After Applied Derating Factor (MW) NBP SO 1, ISO NE 1, , NYISO 1, IESO 3, Québec 3, Total 10, , *Total nameplate capacity in New York is 1,754 MW, however only 1,446 MW participate in the ICAP market. Maritimes Wind projected capacity is derated to its demonstrated output for each summer or winter capability period. In New Brunswick and Prince Edward Island the wind facilities that have been in production over a three year period, a derated monthly average is calculated using metering data from previous years over each seasonal assessment period. For those that have not been in service that length of time (three years), the deration of wind capacity in the Maritimes Area is based upon results from the Sept. 21, 2005 NBSO report Maritimes Wind Integration Study. This wind study showed that the effective capacity from wind projects, and their contribution to loss of load expectation (LOLE), was equal to or better than their seasonal capacity factors. The Northern Maine Independent System Administrator (NMISA) uses a fixed capacity factor of 30 percent for both the summer and winter assessment periods. Nova Scotia applies an 8 percent capacity value to installed wind capacity (92 percent derated). This figure was calculated via a Cumulative Frequency Analysis of historical wind data ( ). The top 10 percent of load hours were analyzed to reflect peak load conditions, and a 90 percent confidence limit was selected as the critical value. This analysis showed that NS Power can expect to have at least 8 percent of installed wind capacity online and generating in 90 percent of peak hours. NPCC Reliability Assessment Summer 2016 Page 30 of 93 Northeast Power Coordinating Council Inc.

35 New England During the 2016 summer assessment period, ISO NE has derated the wind resources by 90.7 percent as a result of established summer Claimed Capability Audits (CCAs). More than 1,000 MW of wind resources are currently interconnected to the grid and approximately 4,000 MW of wind powered generation facilities continue to make up a significant portion of the proposed generation projects in New England. Distributed PV has grown substantially in New England over the last several years. By the end of 2015, 1,325 MW of nameplate PV was installed within the region. For the 2016 summer assessment period, ISO NE estimates that nearly 423 MW of summer peak demand reduction will result from behind the meter PV. Expected summer peak load reductions reflect approximately 40 percent of nameplate PV (i.e., a derate of 60 percent), based on ISO NE s analysis of PV performance during peak load conditions. New York In 2016, there is expected to be 6,174 MW of nameplate renewable resource capacity in New York. This includes 1,754 MW of nameplate wind and 32 MW of nameplate solar capacity. As indicated above only 1,461 MW of nameplate wind capacity participates in the New York ICAP market. The ICAP nameplate capacity is counted at full value towards the Installed Capacity for New York. The wind and solar capacities are derated by 84 percent and 50 percent respectively based on historical performance data when determining operating margins. In 2015, 4,036 gigawatt hours of New York s electricity was produced by wind and solar resources representing approximately 2.8 percent of New York s electric generation. Ontario For Ontario, monthly Wind Capacity Contribution (WCC) values are used to forecast the contribution from wind generators. WCC values in percentage of installed capacity are determined from a combination of actual historic median wind generator contribution and the simulated 10 year wind historic median contribution at the top 5 contiguous demand hours of the day for each winter and summer season, or shoulder period month. The simulated 10 year historic wind data will be included until 10 years of actual wind data is accumulated; at which point the simulated wind data will be phased out of the WCC calculation. Similarly, monthly Solar Capacity Contribution (SCC) values are used to forecast the contribution expected from solar generators. SCC values in percentage of installed capacity are determined by calculating the simulated 10 year solar historic median contribution at the top 5 contiguous demand hours of the day for each winter and NPCC Reliability Assessment Summer 2016 Page 31 of 93 Northeast Power Coordinating Council Inc.

36 summer season, or shoulder period month. As actual solar production data becomes available in future, the process of combining actual historical solar data and the simulated 10 year historical solar data will be incorporated into the SCC methodology, until 10 years of actual solar data is accumulated; at which point the simulated data will be phased out of the calculation. From an adequacy assessment perspective, although the entire installed capacity of the variable generation is included in Ontario s total installed capacity number, the appropriate penalty is applied to the Known Maint./Derat./Bottled Cap. Québec In the Québec area, wind generation plants are owned and operated by Independent Power Producers (IPPs). Nameplate capacity will be 3,260 MW for the 2016 summer peak period of which 212 MW is under contract with Hydro Québec Production (HQP Generator Owner). The rest, 3,048 MW, is under contract with Hydro Québec Distribution (HQD Resources Planner and Load Supply Entity). During the summer period, 100 percent of the wind installed capacity is derated. There is no solar generation in the Québec area. NPCC Reliability Assessment Summer 2016 Page 32 of 93 Northeast Power Coordinating Council Inc.

37 Demand Response Programs Each Reliability Coordinator utilizes various methods of demand management. The table below summarizes demand response available within the NPCC area. Table 4 12: Summary of Active Demand Response Programs Reliability Coordinator area Active Demand Response Available Summer 2016 Active Demand Response Available Summer 2015 Maritimes New England New York 1,325 1,210 Ontario Québec 0 0 Total 2,860 3,030 Maritimes Interruptible loads are forecast on a weekly basis and range between 269 MW and 364 MW. The values can be found in Table AP 2 and are available for use when corrective action is required within the Area. New England For the 2016 summer, ISO NE has 557 MW of active demand resources that are expected to be available on peak. The active demand resources consist of Real Time Demand Response (RTDR) of 372 MW and real time emergency generation (RTEG) of 185 MW, which can be activated with the implementation of ISO NE Operating Procedure No. 4 Action during a Capacity Deficiency (OP 4) 7. These active demand resources can be used to help mitigate an actual or anticipated capacity deficiency. OP 4 Action 2 is the dispatch of Real Time Demand Resources, which is implemented in order to manage operating reserve requirements. Action 6, which is the dispatch of Real Time Emergency Generation Resources, may be implemented to maintain 10 minute operating reserve. 7 ISO New England Operating Procedure No. 4 can be found at ne.com/participate/rulesprocedures/operating procedures NPCC Reliability Assessment Summer 2016 Page 33 of 93 Northeast Power Coordinating Council Inc.

38 In addition to active demand resources, 1,839 MW of passive demand resources (i.e., energy efficiency and conservation) are treated as demand reducers in this report and are accounted for in determining the net load forecast of 26,704 MW. Without the effects of passive demand resources, the 2016 summer forecast would equate to 28,543 MW. Passive demand measures include installed products, equipment, and systems, as well as services, practices, and strategies, at end use customer facilities that result in additional and verifiable reductions in the total amount of electrical energy used during on peak hours. The amount of energy efficiency is based on capacity supply obligations (CSO) in the Forward Capacity Market (FCM). New York The NYISO has three demand response programs to support system reliability. The NYISO currently projects 1,325 MW of total demand response available for the 2016 summer season, approximately consisting of 1,248 MW of SCR and 77 MW of EDRP resources. The Emergency Demand Response Program (EDRP) provides demand resources an opportunity to earn the greater of $500/MWh or the prevailing locational based marginal price ( LBMP ) for energy consumption curtailments provided when the NYISO calls on the resource. Resources must be enrolled through Curtailment Service Providers ( CSPs ), which serve as the interface between the NYISO and resources, in order to participate in EDRP. There are no obligations for enrolled EDRP resources to curtail their load during an EDRP event. The Installed Capacity (ICAP) Special Case Resource program allows demand resources that meet certification requirements to offer Unforced Capacity ( UCAP ) to Load Serving Entities ( LSEs ). The load reduction capability of Special Case Resources ( SCRs ) may be sold in the ICAP Market just like any other ICAP Resource; however, SCRs participate through Responsible Interface Parties (RIPs), which serve as the interface between the NYISO and the resources. RIPs also act as aggregators of SCRs. SCRs that have sold ICAP are obligated to reduce their system load when called upon by the NYISO with two or more hours notice, provided the NYISO notifies the Responsible Interface Party a day ahead of the possibility of such a call. In addition, enrolled SCRs are subject to testing each Capability Period to verify their capability to achieve the amount of enrolled load reduction. Failure of an SCR to reduce load during an event or test results in a reduction in the amount of UCAP that can be sold in future periods and could result in penalties assessed to the applicable RIP in accordance with the ICAP/SCR program rules and procedures. Curtailments are called by the NYISO when reserve shortages are anticipated or during other emergency operating conditions. Resources NPCC Reliability Assessment Summer 2016 Page 34 of 93 Northeast Power Coordinating Council Inc.

39 may register for either EDRP or ICAP/SCR but not both. In addition to capacity payments, RIPs are eligible for an energy payment during an event, using the same calculation methodology as EDRP resources. The Targeted Demand Response Program ( TDRP ), introduced in July 2007, is a NYISO reliability program that deploys existing EDRP and SCR resources on a voluntary basis, at the request of a Transmission Owner, in targeted subzones to solve local reliability problems. The TDRP program is currently available in Zone J, New York City. Ontario Ontario s demand response is comprised of the following programs: Peaksaver, dispatchable loads, DR pilot project participants, Demand Response Auction participants, Capacity Based Demand Response (CBDR), time of use (TOU) tariffs and the Industrial Conservation Initiative (ICI). Dispatchable loads and CBDR resources can be dispatched in the same way that generators are, whereas TOU, ICI, conservation impacts and embedded generation output are factored into the demand forecast as load modifiers. The capacity of the demand response program consists of 369 MW of dispatchable load, 159 MW of CBDR resources, 163 MW of Peaksaver resources, 79 MW of pilot project resources and 392 MW of Demand Response Auction resources. Although the total demand response capacity is 1,161 MW, the effective capacity is 674 MW due to program restrictions and market participant actions. During peak periods of the year, market participants take independent action to reduce their consumption for economic reasons, reducing the available capacity for demand measures. The IESO expanded its demand response programs for the summer of 2016 to include two new programs. In December 2015, a Demand Response Auction was held by the IESO to begin replacing expiring multi year contracts with a more cost competitive mechanism. The successful Demand Response Auction participants are expected to be ready for energy market participation starting May 1 st, In April 2015, a competitive Request for Proposal was issued to demand side resources to procure price responsive consumption capability for a pilot project. The purpose of the pilot was to investigate opportunities to enhance DR participation in meeting system needs through closer integration with the dayto day operations of the system. The DR Pilot program resources are expected to be in service for summer NPCC Reliability Assessment Summer 2016 Page 35 of 93 Northeast Power Coordinating Council Inc.

40 Québec Demand Response programs are neither required nor available during the summer operating period. NPCC Reliability Assessment Summer 2016 Page 36 of 93 Northeast Power Coordinating Council Inc.

41 5. Transmission Adequacy Regional Transmission studies specifically identifying interface transfer capabilities in NPCC are not normally conducted. However, NPCC uses the results developed in each of the NPCC Reliability Coordinator areas and compiles them for all major interfaces and for significant load areas (Appendix III). Recognizing this, the CO 12 working group reviewed the transfer capabilities of NPCC under normal and peak demand configurations. The following is a transmission adequacy assessment from the perspective of the ability to support energy transfers for the differing levels: Inter Region, Inter Area as well as noteworthy transmission improvements within each Reliability Coordinator Area. Inter Regional Transmission Adequacy Ontario Manitoba Interconnection The Ontario Manitoba interconnection consists of two 230 kv circuits and one 115kV circuit. The transfers on the 230 kv are constrained by stability and thermal limitations; 288 MW for exports and imports. The transfers on the 115 kv is limited to 68 MW into Ontario, with no flow out allowed. Ontario Minnesota Interconnection The Ontario Minnesota interconnection consists of a single 115 kv circuit, with transfers constrained by stability and thermal limitations to 150 MW exports and 100 MW imports. Ontario Michigan Interconnection The Ontario Michigan interconnection consists of two 230/345 kv circuits, one 230/115 kv circuit, and one 230 kv circuit which are all constrained by thermal limitations. There are four phase angle regulators presently in service with an export limit of 1,700 MW and an import limit of 1,700 MW. New York PJM Interconnection The New York PJM interconnection consists of one PAR controlled 500/345 kv circuit, one uni directional DC cable into New York, one uni directional DC/DC controlled 345 kv circuit into New York, two free flowing 345 kv circuits, a VFT controlled 345/230 kv circuit, three PAR controlled 345/230 kv circuits, two free flowing 230 kv circuits, three 115 kv circuits, and a 138/69 kv network serving a load pocket through the New York system from PJM. NPCC Reliability Assessment Summer 2016 Page 37 of 93 Northeast Power Coordinating Council Inc.

42 Two new tap stations, Five Mile Road and Pierce Brook, are being added on the 345 kv Homer City Stolle Road line between New York and PJM. Five Mile Road is in service and is located on the New York side of the system. Pierce Brook is expected to be completed by Q and will be located in PJM. The new stations will change the NY PJM interface definition by replacing the Homer City Stolle Road (37) line with the Pierce Brook Five Mile Road (37) line and Pierce Brook Homer City (48) line. Inter Area Transmission Adequacy Appendix III provides a summary of the Total Transfer Capabilities (TTC) on the interfaces between NPCC Reliability Coordinator areas and for some specific load zone areas. They also indicate the corresponding Available Transfer Capabilities (ATC) based on internal limitations or other factors and indicate the rationale behind reductions from the Total Transfer Capability. The table below, Table 6, summarizes the transfer capabilities between each region. Full details can be found in Appendix III. Table 5 1: Interconnection Total Transfer Capability Summary Area Total Transfer Capability (MW) Transfers from Maritimes to Québec 685 New England 1000 Transfers from New England to Maritimes 550 New York 1,840 Québec 1,370 Transfers from New York to New England 2,130 Ontario 1,900 PJM 1,615 Québec 1,040 NPCC Reliability Assessment Summer 2016 Page 38 of 93 Northeast Power Coordinating Council Inc.

43 Area Total Transfer Capability (MW) Transfer from Ontario to New York 1,950 Québec 2,047 Transfers from Québec to Maritimes (Madawaska Outage) radial load New England 2,275 New York 1,990 Ontario 2,800 Area Transmission Adequacy Assessment Transmission system assessments are conducted in order to evaluate the resiliency and adequacy of the bulk power transmission system. Within each region, Areas evaluate the ongoing efforts and challenges of effectively managing the reliability of the bulk transmission system and identifying transmission system projects that would address local or system wide improvements. The CO 12 Working Group reviewed the forecasted conditions for the summer 2016 operating period under normal and peak demand configurations, and have provided the following review as well as identified transmission improvements listed in Table 5 2. Table 5 2: NPCC Recent and Future Transmission Additions NPCC Sub Area Maritimes Transmission Project Voltage (kv) In Service Point Lepreau Terminal (upgrade) Memramcook Terminal (upgrade) 345 Q Q Keswick Terminal (upgrade) 345 Q Keswick Terminal (upgrade) 345 Q Melrose Terminal (new) 138 Q Line 1244 (new) 138 Q NPCC Reliability Assessment Summer 2016 Page 39 of 93 Northeast Power Coordinating Council Inc.

44 NPCC Sub Area New England New York Transmission Project Voltage (kv) In Service 341 Line (Lake Road West Farnum Substations) 366 Line (West Farnum Millbury Substations) 3271 Line (Card Lake Road Substations) 345 Q Q Q Lake Road SPS (Retirement) 345 Q Mainesburg Station (New PJM Station at NYCA Interface) 345 Q Five Mile Rd (New Station) 345 Q Moses Cap Banks 115 Q Pierce Brook (New PJM Station at NYCA Interface) Marcy South Series Compensation Ramapo Sugarloaf Rock Tavern (New Line) 345 Q Q Q Goethals Feeder Separation 345 Q Packard Series Compensation 230 Q Ontario Québec Huntley Cap Banks 230 Q Guelph Area Transmission Refurbishment New 16 mile line between La Romaine 2 substation and La Romaine 1 generating station 115 Q Q Maritimes The Maritimes bulk transmission system is projected to be adequate to supply the demand requirements for the Summer Operating Period. Part of the Total Transfer Capability (TTC) calculation with HQ is based on the ability to transfer radial loads onto the HQ system. The radial load value is calculated monthly and HQ will be notified of the changes (See Appendix III). NPCC Reliability Assessment Summer 2016 Page 40 of 93 Northeast Power Coordinating Council Inc.

45 New England The existing New England transmission system is projected to be sufficient for the 2016 summer assessment period. Transmission system upgrades continue to proceed in New England and ISO NE continually monitors and coordinates transmission facility outages in order to maintain reliability and reduce economic impact that may be associated with these transmission system outages and improvements. The Interstate Reliability Project (IRP), a portion of the New England East West Solution (NEEWS), is a major transmission project that offers further improvements to New England s transmission system. The 3271 line, a new 345 kv path in Connecticut from Card to Lake Road Substations, went into service during the summer 2015 assessment period. Two new 345 kv paths the 341 line from Lake Road to West Farnum Substations (Connecticut to Rhode Island) and the 366 line from West Farnum to Millbury Substations (Rhode Island to Massachusetts) have been placed into service during winter assessment period. These improvements allowed for the retirement of the Lake Road SPS (NPCC Type III) which was designed to protect for tortional stress placed upon the Lake Road Generation when the 330 line, 347 line or 3348 line would become reenergized post contingency. These upgrades have further improved Connecticut and Rhode Island import and export transfer capabilities and New England s east to west and west to east transfer capabilities. New York For the summer 2016 season New York does not anticipate any reliability issues for operating the bulk power system. The Transmission Owner Transmission Solutions (TOTS) consists of three distinct transmission projects approved by the PSC as part of the Indian Point Contingency Plan in October 2013 and are projected by the Transmission Owners to be in service by summer The objective of the plan is to increase transfer capability into Southeast New York. The Marcy South Series Compensation project includes adding compensation to the Marcy South transmission corridor through the installation of series capacitors, and includes re conductoring the Fraser Coopers Corners 345 kv line. The Rock Tavern Ramapo project will add a second Rock Tavern Ramapo 345 kv line and create a Sugarloaf 345/138 kv connection to the Orange and Rockland system. The Marcy South Series Compensation and Rock Tavern Ramapo projects together will increase the transfer capability from upstate to downstate New York. The Staten Island Unbottling project will relieve transmission constraints between Staten Island and the rest of New NPCC Reliability Assessment Summer 2016 Page 41 of 93 Northeast Power Coordinating Council Inc.

46 York City through the reconfiguration of two substations and the forced cooling of four existing 345 kv feeders. The Indian Point Contingency Plan also included 125 MW of additional demand response and combined heat and power resources to be implemented by Consolidated Edison, some of which is already in effect. Congestion in western NY is expected to increase, posing some challenges to operating the system as imports from Ontario will be restricted at times. However, this congestion should not impact overall reliable system operation. Series reactors are being installed to help alleviate this situation, and are expected in service prior to the summer 2016 peak. Ontario For the summer 2016 operating period, Ontario s transmission system is expected to be adequate with planned transmission system enhancements and scheduled transmissions outages. With all transmission elements in service, the theoretical maximum capability for exports from Ontario is up to 6,033 MW, and 6,580 MW for imports. These values represent theoretical levels that could be achieved only with a substantial reduction in generation dispatch in the West and Niagara transmission zones. In practice, the generation dispatch required for high import levels would rarely, if ever, materialize. Therefore, at best, due to internal constraints and external scheduling limitations, Ontario s current expected coincident import capability is approximately 5,200 MW with all transmission elements in service. Outages affecting neighboring jurisdictions can be found in Table 5 3: Area Transmission Outage Assessment. Based on the information provided, Ontario does not foresee any transmission issues for the summer 2016 season. Québec In the Québec Reliability Coordinator Area, most transmission line, transformer and generating unit maintenance is done during the summer period. Internal transmission outage plans are assessed to meet internal demand, firm sales, expected additional sales and additional uncertainty margins. They should not impact inter area transfer capabilities with neighboring systems. As shown in Table AP 6 (Appendix I), Known Maintenance/Derates vary between 9,786 to 12,533 MW. During the Summer Operating Period, some maintenance outages are scheduled on the interconnections. Maintenance is coordinated with neighboring Reliability Coordinator areas so as to leave maximum capability to summer peaking areas. NPCC Reliability Assessment Summer 2016 Page 42 of 93 Northeast Power Coordinating Council Inc.

47 Area Transmission Outage Assessment The section below outlines any known scheduled outages on interfaces between Reliability Coordinators. Maritimes Table 5 3: Area Transmission Outage Assessment Impacted Area Interface Impacted Planned Start Planned End Reduction in Limit NB/HQ NB/HQ Eel River Cct 2 Eel River Cct 1 18 Apr May MW both directions 30 May Jun MW both directions NB/NE Point Lepreau 1 April May MW Export NB/NE Keswick 2 Sept 16 9 Sept MW to 700 MW Export (Dependent of generation configuration in New England) New England Impacted Area Interface Impacted Planned Start Planned End Reduction in Limit New England Highgate 17 May May MW Import / 175 MW Export NPCC Reliability Assessment Summer 2016 Page 43 of 93 Northeast Power Coordinating Council Inc.

48 New York Impacted Area Interface Impacted Planned Start Planned End Reduction in Limit PJM HTP 1 Jan May MW Import PJM VFT 1 May 16 6 May MW Both Directions PJM Neptune 2 May 16 6 May MW Import HQ Cedars Dennison 3 May May MW Import ISONE CSC 9 May May MW Both Directions HQ Cedars Dennison 31 May Jun MW Import Ontario Beck Niagara Jun Jun MW Import 800 MW Export HQ Cedars Dennison 16 Jun Sep MW Import Ontario Impacted Area Interface Impacted Planned Start Planned End Reduction in Limit HQ D4Z 09 May May MW Import HQ B5D 01 May May MW Import 0 MW Export New York PA June June MW Import 750 MW Export NPCC Reliability Assessment Summer 2016 Page 44 of 93 Northeast Power Coordinating Council Inc.

49 Québec Impacted Area Interface Impacted Planned Start Planned End Reduction in Limit New Brunswick Madawaska 1 Jun 16 5 Nov MW Export 400 MW Import New Brunswick 3113 line 3 Jun Jun MW Export New England Phase II 1 Apr Jun MW Export New York GC1 Châteauguay 1200 MW Import 15 Apr May MW Import 400 MW Export NPCC Reliability Assessment Summer 2016 Page 45 of 93 Northeast Power Coordinating Council Inc.

50 6. Operational Readiness for 2016 Maritimes Voltage Control The Maritimes Area, in addition to the reactive capability of the generating units, employs a number of capacitors, reactors, synchronous condensers and a Static Var Compensator (SVC) in order to provide local area voltage control. Operational Procedures The Maritimes is a winter peaking area and because of this the possibility of light system loads along with high wind generator outputs could occur. If this scenario were to happen, procedures are in place to mitigate the event by taking corrective actions (up to and including the curtailment of wind resources). Any internal operating condition within the Maritimes will be handled with Short Term Operating Procedures (STOP). Wind Integration The monitoring of thermal unit dispatch under high wind / low load periods (e.g. shoulder season overnight hours) is an area of focus; work to assess steam unit minimum loads and minimum steam system configurations is ongoing. New England Voltage Control ISO NE manages and monitors both reactive resources and transmission voltages on the bulk power system. These elements are monitored in dedicated EMS reactive power displays, specific voltage / reactive transmission operating guides and via real time voltage transfer limit evaluation software. ISO NE also reviews and manages low side Load Power Factor requirements in the region which accounts for the potential impacts of the distribution load on the BES transmission performance. ISO NE also maintains a detailed set of generator voltage set points and appropriate operational bandwidths recognizing the lead/lag capabilities of the individual resources, which are monitored in real time within the EMS. In conjunction with the asset owners, ISO NE has developed a set of comprehensive normal, long term and short term voltages limits for the BES transmission system and communicates potential concerns with the Transmission Owners. Based on operational studies and experience, the impact of available dynamic and static reactive resources is accounted for in outage coordination and real time operating periods. NPCC Reliability Assessment Summer 2016 Page 46 of 93 Northeast Power Coordinating Council Inc.

51 Solar Integration (PV) With the integration of solar, New England experiences unique demand forecasting challenges. With nearly all of these resources located behind the meter and are small in comparison to conventional generators throughout the system, the power output is not dispatchable and appears as a demand reducer to the system operators. This creates unique challenges in the near term system load forecasting function of ISO NE as approximately 1,325 MW (nameplate) of PV had been installed by retail customers and local utilities as of the end of This capacity value is expected to increase over the next ten years to almost 3,300 MW nameplate, and the integration of solar and other renewable resources will continue to be of key importance. Zonal Load Forecasting New England continues to use a Metrix Zonal load forecast which produces a zonal load forecast for the eight regional load zones for up to six days in advance through the current operating day. This forecast enhances reliability on a zonal level by taking into account conflicting weather patterns. An example would be when the Boston zone is forecasted to be sixty five degrees while the Hartford area is forecasting ninety degrees. This zonal forecast ensures an accurate reliability commitment on a regional level. The eight zones are then summed for a total New England load. Summer Operable Capacity New England forecasts the 2016 summer peak to occur on week beginning July 17. The operable capacity margin calculation takes into account summer Peak Load Exposure (PLE) which covers operating periods from the first full week of June through the last full week in August. The PLE was developed and implemented to help mitigate the effects of abnormal weather during generator maintenance/outage scheduling and help forecast conservative operable capacity margins Operating Week 50/50 PLE Forecast 50/50 Demand Forecast MW Delta 5 Jun 16 26,704 21,739 4, Jun 16 26,704 23,007 3, Jun 16 26,704 23,560 3, Jun 16 26,704 23,664 3,040 3 Jul 16 26,704 24,978 1,726 NPCC Reliability Assessment Summer 2016 Page 47 of 93 Northeast Power Coordinating Council Inc.

52 2016 Operating Week 50/50 PLE Forecast 50/50 Demand Forecast MW Delta 10 Jul 16 26,704 26, Jul 16 26,704 26, Jul 16 26,704 26, Jul 16 26,704 26, Aug 16 26,704 26, Aug 16 26,704 25,596 1, Aug 16 26,704 25,154 1, Aug 16 26,704 24,518 2,186 The difference between PLE and Demand Forecast values for the month of June are more than 3,000 MW. When evaluating the Net Margins in light of this surplus, consider tie line capacity above the Capacity Supply Obligations and the conservative Unplanned Outage values of 2,800 MW, New England expects to have sufficient capacity to meet the peak demand of 26,704 MW. Natural Gas Supply With natural gas as the predominant fuel source in New England, the ISO continues to monitor impacting factors to the natural gas fuel deliverability throughout the winter and summer reliability assessment periods. For the 2016 summer capacity period, the ISO expects heavy natural gas pipeline maintenance and construction to occur for select areas but does not forecast deliverability issues that would affect the installed capacity unless natural gas supplies from the East are reduced or environmental concerns limit the capability of the generating resource. ISO NE continues to share information concerning natural gas fueled generation located in New England with the operating personnel of interstate natural gas pipeline companies, provided that the information is operationally necessary and that it will be shared only with the pipeline company directly serving that generator. This information exchange includes maintenance schedules to promote outage coordination between the industries, output schedules for individual generators and discussion of any real time information concerning specific resources for the purpose of maintaining reliability. NPCC Reliability Assessment Summer 2016 Page 48 of 93 Northeast Power Coordinating Council Inc.

53 To improve situational awareness, ISO NE has developed a gas utilization tool (GUT) that assists control room operators in measuring the at risk gas capacity and evaluating current day and next day operating plans. The tool uses data gathered from electronic bulletin boards (EBBs) presented by the gas pipelines serving New England. It provides visibility and awareness of general pipeline conditions and allows for estimating scheduled deliveries on the basis of historical nominations for local distribution companies as well as commercial and industrial loads. The results offer an estimation of the remaining natural gas pipeline capacity available for use by the New England power sector and a forecast of natural gas capacity at risk. For the 2016 summer assessment, ISO NE has several operating procedures that can be invoked to help mitigate energy emergencies impacting the power generation sector: 1. ISO NE s Operating Procedure No. 4 Action During a Capacity Deficiency (OP 4) is a procedure that establishes criteria and guidelines for actions during capacity deficiencies resulting from generator and transmission contingencies and prescribe actions to manage Operating Reserve Requirements ISO NE s Operating Procedure No. 7 Action in an Emergency (OP 7) is a procedure that establishes criteria to be followed in the event of an operating emergency involving unusually low frequency, equipment overload, capacity or energy deficiency, unacceptable voltage levels, or any other emergency that ISO NE deems appropriate in an isolated or widespread area of New England ISO NE s Operating Procedure No. 21 Action During an Energy Emergency (OP 21) is designed to help mitigate the impacts on bulk power system reliability resulting from the loss of operable capacity due to regional fuel supply deficiencies that can occur anytime during the year 10. Fuel supply deficiencies are the temporary or prolonged disruption to regional fuel supply chains for coal, natural gas, LNG, and heavy and light fuel oil. 8 Operating Procedure No. 4 is located on the ISO s web site at: 9 Operating Procedure No. 7 is located on the ISO s web site at: 10 Operating Procedure No. 21 is located on the ISO s web site at: NPCC Reliability Assessment Summer 2016 Page 49 of 93 Northeast Power Coordinating Council Inc.

54 New York Operational Readiness The New York Independent System Operator (NYISO), as the sole Balancing Authority for the New York Control Area (NYCA), anticipates adequate capacity exists to meet the New York State Reliability Council (NYSRC) Installed Reserve Margin (IRM) of 17.5 percent for the 2016 summer season. The weather normalized 2015 peak was 33,226 MW, 341 MW (1.02 percent) lower than the forecast of 33,567 MW prepared in December The current 2016 peak forecast is 33,360 MW and was updated in April It is lower than the December 2014 forecast by 207 MW (0.62 percent). The lower forecasted growth in energy usage can largely be attributed to the projected impact of existing statewide energy efficiency programs 11 and the growing impact of distributed behind the meter energy resources. These include retail photovoltaic 12, combined heat and power (CHP), anaerobic digester gas (ADG), fuel cells, and energy storage. Such resources are expected to continue to affect forecasted energy usage, as programs authorized under New York State s NY SUN Initiative, Clean Energy Fund and Green Bank programs are implemented. Moreover, the overall growth of distributed energy resources (DERs) at the local distribution level is expected to be facilitated by New York State s Reforming Energy Vision (REV) initiative. The peak load forecast was reduced by 255 MW for energy efficiency impacts, 258 MW for behind the meter PV impacts and 182 MW for other distributed generation impacts. The forecast based on extreme weather conditions, set to the 90 th percentile of typical peak producing weather conditions for 2016 is 35,647 MW. The NYISO maintains Joint Operating Agreements with each of its adjacent Reliability Coordinators that include provisions for the procurement, or supply, of emergency energy, and provisions for wheeling emergency energy from remote areas, if required. Prior to the operating month, the NYISO identifies to neighboring control areas the capacity backed transactions that are expected to be both imported into and exported from NYCA in the upcoming month. Discrepancies identified by neighboring control 11 The Clean Energy Fund programs encompass and continue renewable energy and energy efficiency programs that originated with New York s Renewable Portfolio Standard, Energy Efficiency Portfolio Standard (EEPS) and System Benefits Charge (SBC). The NYISO will continue to serve as a technical advisor to those state agencies that are implementing these programs, and will monitor their impact on the NYISO s system planning processes. 12 Retail PV refers to small scale solar powered photo voltaic systems which generate electric energy and are installed at locations on the customer s side of the meter, rather than large scale systems that are interconnected to the bulk power system. NPCC Reliability Assessment Summer 2016 Page 50 of 93 Northeast Power Coordinating Council Inc.

55 areas are resolved. During the 2016 summer season, New York expects to have 1,769 MW of net import capacity available. The NYISO anticipates sufficient resources, including demand response, to meet peak demand without the need to resort to emergency operations. The Emergency Demand Response Program (EDRP) and ICAP/Special Case Resource program (ICAP/SCR) designs promote participation and the expectation is for full participation. Further control actions are outlined in NYISO policies and procedures. There is no limitation as to the number of times a DR resource can be called upon to provide response. SCRs are required to respond when notice has been provided in accordance with NYISO s procedures; response from EDRP is voluntary for all events. Voltage Control The NYISO does not foresee any voltage issues for the upcoming summer season. Generators are compensated for reactive capability and are required to maintain Automatic Voltage Regulators (AVRs) in service at all times for said compensation. Generators must adjust their VAr output when called upon to provide voltage support. The NYCA also has two SVCs at Fraser and Leeds as well as a Convertible Static Compensator (STATCOM) at Marcy which can provide either dynamic or static VAr support as needed. Furthermore, switched shunt capacitors and reactors are installed at key locations throughout the bulk power system to be utilized for voltage control. For summer 2016, new switched shunt capacitors have been installed at the 230 kv Huntley station. Environmental Impacts High capacity factors on certain New York City peaking units could result in possible violations of their daily NOx emission limits if they were to fully respond to the NYISO dispatch signals; this could occur during long duration hot weather events or following the loss of significant generation or transmission assets in NYC. In 2001, the New York State Department of Environmental Conservation (DEC) extended a prior agreement with the New York Power Pool to address the potential violation of NOx and opacity regulations if the NYISO is required to keep these peaking units operating to avoid the loss of load. Under this agreement (DEC, Declaratory Order # 19 12) if the NYISO issues an instruction to a Generator to go to maximum capability in order to avoid loss of load, any violations of NOx RACT emission limits or opacity requirements imposed under DEC regulations would be subject to the affirmative defense for emergency conditions. This determination is limited to circumstances where the maximum capability requested by the NYISO would involve the generation of the highest level of electrical power achievable by the subject Generators with the continued use of properly maintained NPCC Reliability Assessment Summer 2016 Page 51 of 93 Northeast Power Coordinating Council Inc.

56 and operating pollution control equipment required by all applicable air pollution control requirements. Ontario Base Load During the summer period, Ontario expects to have sufficient electricity to meet its projected needs. However, planned nuclear outages (approximately 5,000 MW) occurring at the start of the summer assessment period will reduce net margins. Occurrences of surplus base load generation (SBG) are likely to occur during the assessment period, with a decline in SBG at the start of the period, coinciding with the planned nuclear outages. It is expected that SBG will be managed effectively during this operating period via the scheduling of intertie transactions, the dispatching of gridconnected renewable resources and the maneuvering of available nuclear units. Embedded solar and wind generation will continue to reduce demand on the transmission system, in particular during summer peaks. The summer peaks will also be subject to lower demands due to the Industrial Conservation Initiative (ICI). Voltage Control Although Ontario does not foresee any voltage issues this summer season, managing grid voltages will be challenging during the nuclear outages occurring at the start of the summer assessment period, especially during off peak periods. Studies to determine the best methods of voltage control have been completed, with plans in place to manage grid security. The IESO has also been actively working with transmitters, generators, natural gas pipelines and interconnected neighbours to ensure reliable operation during this period. Operating Procedures Ontario expects to have sufficient electricity to meet its forecasted demand. Québec Equipment Maintenance Most transmission line, transformer and generating unit maintenance is done during the summer period. The maintenance outages are being planned so that all exports can be maintained. Voltage Control NPCC Reliability Assessment Summer 2016 Page 52 of 93 Northeast Power Coordinating Council Inc.

57 Québec is a winter peaking area. During summer periods, reactive capability of generators is not a problem. TransÉnergie does not expect to encounter any kind of low voltage problem during the summer. On the contrary, controlling over voltages on the 735 kv network during off peak hours is the concern. This is accomplished mainly with the use of shunt reactors. Typically, about 15,000 MVar of 735 kv shunt reactors may be connected at any given time during the summer, with seven to ten 735 kv lines out of service for maintenance. Most shunt capacitors, at all voltage levels, are disconnected during the summer. Thermal limits On a few occasions during the last summers, several 735 kv lines in the southern part of the system became heavily loaded, due to the hot temperatures in southern Québec. Although this is a new issue at Hydro Québec, the situation is expected to happen again because summers are generally getting warmer, the air conditioning load is increasing year after year and transfers to summer peaking systems are increasing. Studies have been performed, thermal limits have been optimized and mitigating measures have been implemented to ensure that no line becomes overloaded following a contingency in hot temperature periods. NPCC Reliability Assessment Summer 2016 Page 53 of 93 Northeast Power Coordinating Council Inc.

58 Summer 2016 Solar Terrestrial Dispatch Forecast of Geomagnetically Induced Current Solar Activity Forecast Discussion For the 2016 Summer Operating Period, the longer term and more predictable component of geomagnetic activity looks set to oscillate about twice per month towards active levels where K indices may peak from 4 to 6. The first and longest interval of activity will tend to occur near the end of the first week of each month at the beginning of the summer and slowly migrate toward the beginning of each month by the end of the summer. The second shorter interval of enhanced activity will tend to occur within the last week of each month at the start of the summer and gradually migrate toward the middle of the month by the end of the summer. The solar cycle is now entering a phase where geomagnetic activity tends to peak. This phase can last approximately two to three years and is typically when the most dangerous transient disturbances occur. These disturbances are unpredictable beyond the three day mark, because their sources are powerful sunspot groups that tend to form unpredictably and more frequently during this phase of the sunspot cycle. The risk for powerful and potentially damaging disturbances caused by major solar flares is highest during this phase of the cycle. It is impossible to predict when these sunspot groups will form. The significantly reduced strength of the current solar cycle compared to prior solar cycles adds additional uncertainty as to how this phase of the sunspot cycle will influence the formation of these mammoth sunspot groups. It is expected that the frequency of their occurrence will be reduced, but several powerful episodes of potentially damaging disturbances are expected over the next two to three years. Operators should be aware that we are now in that phase of the sun s cycle which is most prone to strong GIC activity, and the appearance of such volatile activity could occur at any time over this summer and during the next two to three years. It is important to remind operators that GIC damage can be cumulative. Many small GIC events can add up in significance if structures such as transformers are not regularly assessed. It is encouraged that such assessments be regularly performed so that future larger GIC events do not overstress infrastructure into failure modes during the next two to three years. NPCC Reliability Assessment Summer 2016 Page 54 of 93 Northeast Power Coordinating Council Inc.

59 7. Post Seasonal Assessment and Historical Review Summer 2015 Post Seasonal Assessment The sections below describe each Reliability Coordinator area s summer 2015 operational experiences. The NPCC coincident peak 100,883 MW, occurred on July 29, 2015 at HE17 EDT. Maritimes The Maritimes peak demand during the NPCC coincident peak was 2,967 MW. Maritimes actual peak was 3,688 MW on April 29, 2015 at HE8 EDT. All major transmission lines were in service. New England The New England real time peak demand that occurred during the 2015 NPCC coincident peak was 24,398 MW. This peak demand value was also observed on July 20, hour ending 17:00 EDT. The forecasted normal peak demand for summer 2015 was 26,710 MW. On September 9, 2015, New England implemented Master/Local Control Center Procedure #2 (M/LCC 2), Abnormal Conditions Alert and Operating Procedure #4 (OP#4), Action During a Capacity Deficiency. The Operations Morning Report projected an operating reserve surplus of 204 MW, based on the forecast load of 23,810 MW. The actual peak load observed was 24,230 MW for hour ending 17:00. The load increase was attributed to higher than forecast temperatures and dew points experienced on the system during the afternoon hours. At 16:36, a transmission contingency occurred which reduced transfers into New England on the Québec Phase 2 path by approximately 500 MW creating a slight deficiency in operating reserves. At 16:45, M/LCC 2 and OP #4 Action 1 were declared which allows New England to begin to deplete thirty minute operating reserves. Action 1 of OP#4 was cancelled at 18:15 and M/LCC 2 was cancelled at 22:00. The preliminary integrated peak demand for hour ending 17:00 on Wednesday was 24,230 MW, 420 MW above the forecast 23,810 MW. NPCC Reliability Assessment Summer 2016 Page 55 of 93 Northeast Power Coordinating Council Inc.

60 New York The actual peak demand of 31,138 MW occurred July 29, HE17 EDT. This coincided with the NPCC coincident peak week. There were no fuel supply, transmission or reactive capability issues. Ontario The actual peak demand was 22,516 MW on July 28, 2015 HE17 EST. During the NPCC coincident peak week, the actual peak demand was 22,471 MW. No significant events impacting the reliability of the transmission system occurred during the summer 2015 operating period. Québec The Québec actual internal peak demand for summer 2015 occurred on August 19 and was 20,764 MW. The Québec actual internal demand coincident to the NPCC peak was 19,870 MW. Transfers to other areas during the NPCC coincident peak were approximately 6,300 MW. The all time summer peak demand record is 22,092 MW in July No resource adequacy event occurred during the 2015 Summer Operating Period. NPCC Reliability Assessment Summer 2016 Page 56 of 93 Northeast Power Coordinating Council Inc.

61 Historical Summer Demand Review The table below summarizes historical non coincident summer peaks for each NPCC Balancing Authority Area over the last ten years along with the forecast normal noncoincident peak demand for summer Table 7 1: Ten Year Historical Summer Peak Demands (MW) Year Maritimes New England New York Ontario Québec NPCC Demand ,385 28,127 33,939 27,005 21, , ,886 26,145 32,169 25,737 21, , ,675 26,111 32,432 24,195 21, , ,566 25,100 30,843 24,380 21, , ,497 27,102 33,452 25,075 22, , ,725 27,707 33,865 23,342 21, , ,403 25,880 32,439 24,636 21, , ,299 27,379 33,956 24,927 21, , ,721 24,443 29,782 21,363 21, , ,688 24,398 31,138 22,516 20, , Normal (50/50) Forecast 3,606 26,704 33,360 22,587 20, ,981 NPCC Reliability Assessment Summer 2016 Page 57 of 93 Northeast Power Coordinating Council Inc.

62 Reliability Assessments of Adjacent Regions For a comprehensive review of the ReliabilityFirst Corporation Seasonal Resource and Demand, and Transmission Assessment, go to: For reviews of the NERC reliability regions and some of the large Balancing Authority areas go to: NPCC Reliability Assessment Summer 2016 Page 58 of 93 Northeast Power Coordinating Council Inc.

63 9. CP Summer Multi Area Probabilistic Reliabilty Assessment Executive Summary Please refer to Appendix VIII CP Summer Multi Area Probabilistic Reliability Assessment Supporting Documentation for the full CP 8 Report, including the Executive Summary. NPCC Reliability Assessment Summer 2016 Page 59 of 93 Northeast Power Coordinating Council Inc.

64 Appendix I Summer 2016 Expected Load and Capacity Forecasts Table AP 1 NPCC Summary NPCC Reliability Assessment Summer 2016 Page 60 of 93 Northeast Power Coordinating Council Inc

65 Table AP 2 Maritimes NPCC Reliability Assessment Summer 2016 Page 61 of 93 Northeast Power Coordinating Council Inc

66 Table AP 3 New England NPCC Reliability Assessment Summer 2016 Page 62 of 93 Northeast Power Coordinating Council Inc

67 Table AP 4 New York Area NYISO Revision Date April 12, 2016 Control Area Load and Capacity Week Installed Net Total Load Interruptible Known Req. Operating Unplanned Net Net Beginning Capacity Interchange Capacity Forecast Load Maint./Derat. Reserve Outages Margin Margin Sundays MW 1 MW MW MW MW MW MW MW MW % 1-May-16 38,535 1,769 40,304 18,862 1,325 6,809 2,620 3,005 10, % 8-May-16 38,535 1,769 40,304 19,525 1,325 4,183 2,620 3,253 12, % 15-May-16 38,535 1,769 40,304 20,719 1,325 3,315 2,620 3,336 11, % 22-May-16 38,535 1,769 40,304 21,745 1,325 2,898 2,620 3,375 10, % 29-May-16 38,535 1,769 40,304 26,117 1,325 2,165 2,620 3,444 7, % 5-Jun-16 38,535 1,769 40,304 33,360 1,325 1,529 2,620 3, % 12-Jun-16 38,535 1,769 40,304 33,360 1,325 1,245 2,620 3, % 19-Jun-16 38,535 1,769 40,304 33,360 1,325 1,247 2,620 3, % 26-Jun-16 38,535 1,769 40,304 33,360 1,325 1,245 2,620 3, % 3-Jul-16 38,535 1,769 40,304 33,360 1,325 1,245 2,620 3, % 10-Jul-16 38,535 1,769 40,304 33,360 1,325 1,245 2,620 3, % 17-Jul-16 38,535 1,769 40,304 33,360 1,325 1,265 2,620 3, % 24-Jul-16 38,535 1,769 40,304 33,360 1,325 1,261 2,620 3, % 31-Jul-16 38,535 1,769 40,304 33,360 1,325 1,253 2,620 3, % 7-Aug-16 38,535 1,769 40,304 33,360 1,325 1,248 2,620 3, % 14-Aug-16 38,535 1,769 40,304 33,360 1,325 1,263 2,620 3, % 21-Aug-16 38,535 1,769 40,304 33,360 1,325 1,259 2,620 3, % 28-Aug-16 38,535 1,769 40,304 33,360 1,325 1,253 2,620 3, % 4-Sep-16 38,535 1,769 40,304 27,144 1,325 1,628 2,620 3,495 6, % 11-Sep-16 38,535 1,769 40,304 26,680 1,325 1,920 2,620 3,468 6, % Notes (1) - Figures reflect the use of Unforced Capacity Deliverability Rights (UDRs) as currently know n. UDRs represent controllable transmission projects that provide a transmission interface into NYCA. For more information on the use of UDRs, please see section 4.14 of the ICAP Manual. (2) NYISO does not utilize the firm concept. All import and export transactions are finalized in Real Time Dispatch. Although LSEs may have firm contracts w ith external suppliers all bids must clear economically and for reliability in day ahead scheduling and real time dispatch. NPCC Reliability Assessment Summer 2016 Page 63 of 93 Northeast Power Coordinating Council Inc

68 Table AP 5 Ontario Area Ontario Revision Date April 5, 2016 Control Area Load and Capacity Week Installed Net Total Load Interruptible Known Maint./ Req. Operating Unplanned Net Net Beginning Capacity Interchange Capacity Forecast Load Derat./Bottled Cap. Reserve Outages Margin Margin Sundays MW MW MW MW MW MW MW MW MW % 1-May-16 36, ,011 17, ,905 1,636 1,285 4, % 8-May-16 36, ,011 18, ,763 1,636 1,281 2, % 15-May-16 36, ,011 18, ,742 1,636 1,611 2, % 22-May-16 36, ,011 19, ,680 1,636 1,766 1, % 29-May-16 36, ,011 19, ,792 1,635 1,727 2, % 5-Jun-16 36, ,011 20, ,999 1,635 1,490 2, % 12-Jun-16 36, ,011 21, ,873 1,635 1,270 2, % 19-Jun-16 36, ,011 22, ,885 1,635 1,189 1, % 26-Jun-16 36, ,427 22, ,365 1,635 1,463 1, % 3-Jul-16 36, ,427 22, ,117 1,632 1,303 1, % 10-Jul-16 36, ,427 22, ,198 1,632 1,384 2, % 17-Jul-16 36, ,427 22, ,182 1,632 1,564 2, % 24-Jul-16 36, ,427 22, ,706 1,632 1,442 3, % 31-Jul-16 36, ,427 21, ,220 1,629 1,674 4, % 7-Aug-16 36, ,427 21, ,231 1,629 1,698 4, % 14-Aug-16 36, ,427 21, ,252 1,629 2,073 4, % 21-Aug-16 36, ,427 20, ,168 1,629 2,127 5, % 28-Aug-16 36, ,427 18, ,248 1,632 2,002 5, % 4-Sep-16 36, ,427 18, ,267 1,632 1,339 6, % 11-Sep-16 36, ,427 17, ,058 1,632 1,361 6, % Notes "Installed Capacity" includes all generation registered in the IESO-administered market. "Load Forecast" represents the normal w eather case, w eekly 60-minute peaks. "Know n Maint./Derat./Bottled Cap." includes planned outages, deratings, historic hydroelectric reductions and variable generation reductions. "Unplanned Outages" is based on the average amount of generation in forced outage for the assessment period. NPCC Reliability Assessment Summer 2016 Page 64 of 93 Northeast Power Coordinating Council Inc

69 Table AP 6 Québec Area Quebec Revision Date March 14, 2016 Control Area Load and Capacity Week Installed Net Total Load Demand Known Req. Operating Unplanned Net Net Beginning Capacity Interchange Capacity Forecast Response Maint./Derat. Reserve Outages Margin Margin Sundays MW 1 MW 2 MW MW MW 3 MW MW MW MW % 1-May-16 45,484-1,976 43,508 23, ,866 1,500 1,200 4, % 8-May-16 45,484-1,976 43,508 21, ,143 1,500 1,200 6, % 15-May-16 45,484-1,976 43,508 21, ,416 1,500 1,200 8, % 22-May-16 45,484-1,976 43,508 20, ,257 1,500 1,200 8, % 29-May-16 45,484-1,976 43,508 20, ,782 1,500 1,200 9, % 5-Jun-16 45,484-2,056 43,428 20, ,537 1,500 1,200 9, % 12-Jun-16 45,484-2,056 43,428 20, ,798 1,500 1,200 8, % 19-Jun-16 45,484-2,056 43,428 20, ,700 1,500 1,200 8, % 26-Jun-16 45,484-2,056 43,428 20, ,786 1,500 1,200 10, % 3-Jul-16 45,484-2,056 43,428 20, ,966 1,500 1,200 10, % 10-Jul-16 45,484-2,056 43,428 20, ,807 1,500 1,200 9, % 17-Jul-16 45,484-2,056 43,428 20, ,160 1,500 1,200 8, % 24-Jul-16 45,484-2,056 43,428 20, ,613 1,500 1,200 9, % 31-Jul-16 45,484-2,056 43,428 20, ,069 1,500 1,200 10, % 7-Aug-16 45,484-2,056 43,428 20, ,134 1,500 1,200 10, % 14-Aug-16 45,484-2,056 43,428 20, ,874 1,500 1,200 10, % 21-Aug-16 45,484-2,056 43,428 20, ,277 1,500 1,200 9, % 28-Aug-16 45,484-2,056 43,428 20, ,001 1,500 1,200 10, % 4-Sep-16 45,484-1,940 43,544 20, ,923 1,500 1,200 9, % 11-Sep-16 45,484-1,940 43,544 20, ,472 1,500 1,200 8, % Notes 1) Includes Independant Pow er Producers (IPPs) and available capacity of Churchill Falls at the New foundland - Québec border. 2) Includes firm sale of 145 MW to Cornw all. 3) The Demand Response programs are utilized during the Winter Capacity period. NPCC Reliability Assessment Summer 2016 Page 65 of 93 Northeast Power Coordinating Council Inc

70 Appendix II Load and Capacity Tables definitions This appendix defines the terms used in the Load and Capacity tables of Appendix I. Individual Balancing Authority Area particularities are presented when necessary. Installed Capacity This is the generation capacity installed within a Reliability Coordinator area. This should correspond to nameplate and/or test data and may include temperature derating according to the Operating Period. It may also include wind generation derating. NPCC Glossary of Terms Capacity: The rated continuous load carrying ability, expressed in MW or MVA of generation, transmission, or other electrical equipment. Individual Reliability Coordinator area particularities Maritimes This number is the maximum net rating for each generation facility (net of unit station service) and does not account for reductions associated with ambient temperature derating and intermittent output (e.g. hydro and/or wind). New England Installed capacity is based on generator Seasonal Claimed Capabilities (SCC) and generation anticipated to be commercial for the identified capacity period. Totals also account for the operable capacity values of renewable resources. New York This number includes all generation resources that participate in the NYISO Installed Capacity (ICAP) market. Ontario This number includes all generation registered with the IESO. Québec Most of the Installed Capacity in the Québec Area is owned and operated by Hydro Québec Production. The remaining capacity is provided by Churchill Falls and by private producers (hydro, wind, biomass and natural gas cogeneration). NPCC Reliability Assessment Summer 2016 Page 66 of 93 Northeast Power Coordinating Council Inc

71 Net Interchange Net Interchange is the total of Net Imports Net Exports for NPCC and each Balancing Authority Area. Total Capacity Total Capacity = Installed Capacity +/ Net Interchange. Demand Forecast This is the total internal demand forecast for each Reliability Coordinator area as per its Demand Forecast Methodology (Appendix IV) Demand Response Loads that are interruptible under the terms specified in a contract. These may include supply and economic interruptible loads, Demand Response Programs or market based programs. Known Maintenance/Constraints This is the reduction in Capacity caused by forecasted generator maintenance outages and by any additional forecasted transmission or by other constraints causing internal bottling within the Reliability Coordinator area. Some Reliability Coordinator areas may include wind generation derating. Individual Reliability Coordinator area particularities Maritimes This includes scheduled generator maintenance and ambient temperature derates. It also includes wind and hydro generation derating. New England Known maintenance includes all known outages as reported on the ISO NE Annual Maintenance Schedule. NPCC Reliability Assessment Summer 2016 Page 67 of 93 Northeast Power Coordinating Council Inc

72 New York This includes scheduled generator maintenance and includes all wind and other renewable generation derating. Ontario This includes planned generator outages, deratings, bottling, historic hydroelectric reduction and variable generation reductions. Québec This includes scheduled generator maintenance and hydraulic as well as mechanical restrictions. It also includes wind generation derating. It may include usually in summer transmission constraints on the TransÉnergie system. Required Operating Reserve This is the minimum operating reserve on the system for each Reliability Coordinator area. NPCC Glossary of Terms Operating reserve: This is the sum of ten minute and thirty minute reserve (fully available in 10 minutes and in 30 minutes). Individual Reliability Coordinator area particularities Maritimes The required operating reserve consists of 100 percent of the first largest contingency plus 50 percent of the second largest contingency. New England The required operating reserve consists of 120 percent of the first largest contingency plus 50 percent of the second largest contingency. New York The required operating reserve consists of 150 percent of the largest generator contingency. Ontario NPCC Reliability Assessment Summer 2016 Page 68 of 93 Northeast Power Coordinating Council Inc

73 The required operating reserve consists of 100 percent of the first largest contingency plus 50 percent of the second largest contingency. Québec The required operating reserve consists of 100 percent of the largest first contingency + 50 percent of the largest second contingency, including 1,000 MW of hydro synchronous reserve distributed all over the system to be used as stability and frequency support reserve. Unplanned Outages This is the forecasted reduction in Installed Capacity by each Reliability Coordinator area based on historical conditions used to take into account a certain probability that some capacity may be on forced outage. Individual Reliability Coordinator area particularities Maritimes Monthly unplanned outage values have been calculated based on historical unplanned outage data. New England Monthly unplanned outage values have been calculated on the basis of historical unplanned outage data and will also include values for at risk natural gas capacity. New York Seasonal generator unplanned outage values are calculated based on historical generator availability data and include the loss of largest generator source contingency value. Ontario This value is a historical observation of the capacity that is on forced outage at any given time. Québec This value includes a provision for frequency regulation in the Québec Balancing Authority Area, for unplanned outages and for heavy loads as determined by the system controller. Net Margin NPCC Reliability Assessment Summer 2016 Page 69 of 93 Northeast Power Coordinating Council Inc

74 Net margin = Total capacity Load forecast + Interruptible load Known maintenance/constraints Required operating reserve Unplanned outages Individual Reliability Coordinator area particularities New York New York requires load serving entities to procure capacity for their loads equal to their peak demand plus an Installed Reserve Margin. The Installed Reserve Margin requirement represents a percentage of capacity above peak load forecast and is approved annually by the New York State Reliability Council (NYSRC). New York also maintains locational reserve requirements for certain regions, including New York City (Load Zone J), Long Island (Load Zone K) and the G J Locality (Load Zones G, H, I and J). Load serving entities in those regions must procure a certain amount of their capacity from generators within those regions. Bottled Resources Bottled resources = Québec Net margin + Maritimes Net margin available transfer capacity between Québec/Maritimes and Rest of NPCC. Though this is primarily impactive in the summer capacity period, it is determined for both the summer and winter capacity analysis. The Bottled Resources calculation takes into account the fact that the margin available in Maritimes and Québec exceeds the transfer capability to the rest of NPCC. Revised net margin (NPCC Summary only) Revised net margin = Net margin Bottled resources This is used in the NPCC assessment and follows from the Bottled Resources calculation. NPCC Reliability Assessment Summer 2016 Page 70 of 93 Northeast Power Coordinating Council Inc

75 Appendix III Summary of Total Transfer Capability under Forecasted Summer Conditions The following table represents the forecasted transfer capabilities between Reliability Coordinator areas represented as Total Transfer Capabilities (TTC). It is recognized that the forecasted and actual transfer capability may differ depending on system conditions and configurations such as real time voltage profiles, generation dispatch or operating conditions and may also account for Transmission Reliability Margin (TRM). It should be noted that real time transfer limits may change depending on the operation of the system at the time and readers are encouraged to review information on the Available Transfer Capability (ATC) and Total Transfer Capabilities (TTC) between Reliability Coordinator areas. Transmission limit particularities can be found on the Open Access Same Time Information Transmission System (OASIS) or Area specific website listed in below. Maritimes New England New York Ontario o Québec NPCC Reliability Assessment Summer 2016 Page 71 of 93 Northeast Power Coordinating Council Inc

76 Transfers from Maritimes to Interconnection Point TTC at Interconnection Points (MW) ATC under Specified Conditions (MW) Rationale Québec Eel River (NB)/Matapédia (QC) Eel River HVDC (capable of 350 MW) reduced by 15 MW due to losses. When Eel River converter losses and line losses to the Québec border are taken into account, Eel River to Matapédia transfer is 335 MW. Eel River current limit of 325 MW is due to load loss limitation in the Maritimes. This limit is currently under review. Edmundston (NB)/Madawaska (QC) 0 0 An outage is scheduled on the Madawaska HVDC for refurbishment beginning June 1, 2016 with a scheduled return date of November 5, This will reduce the transfer capability to zero. Total New England Keswick (3001 line), Point Lepreau (390/3016 line) For resource adequacy studies, NE assumes that it can import 1,000 MW of capacity to meet New England loads with 50 MW of margin for real time balancing control margin. Total NPCC Reliability Assessment Summer 2016 Page 72 of 93 Northeast Power Coordinating Council Inc

77 Transfers from New England to Interconnection Point TTC (MW) ATC (MW) Comments Maritimes Keswick (3001 line), Point Lepreau (390/3016 line) Transfer capability depends on operating conditions in northern Maine and the Maritimes area. If key generation or capacitor banks are not operational, the transfer limits from New England to New Brunswick will decrease. At present, the NBP SO has limited the transfer to 200 MW but will increase it to 550 MW on request from the NBP SO under emergency operating conditions for up to 30 minutes. This limitation is due to system security/stability within New Brunswick and is currently under review Total New York Northern AC Ties (393, 398, E205W, PV20, K7, K6 and 690 lines) NNC Cable (601, 602 and 603 cables) 1,310 1,310 The transfer capability is dependent upon New England system load levels and generation dispatch. If key generators are online and New England system load levels are acceptable, the transfers to New York could exceed 1,310 MW. ISO NE planning assumptions are based on an interface limit of 1,310 MW The NNC is an interconnection between Norwalk Harbor, Connecticut and Northport, New York. The flow on the NNC Interface is controlled by the Phase Angle Regulating transformer at Northport, adjusting the flows across the cables listed. ISO New England and New York ISO Operations staff evaluates the seasonal TTC across the NNC Interface on a periodic basis or when there are significant changes to the transmission system that warrant an evaluation. A key objective while determining the TTC is to not have a negative impact on the prevalent TTC across the Northern NE NY AC Ties Interface LI / Connecticut (CSC) The transfer capability of the Cross Sound Cable (CSC) is 346 MW. However, losses reduce the amount of MWs that can actually be delivered across the cable. When 346 MW is injected into the cable, 330 MW is received at the point of withdrawal. Total 1,840 1,840 Québec Phase II HVDC link (451 and 452 lines) Highgate (VT) Bedford (BDF) Line 1429 Derby (VT) Stanstead (STS) 1,200 1,200 Export capability of the facility is 1,200 MW Capability of the tie is 225 MW but at times, conditions in Vermont limit the capability to 100 MW or less. The DOE permit is 170 MW. 0 0 Though there is no capability scheduled to export to Québec through this interconnection path, exports may be able to be provided, dependent upon New England system load levels and generation dispatch. NPCC Reliability Assessment Summer 2016 Page 73 of 93 Northeast Power Coordinating Council Inc

78 Line 1400 ISO NE planning assumptions are based on a path limit of 0 MW. Total 1,370 1,300 The New England to Québec transfer limit at peak load is assumed to be 0 MW. It should be noted that this limit is dependent on New England generation and could be increased up to approximately 350 MW depending on New England dispatch. If energy was needed in Québec and the generation could be secured in the Real Time market, this action could be taken to increase the transfer limit. NPCC Reliability Assessment Summer 2016 Page 74 of 93 Northeast Power Coordinating Council Inc

79 Transfers from New York to Interconnection Point TTC (MW) ATC (MW) Rationale for Transfer Capability New England Northern AC Ties (393, 398, E205W, PV20, K7, K6 and 690 lines) LI / Connecticut Northport Norwalk Harbor Cable LI / Connecticut Cross Sound Cable 1,600 1,400 New York applies a 200 MW Transmission Reliability Margin (TRM) Cross Sound Cable power injection is up to 346 MW; losses reduce power at the point of withdrawal to 330 MW. Total 2,130 1,930 Ontario Lines PA301, PA302, BP76, PA27, L33P, L34P 1,900 1,600 New York applies a 300 MW Transmission Reliability Margin (TRM).Thermal limits on the QFW interface may restrict exports to lesser values when the generation in the Niagara area is taken into account. PJM PJM AC Ties 1,300 1,000 New York applies a 300 MW Transmission Reliability Margin (TRM). NYC/PJM Linden VFT LI/PJM Neptune Cable NYC/PJM HTP DC/DC Tie The Neptune DC cable is uni directional into New York. 0 0 The HTP DC/DC tie is uni drectional into New York. Total 1,615 1,315 Québec Chateauguay (QC)/Massena (NY) 1,000 1,000 Cedars / Quebec NPCC Reliability Assessment Summer 2016 Page 75 of 93 Northeast Power Coordinating Council Inc

80 Total 1,040 1,040 NPCC Reliability Assessment Summer 2016 Page 76 of 93 Northeast Power Coordinating Council Inc

81 Transfers from Ontario to Interconnection Point TTC (MW) ATC (MW) Rationale for Transfer Capability New York Lines PA301, PA302, BP76, PA27, L33P, L34P 1,950 1,750 The TRM is 200 MW. Total 1,950 1,750 MISO Michigan Lines L4D, L51D, J5D, B3N 1,700 1,500 The TRM is 200MW. Total 1,700 1,500 Québec NE / RPD KPW Lines D4Z, H4Z Ottawa / BRY PGN Lines P33C, X2Y, Q4C Ottawa / Brookfield Lines D5A, H9A East / Beau Lines B5D, B31L HAW / OUTA Lines A41T, A42T The 95 MW reflects an agreement through the TE IESO Interconnection Committee. The TRM is 10 MW There is no capacity to export to Québec through Lines P33C and X2Y Only one of H9A or D5A can be in service at any time. The TRM is 10 MW Capacity from Saunders that can be synchronized to the Hydro Québec system. 1,250 1,230 The TRM is 20 MW. Total 2,047 2,007 MISO Manitoba, Minnesota NW / MAN The TRM is 25 MW. NPCC Reliability Assessment Summer 2016 Page 77 of 93 Northeast Power Coordinating Council Inc

82 Lines K21W, K22W NW / MIN Line F3M The TRM is 10 MW. Total NPCC Reliability Assessment Summer 2016 Page 78 of 93 Northeast Power Coordinating Council Inc

83 Transfers from Québec to 1 Interconnection Point TTC (MW) ATC (MW) Rationale for Transfer Capability Maritimes Matapédia (QC)/Eel River (NB) radial loads radial loads Radial load transfer amount is dependent on local loading and is reviewed annually Madawaska (QC)/Edmundston (NB) Radial loads Radial loads HQ has an outage scheduled on their Madawaska HVDC for refurbishment beginning June 1, 2016 with a scheduled return date of November 5, Radial loads supply will still be possible via L3113. Total radial loads radial loads Radial load transfer amount is dependent on local loading and is updated monthly and reviewed annually. New England NIC / CMA HVDC link Bedford (BDF) Highgate (VT) Line 1429 Stanstead (STS) Derby (VT) Line ,000 2,000 Capability of the facility is 2,000 MW; At certain times, flows over this tie can be limited to 1,400MW in order to respect operating agreements regarding largest single loss of source Capacity of the Highgate HVDC facility is 225 MW Normally only 35 MW of load in New England is connected. Total 2,275 2,275 New York Chateauguay (QC)/Massena (NY) Les Cèdres (QC)/Dennison (NY) 1,800 1,800 The maximum capacity in this path is 1,800 MW. This capacity is limited by the maximum allowable short circuit current of the Châteauguay facilities. It may also be limited by the maximum import capacity of the New York grid, which ranges from 1,500 to 1,800 MW Points of delivery Dennison (NY) and Cornwall (Ont.) have a maximum capacity of 190 MW and 160 MW respectively (during the summer). However, the TTC of both points of delivery combined is 325 MW, the maximum capacity of Les Cèdres substation. Total 1,990 1,990 Québec to New York transfer capability may reach 1,990 MW on an hour ahead basis and depending on operating conditions in New York and in Québec. NPCC Reliability Assessment Summer 2016 Page 79 of 93 Northeast Power Coordinating Council Inc

84 Ontario Les Cèdres (QC)/Cornwall (Ont.) Beauharnois(QC)/St Lawrence (Ont.) Brookfield/Ottawa (Ont.) Rapide des Iles (QC)/Dymond (Ont.) Bryson Paugan (QC)/Ottawa (Ont.) Outaouais (Qc)/Hawthorne (Ont.) Points of delivery Dennison (NY) and Cornwall (Ont.) have a maximum capacity of 190 MW and 160 MW respectively (during the summer). However, the TTC of both points of delivery combined is 325 MW, the maximum capacity of Les Cèdres substation Only one of H9A or D5A can be in services at any time. The transfer capability reflects usage of D5A. The 200 MW reflects the maximum transfer available from Brookfield to Ontario. D5A s transfer limit is 200 MW during the summer period This represents Line D4Z capacity in summer. There is no capacity to export to Ontario through Line H4Z Capability of line P33C is 270 MW and the X2Y capability is 65 MW (at 30 C / 86 F). There is no capacity to export to Ontario through Line Q4C. 1,250 1,230 HVDC back to back facility at Outaouais. Normally Ontario will schedule up to 1,230 MW allowing for a Transmission Reliability Margin of 20 MW. Total 2,800 2,780 Note 1: These capabilities may not exactly correspond to other numbers posted in Hydro Québec s Annual Reports or on TransÉnergie s website. Such numbers usually corresponding to winter ratings are maximum import/export capabili es available at any one me of the year. The present assessment focuses on summer conditions and these limits recognize transmission or generation constraints in both Québec and its neighbors for the 2016 Summer Operating Period. NPCC Reliability Assessment Summer 2016 Page 80 of 93 Northeast Power Coordinating Council Inc

85 Transfers from Regions External to NPCC Interconnection Point TTC at (MW) ATC (MW) Rationale for Transfer Capability MISO (Michigan) / ONT Lines L4D, L51D, J5D, B3N 1,600 1,600 Represents a worst case scenario for the implementation of Policy on operation. Total 1,600 1,600 Simultaneous Transfers between Michigan and Ontario may be impacted by loop flows and assumes phase shifting capability of Ontario Michigan interface is not available. MISO (Manitoba Minnesota) / ONT NW / MAN Lines K21W, K22W NW / MIN Line F3M The TRM is 25 MW The TRM is 20 MW. Total PJM / New York AC Ties 2,300 2,000 The TRM is 300 MW PJM/NYC Linden VFT PJM/Neptune Neptune Cable PJM/NYC HTP DC/DC Tie Total 3,935 3,635 NPCC Reliability Assessment Summer 2016 Page 81 of 93 Northeast Power Coordinating Council Inc

86 Appendix IV Demand Forecast Methodology Reliability Coordinator area Methodologies Maritimes The Maritimes Area demand is the mathematical sum of the forecasted weekly peak demands of the sub areas (New Brunswick, Nova Scotia, Prince Edward Island, and the area served by the Northern Maine Independent System Operator). As such, it does not take the effect of load coincidence within the week into account. If the total Maritimes Area demand included a coincidence factor, the forecast demand would be approximately 1 to 3 percent lower. For New Brunswick, the demand forecast is based on an End use Model (sum of forecasted loads by use e.g. water heating, space heating, lighting etc.) for residential loads and an Econometric Model for general service and industrial loads, correlating forecasted economic growth and historical loads. Each of these models is weather adjusted using a 30 year historical average. For Nova Scotia, the load forecast is based on a 10 year weather average measured at the major load center, along with analyses of sales history, economic indicators, customer surveys, technological and demographic changes in the market, and the price and availability of other energy sources. For Prince Edward Island, the demand forecast uses average long term weather for the peak period (typically December) and a time based regression model to determine the forecasted annual peak. The remaining months are prorated on the previous year. The Northern Maine Independent System Administrator performs a trend analysis on historic data in order to develop an estimate of future loads. To determine load forecast uncertainty (LFU) an analysis of the historical load forecasts of the Maritimes Area utilities has shown that the standard deviation of the load forecast errors is approximately 4.6 percent based upon the four year lead time required to add new resources. To incorporate LFU, two additional load models were created from the base load forecast by increasing it by 5.0 and 9.0 percent (one or two standard deviations) respectively. The reliability analysis was repeated for these two load models. Nova Scotia uses 5 percent as the Extreme Load Forecast Margin while the rest of the Maritimes uses 9 percent after similar analysis on their part. NPCC Reliability Assessment Summer 2016 Page 82 of 93 Northeast Power Coordinating Council Inc

87 New England ISO New England s long term energy model is an annual model of ISO NE Area total energy, using real income, the real price of electricity, economics and weather variables as drivers. Income is a proxy for all economic activity. The long term peak load model is a monthly model of the typical daily peak for each month, and produces forecasts of weekly, monthly, and seasonal peak loads over a 10 year time period. Daily peak loads are modeled as a function of energy, weather, and a time trend on weather for the summer months to capture the increasing sensitivity of peak load to weather due to the increasing cooling load. The reference (normal) demand forecast 13, which has a 50 percent chance of being exceeded, is based on weekly weather distributions and the monthly model of typical daily peak. The weekly weather distributions are built using 40 years of temperature data at the time of daily electrical peaks (for non holiday weekdays). A reasonable approximation for normal weather associated with the winter peak is 7.0 F and for the summer peak is 90.2 F. The extreme demand forecast, which has a 10 percent chance of being exceeded, is associated with weather at the time of the winter peak of 1.6 F and summer peak of 94.2 F. From a short term load forecast perspective, New England has deployed the Metrix Zonal load forecast which produces a zonal load forecast for the eight regional load zones for up to six days in advance through the current operating day. This forecast enhances reliability on a zonal level by taking into account conflicting weather patterns. An example would be when the Boston zone is forecasted to be sixty five degrees while the Hartford area is forecasting ninety degrees. This zonal forecast ensures an accurate reliability commitment on a regional level. The eight zones are then summed for a total New England load. This adds an additional New England load forecast to our Artificial Neural Network models (ANN) and our Similar Day Analysis (SimDays). Accuracy for this zonal forecast has been an improvement since the summer of New York The NYISO employs a two stage process to develop load forecasts for each of the 11 zones within the NYCA. In the first stage, zonal load forecasts are based upon econometric projections. These forecasts assume a conventional portfolio of appliances 13 Additional information describing ISO New England s load forecasting may be found at NPCC Reliability Assessment Summer 2016 Page 83 of 93 Northeast Power Coordinating Council Inc

88 and electrical technologies. The forecasts also assume that future improvements in energy efficiency measures will be similar to those of the recent past and that spending levels on energy efficiency programs will be similar to recent history. In the second stage, the NYISO adjusts the econometric forecasts to explicitly reflect a projection of the energy savings resulting from statewide energy efficiency programs, impacts of new building codes and appliance efficiency standards and a projection of energy usage due to electric vehicles. In addition to the baseline forecast, the NYISO also produces high and low forecasts for each zone that represent extreme weather conditions. The forecast is developed by the NYISO using a Temperature Humidity Index (THI) which is representative of normal weather during peak demand conditions. The weather assumptions for most regions of the state are set at the 50 th percentile of the historic series of prevailing weather conditions at the time of the system coincident peak. For Orange & Rockland and for Consolidated Edison, the weather assumptions are set at the 67 th percentile of the historic series of prevailing weather conditions at the time of the system coincident peak. Individual utilities include the peak demand impact of demand side management programs in their forecasts. Each investor owned utility, the New York State Energy Research and Development Authority (NYSERDA), the New York Power Authority (NYPA), and the Long Island Power Authority (LIPA), maintain a database of installed measures from which estimates of impacts can be determined. The impact evaluation methodologies and measurement and verification standards are specified by the state's Evaluation Advisory Group, a part of the New York Department of Public Service staff reporting to the New York Public Service Commission. Ontario The Ontario Demand is the sum of coincident loads plus the losses on the IESOcontrolled grid. Ontario Demand is calculated by taking the sum of injections by registered generators, plus the imports into Ontario, minus the exports from Ontario. Ontario Demand does not include loads that are supplied by non registered generation. The IESO forecasting system uses multivariate econometric equations to estimate the relationships between electricity demand and a number of drivers. These drivers include weather effects, economic data and calendar variables. Using regression techniques, the model estimates the relationship between these factors and energy and peak demand. Calibration routines within the system ensure the integrity of the forecast with respect to energy and peak demand, including zone and system wide projections. IESO produces a forecast of hourly demand by zone. From this forecast the following information is available: NPCC Reliability Assessment Summer 2016 Page 84 of 93 Northeast Power Coordinating Council Inc

89 hourly peak demand hourly minimum demand hourly coincident and non coincident peak demand by zone energy demand by zone These forecasts are generated based on a set of weather and economic assumptions. IESO uses a number of different weather scenarios to forecast demand. The appropriate weather scenarios are determined by the purpose and underlying assumptions of the analysis. The base case demand forecast uses a median economic forecast and monthly normalized weather. Multiple economic scenarios are only used in longer term assessments. A quantity of price responsive demand is also forecast based on market participant information and actual market experience. The Ontario demand forecast uses multivariate econometric equations to estimate the relationships between electricity demand and a number of drivers, including weather effects, economic and demographic data and calendar variables. Using regression techniques, the model estimates the relationship between these factors and energy and peak demand. A consensus of four major, publicly available provincial forecasts is used to generate the economic drivers used in the model. In addition, forecast data from a service provider is purchased to enable further analysis and insight. Population projections, labour market drivers and industrial indicators are utilized to generate the forecast of demand. The impact of conservation measures are decremented from the demand forecast, which includes demand reductions due to energy efficiency, fuel switching and conservation behaviour (including the impact smart meters). In Ontario, demand management programs include Demand Response programs and the dispatchable loads program. Historical data is used to determine the quantity of reliably available capacity, which is treated as a resource to be dispatched. Embedded generation leads to a reduction in on grid demand on the grid, which is decremented from the demand forecast. Ontario uses 31 years of history to calculate a weather factor to represent the MW impact on demand if the weather conditions (temperature, wind speed, cloud cover and humidity) are observed in the forecast horizon. Weather is sorted on a monthly basis, and for the extreme weather 14 scenario, Ontario uses the maximum value from the sorted history. 14 Additional information describing Ontario s demand forecasting may be found at: /Power Data/Demand.aspx NPCC Reliability Assessment Summer 2016 Page 85 of 93 Northeast Power Coordinating Council Inc

90 The variable generation capacity in Table 4 is the total installed capacity expected during the operating period, with the variable generation resources expected in service outlined in Table 3. For determining wind derating factors, Ontario uses seasonal contribution factors based on median historical hourly production values from September 2006 to the present. The wind contribution factor is 37.3 percent for the winter and 12.6 percent for the summer. The solar contribution factor is 0 percent for the winter and 33.6 percent for the summer. Québec Hydro Québec s demand and energy sales forecasting is Hydro Québec Distribution s responsibility. First, the energy sales forecast is built on the forecast from four different consumption sectors domestic, commercial, small and medium size industrial and large industrial. The model types used in the forecasting process are different for each sector and are based on end use and/or econometric models. They consider weather variables, economic driver forecasts, demographics, energy efficiency, and different information about large industrial customers. This forecast is normalized for weather conditions based on an historical trend weather analysis. The requirements are obtained by adding transmission and distribution losses to the sales forecasts. The monthly peak demand is then calculated by applying load factors to each end use and/or sector sale. The sum of these monthly end use/sector peak demands is the total monthly peak demand. Load Forecast Uncertainty (LFU) includes weather and load uncertainties. Weather uncertainty is due to variations in weather conditions. It is based on a 44 year database of temperatures ( ), adjusted by 0.3 C (0.5 F) per decade starting in 1971 to account for climate change. Moreover, each year of historical climatic data is shifted up to ±3 days to gain information on conditions that occurred during either a weekend or a weekday. Such an exercise generates a set of 294 different demand scenarios. The base case scenario is the arithmetical average of the peak hour in each of these 294 scenarios. Load uncertainty is due to the uncertainty in economic and demographic variables affecting demand forecast and to residual errors from the models. Overall uncertainty is defined as the independent combination of climatic uncertainty and load uncertainty. This Overall Uncertainty, expressed as a percentage of standard deviation over total load, is lower during the summer than during the winter. As an NPCC Reliability Assessment Summer 2016 Page 86 of 93 Northeast Power Coordinating Council Inc

91 example, at the summer peak, weather conditions uncertainty is about 450 MW, equivalent to one standard deviation. During winter, this uncertainty is 1,450 MW. TransÉnergie the Québec system operator then determines the Québec Balancing Authority Area forecasts using Hydro Québec Distribution s forecasts (HQ internal demand) and accounting for agreements with different private systems within the Balancing Authority Area. The forecasts are updated on an hourly basis, within a 12 day horizon according to information on local weather, wind speed, cloud cover, sunlight incidence and type and intensity of precipitation over nine regions of the Québec Balancing Authority Area. Forecasts on a minute basis are also produced within a two day horizon. TransÉnergie has a team of meteorologists who feed the demand forecasting model with accurate climatic observations and precise weather forecasts. Short term changes in industrial loads and agreements with different private systems within the Balancing Authority Area are also taken into account on a short term basis. NPCC Reliability Assessment Summer 2016 Page 87 of 93 Northeast Power Coordinating Council Inc

92 Appendix V NPCC Operational Criteria, and Procedures NPCC Directories Pertinent to Operations NPCC Regional Reliability Reference Directory #1 Design and Operation of the Bulk Power System Description: This directory provides a design based approach to ensure the bulk power system is designed and operated to a level of reliability such that the loss of a major portion of the system, or unintentional separation of a major portion of the system, will not result from any design contingencies. Includes Appendices F and G Procedure for Operational Planning Coordination and Procedure for Inter Reliability Coordinator area Voltage Control, respectively. NPCC Regional Reliability Reference Directory #2 Emergency Operations Description: Objectives, principles and requirements are presented to assist the NPCC Reliability Coordinator areas in formulating plans and procedures to be followed in an emergency or during conditions which could lead to an emergency. Note: This document is currently under review. NPCC Regional Reliability Reference Directory #5 Reserve Description: This directory provides objectives, principles and requirements to enable each NPCC Reliability Coordinator Area to provide reserve and simultaneous activation of reserve. Note: This document is currently under review. NPCC Regional Reliability Reference Directory #6 Reserve Sharing Groups Description: This directory provides the framework for Regional Reserve Sharing Groups within NPCC. It establishes the requirements for any Reserve Sharing Groups involving NPCC Balancing Authorities. NPCC Regional Reliability Reference Directory #8 System Restoration Description: This directory provides objectives, principles and requirements to enable each NPCC Reliability Coordinator Area to perform power system restoration following a major event or total blackout. Note: This document is currently under review. NPCC Reliability Assessment Summer 2016 Page 88 of 93 Northeast Power Coordinating Council Inc

93 NPCC Regional Reliability Reference Directory # 9 Verification of Generator Gross and Net Real Power Capability Description: This document establishes the minimum criteria to verify the Gross Real Power Capability and Net Real Power Capability of generators used to ensure accuracy of information used in the steady state and dynamic simulation models to assess the reliability of the NPCC bulk power system. Note: Review is underway to check continued need for the document based on content in corresponding NERC Standard (MOD 025 1). NPCC Regional Reliability Reference Directory # 10 Verification of Generator Gross and Net Reactive Power Capability Description: This document establishes the minimum criteria to verify the Gross Reactive Power Capability and Net Reactive Power Capability of generators used to ensure accuracy of information used in the steady state and dynamic simulation models to assess the reliability of the NPCC bulk power system. These criteria have been developed to ensure that the requirements specified in NERC Standard MOD 025 1, Verification of Generator Gross and Net Reactive Power Capability are met by NPCC and its applicable members responsible for meeting the NERC standards. Note: Review is underway to check continued need for the document based on content in corresponding NERC Standard (MOD 025 1). NPCC Regional Reliability Reference Directory # 12 Underfrequency Load Shedding Requirements Description: This document presents the basic criteria for the design and implementation of under frequency load shedding programs to ensure that declining frequency is arrested and recovered in accordance with established NPCC performance requirements to prevent system collapse due to loadgeneration imbalance. A 10 Classification of Bulk Power System Elements Description: This Classification of Bulk Power System Elements (Document A 10) provides the methodology for the identification of those elements of the interconnected NPCC Region to which NPCC bulk power system criteria are applicable. Each Reliability Coordinator area has an existing list of bulk power system elements. The methodology in this document is used to classify elements NPCC Reliability Assessment Summer 2016 Page 89 of 93 Northeast Power Coordinating Council Inc

94 of the bulk power system and has been applied in classifying elements in each Reliability Coordinator area as bulk power system or non bulk power system. NPCC Procedures Pertinent to Operations C 01 NPCC Emergency Preparedness Conference Call Procedures NPCC Security Conference Call Procedures Description: This document details the procedures for the NPCC Emergency Preparedness Conference Calls, which establish communications among the Operations Managers of the Reliability Coordinator (RC) Areas which discuss issues related to the adequacy and security of the interconnected bulk power supply system in NPCC. Note: This document is currently under review.. C 15 Procedures for Solar Magnetic Disturbances on Electrical Power Systems Description: This procedural document clarifies the reporting channels and information available to the operator during solar alerts and suggests measures that may be taken to mitigate the impact of a solar magnetic disturbance. Note: This document is currently under review. C 43 NPCC Operational Review for the Integration of New Facilities Description: The document provides the procedure to be followed in conducting operations reviews of new facilities being added to the power system. This procedure is intended to apply to new facilities that, if removed from service, may have a significant, direct or indirect impact on another Reliability Coordinator area s inter Area or intra Area transfer capabilities. The cause of such impact might include stability, voltage, and/or thermal considerations. NPCC Reliability Assessment Summer 2016 Page 90 of 93 Northeast Power Coordinating Council Inc

95 Appendix VI Web Sites Hydro Québec Independent Electricity System Operator ISO New England ne.com Maritimes Maritimes Electric Company Ltd. New Brunswick Power Corporation New Brunswick Transmission and System Operator Nova Scotia Power Inc. Northern Maine Independent System Administrator Midwest Reliability Organization New York ISO Northeast Power Coordinating Council, Inc. North American Electric Reliability Corporation ReliabilityFirst Corporation NPCC Reliability Assessment Summer 2016 Page 91 of 93 Northeast Power Coordinating Council Inc

96 Appendix VII References CP Summer Multi Area Probabilistic Reliability Assessment NPCC Reliability Assessment for Summer 2016 NPCC Reliability Assessment Summer 2016 Page 92 of 93 Northeast Power Coordinating Council Inc

97 Appendix VIII CP Multi Area Probabilistic Reliability Assessment Supporting Documentation NPCC Reliability Assessment Summer 2016 Page 93 of 93 Northeast Power Coordinating Council Inc

98 Northeast Power Coordinating Council, Inc. Multi-Area Probabilistic Reliability Assessment For Summer 2016 Approved by the TFCP April 19, 2016 Conducted by the CP-8 Working Group

99 CP-8 WORKING GROUP Philip Fedora (Chair) Alan Adamson Syed Ahmed Frank Ciani Jean-Dominic Lacas Kamala Rangaswamy Dragan Pecurcia Rob Vance Vithy Vithyananthan Fei Zeng Northeast Power Coordinating Council, Inc. New York State Reliability Council National Grid USA New York Independent System Operator Hydro-Québec Distribution Nova Scotia Power Inc. Énergie NB Power Independent Electricity System Operator ISO New England Inc. The CP-8 Working Group acknowledges the efforts of Messrs. Mark Walling and Patricio Rocha- Garrido, the PJM Interconnection, and thanks them for their assistance in this analysis.

100 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION FOREWORD Following activation of demand response resources, use of operating procedures designed to mitigate resource shortages (reducing 30-minute reserve, voltage reduction, and reducing 10-minute reserve) is not expected during the 2016 summer period for the Base Case conditions assumed for the expected load forecast assumptions. Natural gas pipeline construction and maintenance is expected to occur throughout the summer period; adequate natural gas pipeline capacity to New England is anticipated throughout the summer period, provided gas supply and transportation is scheduled within each pipeline s posted capability and natural gas supplies are available. Operating procedures are available, as required, to maintain reliability when or if system conditions (such as reductions in anticipated transfers, maintenance extending into the summer period and/or additional constraints) materialize coincident with higher than expected loads (such as caused by a wide spread, prolonged heat wave with high humidity and near record temperatures). CP-8 Working Group April 19, Final Report

101 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION TABLE OF CONTENTS PAGE FOREWORD 1 EXECUTIVE SUMMARY 4 Introduction... 4 Base Case Results... 4 Severe Case Results... 5 Conclusions... 6 INTRODUCTION 7 MODEL ASSUMPTIONS 8 Load Representation... 8 Load Shape... 9 Load Forecast Uncertainty Generation Unit Availability Transfer Limits Operating Procedures to Mitigate Resource Shortages Assistance Priority Modeling of Neighboring Regions ANALYSIS 23 Summer 2015 Review Base Case Results Base Case Assumptions Severe Case Results Severe Case Assumptions Conclusions CP-8 Working Group April 19, Final Report

102 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION APPENDICES PAGE A) OBJECTIVE AND SCOPE OF WORK 36 B) EXPECTED NEED FOR OPERATING PROCEDURES 38 Table 7 Base Case Table 8 Severe Case C) MULTI-AREA RELIABILITY SIMULATION PROGRAM DESCRIPTION 40 CP-8 Working Group April 19, Final Report

103 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION EXECUTIVE SUMMARY Introduction This study assessed NPCC Area reliability by estimating the projected use of Area Operating Procedures designed to mitigate resource shortages for the summer of 2016 (May through September). The CP-8 Working Group closely coordinated its efforts with those of the CO-12 Working Group s study, "NPCC Reliability Assessment for Summer 2016", April General Electric s (GE) Multi-Area Reliability Simulation (MARS) program was selected for the analysis. GE Energy was retained by the Working Group to conduct the simulations. Base Case Results For the May - September 2016 period, assuming the Base Case conditions for the expected load level and following activation of demand response resources, Figures EX- 1(a) shows there would be no significant likelihood of implementing the identified operating procedures (reducing 30-minute reserve, voltage reduction, and reducing 10- minute reserve, etc.) in response to a capacity deficiency for the expected load forecast. The expected load forecast is based upon the probability-weighted average of seven load levels simulated. Estimated Number of Occurrences (days/period) NE NY ON MT QC Activation of DR/SCR Reduce 30-min Reserve Initiate Voltage Reduction Reduce 10-min Reserve Appeals Disconnect Load Figure EX-1(a) Expected Use of Indicated Operating Procedures for Summer 2016 Considering Base Case Assumptions (May September) (Expected Load Forecast) 1 See: CP-8 Working Group April 19, Final Report

104 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION Figure EX-1(b) shows, following activation of demand response resources, the likelihood of reducing 30-minute reserve, voltage reduction, and reducing 10-minute reserve under the Base Case conditions for the extreme load forecast (represents the second to highest load level, having approximately a 6% chance of occurring). Estimated Number of Occurrences (days/period) NE NY ON MT QC Activation of DR/SCR Reduce 30-min Reserve Initiate Voltage Reduction Reduce 10-min Reserve Appeals Disconnect Load Figure EX-1(b) Expected Use of Indicated Operating Procedures for Summer 2016 Considering Base Case Assumptions (May September) (Extreme Load Forecast) Severe Case Results For the May - September 2016 period, Figure EX-1(c) shows, following activation of demand response resources, the expected use of the indicated operating procedures assuming the Severe Case conditions and the expected load forecast. Estimated Number of Occurrences (days/period) NE NY ON MT QC Activation of DR/SCR Reduce 30-min Reserve Initiate Voltage Reduction Reduce 10-min Reserve Appeals Disconnect Load Figure EX-1(c) Expected Use of Indicated Operating Procedures for Summer 2016 Considering Severe Case Assumptions (May September) (Expected Load Forecast) CP-8 Working Group April 19, Final Report

105 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION For the May - September 2016 period, Figure EX-1(d) shows, following activation of demand response resources, the expected use of the indicated operating procedures assuming the Severe Case conditions and the extreme load forecast. Estimated Number of Occurrences (days/period) NE NY ON MT QC Activation of DR/SCR Reduce 30-min Reserve Initiate Voltage Reduction Reduce 10-min Reserve Appeals Disconnect Load Figure EX-1(d) Expected Use of Indicated Operating Procedures for Summer 2016 Considering Severe Case Assumptions (May September) (Extreme Load Forecast) Figures EX-1(c) (expected load level) and EX-1(d) (extreme load level) show, following activation of demand response resources, the possible range of operating procedure if all the Severe Case assumed reductions in anticipated transfers, maintenance extending into the summer period and/or additional constraints materialize coincident with higher than expected loads (such as caused by a wide spread, prolonged heat wave with` high humidity and near record temperatures). Conclusions Following activation of demand response resources, there would be no significant likelihood of using operating procedures designed to mitigate resource shortages (reducing 30-minute reserve, voltage reduction, and reducing 10-minute reserve) during the 2016 summer period for the Base Case conditions assumed for the expected load forecast assumptions. Only New York and New England show the need to use these operating procedures under the Base Case conditions for the extreme load forecast (represents the second to highest load level, having approximately a 6% chance of occurring). Natural gas pipeline construction and maintenance is expected to occur throughout the summer period; adequate natural gas pipeline capacity to New England is anticipated throughout the summer period, provided gas supply and transportation is scheduled within each pipeline s posted capability and natural gas supplies are available. Operating procedures are available, as required, to maintain reliability when or if severe system conditions materialize coincident with higher than expected loads. CP-8 Working Group April 19, Final Report

106 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION INTRODUCTION This study assessed the short-term reliability of Northeast Power Coordinating Council, Inc. (NPCC) for summer 2016 by estimating use of Area operating procedures to mitigate resource shortages for the May - September period. The Working Group closely coordinated its efforts with the CO-12 Working Group s study, "NPCC Reliability Assessment for Summer 2016", April The development of this Working Group s assessment was in response to recommendation (5) from the "June 1999 Heat Wave NPCC Final Report", August 1999 that states: The NPCC Task Force on Coordination of Planning (TFCP) should explore the use of a multi-area reliability study tool as a part of an annual resource adequacy review to gain insight into the effects of maintenance schedules and transmission constraints on regional reliability. The database developed for the NPCC CP-8 Working Group's "2015 Long Range Adequacy Overview", December 1, 2015, 2 was used as the starting point for this analysis. Working Group members reviewed the existing data and made revisions to reflect the conditions expected for the year 2016 assessment period. This report is organized in the following manner: after a brief Introduction, specific Model Assumptions are presented, followed by an Analysis of the results based on the scenarios simulated. The Working Group's Objective and Scope of Work is shown in Appendix A. Tables presenting the corresponding results for the Base Case and Severe Case simulations are listed in Appendix B. Appendix C provides an overview of General Electric's Multi-Area Reliability Simulation (MARS) Program; version 3.18 was used in this assessment. 2 See: CP-8 Working Group April 19, Final Report

107 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION MODEL ASSUMPTIONS Load Representation The loads for each Area were modeled on an hourly, chronological basis. The MARS program modified the input hourly loads through time to meet each Area's specified annual or monthly peaks and energies to model the 2002 load shape. Table 1 summarizes each Area's summer peak load assumptions for the year The values shown for Québec and the Maritimes Area show both their actual summer peak and the peak during the period of NPCC s peak. Table 1 Assumed NPCC 2016 Summer Peak Loads MW Québec Area Maritimes Area 4 New England 5 (QC) (MT) Expected Peak 22,074 20,626 3,456 3, Load Shape Extreme Peak 3 24,194 21,657 3,774 3,442 Month May August May August (NE) 28,593 32,031 August New York (NY) 33,635 36,511 August Ontario (ON) 22,587 25,250 July An explanation of each Area s expected load forecast and methodology can be found in the companion NPCC CO-12 Working Group Report, NPCC Reliability Assessment for Summer 2016, April NPCC Areas have different definitions for their extreme peak load forecasts. A brief summary of the basis of each NPCC Area's extreme peak load forecasts follows. Québec Expected peak load is based on a reference scenario and average weather conditions. Québec doesn t forecast extreme load per se. For the purpose of this exercise, the extreme peak is based on load forecast uncertainty representing approximately two standard deviations. The impact of weather conditions as well as load forecast uncertainty (economic, demographic, prices) are taken into account in simulations. Maritimes Area The Maritimes Area doesn t forecast extreme load ; however, load forecast uncertainty is modeled in its reliability analysis. The load forecast uncertainty factors are developed by comparing the historical forecast values of load to the actual loads experienced. 3 Extreme peak value based on load forecast uncertainty for referenced peak month. 4 The Maritimes Area represents New Brunswick, Nova Scotia, Prince Edward Island, and the area administrated by the Northern Maine Independent System Administrator (NMISA). 5 Net load forecast after taking into account the estimated reduction associated with behind the meter photovoltaic (solar) resources. CP-8 Working Group April 19, Final Report

108 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION New England The Independent System Operator of New England (ISO-NE) bases on a 3-day weighted temperature-humidity index (WTHI) for weather conditions in its peak load forecasts. The peak loads that have a 50% chance of being exceeded and are expected to occur at weighted New England-wide temperature of 90.2F are considered as the 50/50 reference case. Peak loads with a 10% chance of being exceeded and expected to occur at a weighted New England-wide temperature of 94.2F, are considered the 90/10 extreme case. New York The New York Independent System Operator (NYISO) bases its extreme load forecast on one in 15 year weather extreme for high temperature. The NYISO characterizes extreme weather conditions in terms of the NYISO summer index, which incorporates dry bulb and dew point values (temperature and humidity), as well as a build-up effect (through lagged elements in the equation). Ontario Ontario s Independent Electricity System Operator (IESO) uses a multivariate econometric model to forecast energy and peak demand on the IESO controlled grid. The expected peak" for this study was based on the normal weather forecast and its associated load forecast uncertainties, which capture the variability of weather. They, together, generate a distribution of possible outcomes of demand. For some of its studies, the IESO forecasts an Extreme Weather demand scenario, which is generated using the most severe weather experienced over the past thirty-one years for each week of the forecast. Severe relates to the weather which will give the highest peak demand (cold in winter and hot in summer). The resulting forecast provides an outer envelope of peak demands. However, the extreme peak in this study was based on load forecast uncertainty representing approximately two standard deviations. Load Shape Based on comparison of the results from the previous analyses, and recent weather experience, the Working Group concluded that the 2002 load shape was representative of a reasonable expected coincidence of Area load for summer The growth rate in each month s peak was used to escalate Area loads to match the Area's year 2016 demand and energy forecasts. The impacts of Demand-Side Management programs were included in each Area's load forecast, except for New England an Ontario, where demand response programs are treated as supply resources modeled in EOP steps. New York and Ontario include energy efficiency programs in the load forecast, but New York demand response (SCR) resources are not included in the load forecast and are treated as supply resources. The New York EDRP program is modeled as an EOP step, and is also not included in the load forecast. CP-8 Working Group April 19, Final Report

109 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION Figure 1(a) shows the diversity in the NPCC Area load shapes used in this analysis for the composite load shape, which assumes the 2002 load shape for the summer period. Figure 1 (a) Projected Monthly Expected Peak Loads for NPCC Areas 6 Figure 1(b) shows the forecast daily summer peaks (June through August) modeled for the summer-peaking NPCC Areas (New England, New York, and Ontario) assuming the 2002 load shape. New England and New York closely track each other, while Ontario shows a similar pattern but with a bit more variation /04 load shape assumed for the November March period. CP-8 Working Group April 19, Final Report

110 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION 40,000 35,000 30,000 25,000 Load (MW) 20,000 15,000 NY NE ON 10,000 5,000 - June July August Figure 1(b) Forecast 2016 Daily Peak Loads (MW) Modeled for New England, New York and Ontario (Based on 2002 Load Shape Assumption) Load Forecast Uncertainty The effects on reliability of uncertainties in the load forecast, due to weather and economic conditions, were captured through the load forecast uncertainty model in MARS. The program computes the reliability indices at each of the specified load levels (for this study, seven load levels were modeled) and calculates weighted-average values based on the associated probabilities of occurrence. While the per unit variations in Area and sub Area load can vary on a monthly basis, Table 2 shows the values assumed for August, corresponding to the assumed occurrence of the NPCC system peak load (assuming the 2002 load shape). Table 2 also shows the probability of occurrence assumed for each of the seven load levels modeled. In computing the reliability indices, all of the Areas were evaluated simultaneously at the corresponding load level, the assumption being that the factors giving rise to the uncertainty affect all of the Areas at the same time. The amount of the effect can vary according to the variations in the load levels. CP-8 Working Group April 19, Final Report

111 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION For this study, reliability measures are reported for two load conditions: expected and extreme. The values for the expected load conditions are derived from computing the reliability at each of the seven load levels, and computing a weighted-average expected value based on the specified probabilities of occurrence. The indices for the extreme load conditions provide a measure of the reliability in the event of higher than expected loads, and were computed for the second-to-highest load level. These values are shaded in Table 2. Table 2 Per Unit Variation in Load Assumed for the Month of August 2016 Area Per-Unit Variation in Load QC MT NE NY ON Prob Generation Tables 3(a) and 3(b) summarize the summer 2016 capacity assumptions for the NPCC Areas used in the analysis for the Base Case and the Severe Case Scenario, respectively. Also shown in Table 3(a) is each Area's annual weighted average unit availability percentage, based on each Area s capacity according to the following relationship: Annual Weighted Average Availability (%) = (1-P.O.R.) x (1- F.O.R.) Where: P.O.R. = Total Hours on Planned Outage/Total Number of Hours F.O.R. = Total Hours on Forced Outage/Total Number of Hours not on Planned Outage CP-8 Working Group April 19, Final Report

112 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION Table 3(a) NPCC Capacity and Load Assumptions for Indicated Summer 2016 peak period - MW Base Case - Expected Load QC 7 (August) MT (August) NE 8 (August) NY (August) ON 9 (July) Assumed Capacity 33,914 7,397 30,313 38,329 28,076 Net Purchase (+)/Sale (-) -2, ,062 2,058 0 Peak Load 10 22,074 3,456 28,593 33,635 22,587 DR / SCR , Reserve (%) Annual Weighted Average Unit Availability (%) Scheduled Maintenance Table 3(b) NPCC Capacity and Load Assumptions for Indicated Summer 2016 peak period - MW Severe Assumptions Scenario - Extreme Load QC 6 (August) MT (August) NE 8 (August) NY (August) ON 9 (July) Assumed Capacity 32,915 6,892 30,313 38,329 27,488 Net Purchase (+)/Sale (-) -2, ,062 2,058 0 Peak Load 8 24,194 3,774 32,031 36,511 25,250 DR / SCR , Reserve (%) Scheduled Maintenance ,308 Note: Reserve Margin calculation includes Demand Response (DR) for New England and Ontario, and Special Case Resources (SCR) for New York. 7 Capacity shown for Québec adjusted for scheduled maintenance. Annual Weighted Average Unit Availability for Québec does not include scheduled maintenance MW of estimated behind the meter photovoltaic (solar) resources netted from the load forecast. 9 Capacity for Ontario is seasonally adjusted and represents maintenance. 10 Based on the 2002 Load Shape assumption. 11 Maintenance shown is for the week of the monthly peak load. CP-8 Working Group April 19, Final Report

113 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION Unit Availability Details regarding each NPCC Area s assumptions for generator unit availability are described in the respective Area s most recent "NPCC Review of Resource Adequacy," 12 updated for the 2016 summer period as described below. Ontario Ontario s generating unit availability was based on the IESO 18 Month Outlook An Assessment of the Reliability and Operability of the Ontario Electricity System From April 2016 to September (March 22, 2106) 13 The capacity values and planned outage schedules for thermal units are based on monthly maximum continuous ratings and planned outage information contained in market participant submissions. The available capacity states and state transition rates for each existing thermal unit are derived based on analysis of a rolling five-year history of actual forced outage data. For existing units with insufficient historical data, and for new units, capacity states and state transition rate data of existing units with similar size and technical characteristics are applied. Hydroelectric resources are modelled in MARS as capacity-limited and energy-limited resources. Minimum capacity, maximum capacity and monthly energy values are determined on an aggregated basis for each zone based on historical data since market opening (2002). Wind Modeling Capacity limitations due to variability of wind generators are captured by providing probability density functions from which stochastic selections are made by the MARS software. Wind generation is aggregated on a zonal basis and modelled as an energylimited resource with a cumulative probability density function (CPDF) which represents the likelihood of zonal wind contribution being at or below various capacity levels during peak demand hours. The CPDFs vary by month and season. Solar Modeling Solar generation is aggregated on a zonal basis and is modelled as load modifiers. The contribution of solar resources is modelled as fixed hourly profiles that vary by month and season. New England This probabilistic assessment reflects New England generating unit availability assumptions based upon historical performance over the prior five-year period. Unit availability modeled reflects the projected scheduled maintenance and forced outages. Individual generating unit maintenance assumptions are based upon each unit s historical 12 See: 13 See: Outlooks.aspx CP-8 Working Group April 19, Final Report

114 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION five-year average of scheduled maintenance. Individual generating unit forced outage assumptions were based on the unit s historical data and North American Reliability Corporation (NERC) average data for the same class of unit. A more detailed description of the modeling assumptions can be found by referring to the corresponding FERC filings concerning the ISO-New England Installed Capacity Requirement and related values for the 3 rd Reconfiguration Auction for the 2016/2017 Capability Year. 14 Wind Modeling New England utilizes units of a fixed capacity (that varies seasonally) representing the Seasonal Claimed Capability to represent their wind resources. Solar Modeling The solar resources in the 2016 CELT report are included in this assessment, and their seasonal claimed capabilities are used. Approximately 373 MW of Behind the Meter photovoltaic resources are assumed to reduce the internal demand. New York Detailed availability assumptions used for the New York units can be found in the New York ISO Technical Study Report 15 "Locational Minimum Installed Capacity Requirements Study covering the New York Control Area for the Capability Year" and the New York Control Area Installed Capacity Requirement for the Period May April 2017 New York State Reliability Council, December 4, 2015 report. 16 Wind Modeling Wind generators are modeled as hourly load modifiers. The output of each unit varies between 0 MW and the nameplate value based on 2013 production data. Characteristics of this data indicate a capacity factor of approximately 14% during the summer peak hours. A total of 1,455 MW of installed capacity associated with wind generators is included in this study. Solar Modeling Solar generators are modeled as hourly load modifiers. The output of each unit varies between 0 MW and the nameplate MW value based on 2013 production data. Characteristics of this data indicate an overall 47% capacity factor during the summer peak hours. A total of 31.5 MW of solar capacity was included in this study. Maritimes Detailed availability assumptions used for the Marmites units can be found in the latest NPCC Maritimes Area Review of Resource Adequacy See: 15 See: es/resource_adequacy/resource_adequacy_documents/lcr2015_report.pdfn 16 See: CP-8 Working Group April 19, Final Report

115 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION Wind Modeling The Maritimes provides an hourly historical wind output for each sub-area. This profile is then scaled according to the wind online at the time of the regional peak. Solar Modeling There is currently no solar generation in the Maritimes area. Quebec Detailed availability assumptions used for the Quebec units can be found in the latest NPCC Quebec Area Review of Resource Adequacy. 12 Wind Modeling Quebec utilizes units of a fixed capacity (that varies seasonally) to represent the expected capacity. The expected capacity at peak is 30% of the Installed (Nameplate) capacity, with the exception of a small amount (roughly 3%) which is derated for all years of the study. Solar Modeling There is currently no solar generation in the Quebec area. Transfer Limits Figure 2 depicts the system that was represented in this Assessment, showing Area and assumed Base Case transfer limits for the year New York Area internal transmission representation was consistent with the assumptions used in the New York ISO Technical Study Report 15 - "Locational Minimum Installed Capacity Requirements Study covering the New York Control Area for the Capability Year" and the New York Control Area Installed Capacity Requirement for the Period May 2016 April 2017 New York State Reliability Council, December 4, 2015 report. 16 The New England internal transmission representation is consistent with assumptions developed for the 2015 New England Regional System Plan New England Regional System Plan(s) can be found at: CP-8 Working Group April 19, Final Report

116 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION MISO 100 NW West Ontario Niagara Total Ontario 5, (S) MANIT Imports 6100 (W) Exports 288 (S) (W) 65 (S) 85 (W) NE 357 1,700 (S) 1,750 (W) 1,700 (S) 1,750 (W) 16,000 9, (S) 1570 (W) 7,707 Ottawa East 1,650 10,160 1,900 A NPCC Transfer Limits CP Summer Assessment (Assumed Ratings MW) 1760 (S) 2090 (W) * Rating a function of unit availabilities and/or area loads. 550 PJM-SW 2,710 5, New York West 6, (S) 2060 (W) ,000 7,400 3,500 D C Mtl 5,700 1,015 Quebec 1,000 1, DOM- VEPC 0 Cent. G 1,000 1,500 3,200 JB 100 ND 190 (S) 198 (W) ,500 8,400 East Chur. Cedars , (S) 0 (W) 1, PJM-RTO J F MAN Que. J K ,400 The transfer capability between Québec and New Brunswick has been adjusted to reflect the Madawaska HVDC outage. 350 NM 0 NB (S) 1875 (W) CT VT 222 NOR PEI BHE CMA W-MA NS Maritimes 1, ** New England The transfer capability in this direction reflects limitations imposed by ISO-NE for internal New England constraints. Figure 2 - Assumed Transfer Limits Note: With the Variable Frequency Transformer operational at Langlois (Cdrs), Hydro- Québec can import up to 100 MW from New York. 18 Transfer limits between and within some Areas are indicated in Figure 2 with seasonal ratings (S- summer, W- winter) where appropriate. Details regarding the sub-area representation for Ontario, 19 New York, 16 and New England 17 are provided in the respective references. The acronyms and notes used in Figure 2 are defined as follows: Chur - Churchill Falls NOR - Norwalk Stamford NM - Northern Maine MANIT - Manitoba BHE - Bangor Hydro Electric NB - New Brunswick ND - Nicolet-Des Cantons Mtl - Montréal PEI - Prince Edward Island BJ - Bay James C MA - Central MA CT - Connecticut MN - Minnesota W MA - Western MA NS - Nova Scotia MAN - Manicouagan NBM - Millbank NW - Northwest (Ontario) NE - Northeast (Ontario) VT - Vermont RFC- ReliabilityFirst MRO - Midwest Reliability Que - Québec Centre MT - Maritimes Area Organization Cdrs - Cedars/Langlois The transfer capability between New Brunswick and New England is 1,000 MW. However, it was modeled as 700 MW to reflect limitations imposed by ISO-NE for internal New England constraints. 18 See: 19 Ontario Transmission System document can be found at: CP-8 Working Group April 19, Final Report

117 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION Operating Procedures to Mitigate Resource Shortages Each NPCC Area takes defined steps as their reserve levels approach critical levels. These steps consist of those load control and generation supplements that can be implemented before firm load has to be disconnected. Load control measures could include disconnecting or reducing interruptible loads, making public appeals to reduce demand, and/or implementing voltage reductions. Other measures could include calling on generation available under emergency conditions, and/or reducing operating reserves. The need for an Area to begin these operating procedures is modeled in MARS by evaluating the daily probabilistic expectation at specified margin states. The user specifies these margin states for each area in terms of the benefits realized from each emergency measure, which can be expressed in MW, as a per unit of the original or modified load, and as a per unit of the available capacity for the hour. Table 4 summarizes the load relief assumptions modeled for each NPCC Area. The Working Group recognizes that Areas may invoke these actions in any order, depending on the situation faced at the time; however, it was agreed that modeling the actions as in the order indicated in Table 4 was a reasonable approximation for this analysis. Table 4 NPCC Operating Procedures to Mitigate Resource Shortages 2016 Summer Load Relief Assumptions MW or % of Load (August) Actions Q MT NE 20 NY ON 1. Curtail Load / Utility Surplus Appeals RT-DR */ SCR / EDRP SCR Load / Man. Volt. Red % % No 30-min Reserves Volt. Red. 250 Interruptible Load % No 10-min Reserves RT-EG 23 Appeals / Curtailments % Voltage Reduction No 10-min Reserves *Real-Time Demand Resource , ,310 2% 0 20 Values for New England s Real-Time Demand Resources and Real-Time Emergency Generation have been derated to account for historical availability performance. 21 Modeled capacity representing the derated values for New York s SCR and EDRP programs 22 Interruptible Loads for Maritimes Area (implemented only for the Area), Voltage Reduction for all others. 23 Real Time Emergency Generation CP-8 Working Group April 19, Final Report

118 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION Assistance Priority All Areas received assistance on a shared basis in proportion to their deficiency. In this analysis, each step was initiated simultaneously in all Areas and sub- areas. The methodology used is described in Appendix C - Multi-Area Reliability Simulation Program Description - Resource Allocation Among Areas (see page 40). CP-8 Working Group April 19, Final Report

119 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION Modeling of Neighboring Regions For the scenarios studied, a detailed representation of the PJM-RTO and neighboring regions of RFC (ReliabilityFirst) and the MRO-US (Midwest Reliability Organization US portion) MISO (Midcontinent Independent System Operator) was assumed. The assumptions are summarized in Table 5 and Figure 3. Table 5 PJM-RTO, and MISO 2016 Assumptions 24 PJM-RTO MISO Peak Load (MW) 153,010 97,714 Peak Month July July Assumed Capacity (MW) 180, ,755 Reserve (%) Weighted Unit Availability (%) Operating Reserves 3,400 3,906 Interruptible Load 8,777 3,791 No 30-min Reserves 2,765 2,670 Voltage Reductions 2,201 2,200 No 10-min Reserves 635 1,236 Appeals Load Forecast Uncertainty (%) 1.0 +/- 4.51, 9.01, 13.51% 1.0 +/- 3.75, 7.49, 11.24% The diversity between the NPCC monthly peak loads and those of PJM-RTO and MISO are shown in Figure Load and capacity assumptions for RFC-Other based on NERC s Electricity and Supply Database (ES&D) available at: CP-8 Working Group April 19, Final Report

120 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION Figure Projected Monthly Expected Peak Loads for NPCC, PJM-RTO, and MISO 5 Beginning with the 2015 NPCC Long Range Adequacy Overview, 25 (LRAO) the MISO region (minus the recently integrated Entergy region) was included in the analysis replacing the RFC-OTH and MRO-US regions. In previous versions of the LRAO, RFC- OTH and MRO-US were included to represent specific areas of MISO, however due to difficulties in gathering load and capacity data for these two regions (since most of the reporting is done at the MISO level), it was decided to start including the entirety of MISO in the model beginning this year. MISO was modeled in this study due to the strong transmission ties of the region with the rest of the study system. MISO The Mid-Continent Independent System Operator, Inc. (MISO) is a not-for-profit, member-based organization administering wholesale electricity markets in all or parts of 15 states in the US. MISO unit data was obtained from the publicly available NERC datasets. Each individual unit represented in MISO was then assigned unit performance characteristics 25 See: CP-8 Working Group April 19, Final Report

121 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION based on PJM RTO fleet class averages (consistent with PJM 2015 Reserve Requirement Study Report). MISO load data was obtained from publicly available sources, namely FERC Form 714 and the MISO LOLE Study Report. 26 PJM-RTO Load Model The load model used for the PJM-RTO in this study is consistent with the PJM Planning division's technical methods. 27 The hourly load shape is based on observed 2002 calendar year values, which reflects representative weather and economic conditions for a peak planning study. The hourly loads were then adjusted per the PJM Load Forecast Report, January Load forecast uncertainty was modeled consistent with recent planning PJM models 29 considering seven load levels, each with an associated probability of occurrence. This load uncertainty typically reflects factors such as weather, economics, diversity (timing) of peak periods among internal PJM zones, the period years the model is based on, sampling size, and how many years ahead in the future the load forecast is being derived for. Expected Resources All generators that have been demonstrated to be deliverable were modeled as PJM capacity resources in the PJM-RTO study area. Existing generation resources, planned additions, modifications, and retirements are per the EIA-411 data submission and the PJM planning process. Load Management (LM) is modeled as an Emergency Operating Procedure. The total available MW as LM is as per results from the PJM s capacity market. Expected Transmission Projects The transfer values shown in the study are reflective of peak emergency conditions. PJM is a summer peaking area. The studies performed to determine these transfer values are in line with the Regional Transmission Planning Process employed at PJM, of which the Transmission Expansion Advisory Committee (TEAC) reviews these activities. All activities of the TEAC can be found at the pjm.com web site. All transmission projects are treated in aggregate, with the appropriate timing and transfer values changing in the model, consistent with PJM s regional Transmission Expansion Plan Please refer to PJM Manuals 19 and 20 at redline.ashx and, for technical specifics. 28 See: 29 See: 30 See: CP-8 Working Group April 19, Final Report

122 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION ANALYSIS Summer 2015 Review 31 The average temperature for the contiguous US during summer 2015 was 72.7 F, 1.3 F above the 20th century average. This ranked as the 12th warmest summer on record and warmest since The summer contiguous U.S. maximum (daytime) temperature was 85.1 F, 0.7 F above average, the 36th warmest on record. The summer contiguous U.S. minimum (nighttime) temperature was 60.3 F, 1.9 F above average, the fourth warmest on record. Near- to below-average temperatures stretched from the Central Plains, through the Midwest, and into the Northeast. No state was record cold. Above-average precipitation across these areas suppressed daytime temperatures, contributing to the cool summer. This was the third consecutive cooler-than-average summer for many locations in the Midwest. According to information from the Midwest Regional Climate Center, most cities in the region had below average counts of 90 F days during the summer of A few examples of the lack of 90 F days through August 31st: Minneapolis: Four 90 F days in 2015 compared to 13 on average. Chicago: Seven 90 F days in 2015 compared to 14 on average. Indianapolis: Six 90 F days in 2015 compared to 14 on average. Cleveland: Three 90 F days in 2015 compared to 11 on average. Based on Residential Energy Demand Temperature Index (REDTI), 32 the contiguous U.S. temperature-related energy demand during June-August was 51.1 percent above average and the 21st highest in the period of record. Precipitation The summer precipitation total for the contiguous U.S. was 9.14 inches, 0.82 inch above average. Driven largely by rainfall early in the season across the Midwest and Northeast, it was the 16 th wettest summer on record. Nine states across the Midwest and Northeast had summer precipitation totals that were much above average. Record precipitation fell across the Ohio Valley during June and July, but a relatively dry August kept the seasonal rainfall totals off the record mark. Above-average precipitation also fell in parts of the West, mostly during July, but this is the dry season for the region and the rainfall did little to improve long-term drought conditions. 31 NOAA National Centers for Environmental Information, State of the Climate: National Overview for August 2015, published online September 2015, retrieved on March 17, 2016 from 32 See: CP-8 Working Group April 19, Final Report

123 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION Northeast Region 33 The Northeast wrapped up August with an average temperature of 68.9 F (20.5 C), which was 0.8 F (0.4 C) above normal. Of the eight states that saw above-normal temperatures, seven ranked this August among their top 20 warmest: Rhode Island, 4th warmest; Maine, 5th warmest; Connecticut, 8th warmest; Massachusetts, 9th warmest; New Hampshire, 11th warmest; Vermont, 16th warmest; and New Jersey, 20th warmest. Departures for all states ranged from 1.2 F (0.7 C) below normal in West Virginia to 2.9 F (1.6 C) above normal in Maine. Kennedy Airport, New York and Caribou, Maine both had a record-warm August. Kennedy Airport's average maximum temperature was also record-warm. The site did not have a maximum temperature below 81 F (27.2 C) during August, which is the first time on record. Caribou set a record for the greatest number of consecutive days with a high temperature of 80 F (26.7 C) or higher with 10 such days from August 14-23, After a cool June, variable July, and warm August, the summer season in the Northeast averaged out to be normal, with an average temperature of 67.6 F (19.8 C). Ten states were either normal or warmer than normal, with temperatures ranging from 0.5 F (0.3 C) below normal in Maine to 0.8 F (0.4 C) above normal in New Jersey, its 16th warmest summer on record. In addition, Rhode Island had its 19th warmest summer. August was a dry month for the Northeast with 2.99 inches (75.95 mm) of precipitation, which was 76 percent of normal. Eleven states were drier than normal, with four ranking this August among their top 20 driest: Connecticut, 11th driest; New Jersey and West Virginia, 15th driest; and Pennsylvania, 19th driest. Departures ranged from 50 percent of normal in Connecticut to 108 percent of normal in Maine. The Northeast had its 12th wettest summer on record, due primarily to an extremely wet June. For the season, the region ended up with inches ( mm) of precipitation, which was 117 percent of normal. Of the ten states that were wetter than normal, six ranked this summer among their top 20 wettest: Pennsylvania, 11th wettest; New Hampshire, 12th wettest; Vermont, 14th wettest; New York, 15th wettest; Maine, 18th wettest; and West Virginia, 19th wettest. Departures ranged from 85 percent of normal in Connecticut to 135 percent of normal in Maryland. At the beginning of August, parts of New England and New York (totaling 10 percent of the region) were abnormally dry or experiencing moderate drought. Spotty rainfall led to the expansion of abnormal dryness in these areas mid-month. Abnormal dryness was introduced in parts of New Jersey, Pennsylvania, Maryland, and West Virginia midmonth, as well. By the end of August, 23 percent of the Northeast was abnormally dry or under moderate drought conditions, according to the U.S. Drought Monitor. The Northeast experienced severe weather multiple times during August. A waterspout moved across Boston Harbor near Peddocks Island on the 4th. In addition, two tornadoes 33 Information provided by the Northeast Regional Climate Center CP-8 Working Group April 19, Final Report

124 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION touched down in Pennsylvania during the month, an EF-0 on the 10th and an EF-1 on the 20th. Straight-line winds of up to 100 mph (45 m/s) caused damage, as did large hail, which was as large as tennis balls and baseballs in some areas. In addition, heavy rain triggered flash flooding, leading to road closures and water rescues. New England 34 On Wednesday, September 9, 2015 ISO New England implemented Master/Local Control Center Procedure No. 2 (M/LCC 2), Abnormal Conditions Alert and Operating Procedure No. 4 (OP4), Action During a Capacity Deficiency. The Morning Report projected an operating reserve surplus of 204 MW, based on the forecast load of 23,810 MW. The actual integrated peak load observed was 24,230 MW for hour ending The load increase can be attributed to higher temperatures and dew points experienced on the system during the afternoon hours. The forecasted temperatures in Boston and Hartford were 86 F and 88 F respectively with actual temps of 90 F and 91 F during the peak hour. At 16:36, a transmission contingency occurred which reduced transfers into New England on Phase 2 by approximately 500 MW creating a slight deficiency in operating reserves. At 16:45, M/LCC 2 and OP4 Action 1 were declared which allows New England to begin to deplete thirty minute operating reserves. Action 1 of OP4 was cancelled at 18:15 and M/LCC 2 was cancelled at 22:00. The preliminary integrated peak demand for hour ending 17:00 on Wednesday was 24,230 MW, 420 MW above the forecast 23,810 MW value. New York New York had no Demand Response activations or use of emergency procedures for the entire summer 2015 period. Ontario No significant events impacting the reliability of the transmission system occurred during the summer period May September, Table 6 compares each NPCC Area s actual 2015 summer peak demands against the forecast assumptions. 34 See: CP-8 Working Group April 19, Final Report

125 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION Table 6 NPCC 2015 Summer Peak Loads Actual versus Forecast MW Area Québec Actual Peak Date 20,766 August 19 Maritimes 3,688 April 29 Expected Peak 22,091 21,035 3,607 3, Load Shape Extreme Peak 24,212 22,087 3,939 3,566 Month May August May August New England 24, July 20 28,397 31,768 August New York 31,138 July 29 33,567 36,445 August Ontario 36 22,516 July 28 22,991 25,701 July 35 The weather normalized peak is 28,225 MW. 36 Ontario was winter peaking in 2014 for the first time in 10 years due to mild summer weather. With the more summer typical weather, Ontario was summer peaking in CP-8 Working Group April 19, Final Report

126 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION 2016 Base Case Results The Working Group modified the 2015 NPCC Long Range Adequacy Overview MARS database for the conditions expected for the year Table 7 (see Appendix B) shows the estimated need for the indicated operating procedures (in days/period) during May through September 2016 for the Base Case for all NPCC Areas. As shown in Figure 4(a), for the May - September 2016 period, following activation of demand response resources, assuming the Base Case conditions and the expected load forecast, it is anticipated there would be no significant likelihood of implementing the indicated operating procedures in response to a capacity deficiency. Estimated Number of Occurrences (days/period) NE NY ON MT QC Activation of DR/SCR Reduce 30-min Reserve Initiate Voltage Reduction Reduce 10-min Reserve Appeals Disconnect Load Figure 4(a) - Summer 2016 Expected Use of the Indicated Operating Procedures Base Case Assumptions, Expected Load Level (May September) Figure 4(b) shows the corresponding results for the extreme load level (represents the second to highest load level, having approximately a 6% chance of occurring). Following activation of demand response resources, only New York and New England show a chance of using their operating procedures shown under the Base Case conditions for the extreme load forecast. CP-8 Working Group April 19, Final Report

127 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION Estimated Number of Occurrences (days/period) NE NY ON MT QC Activation of DR/SCR Reduce 30-min Reserve Initiate Voltage Reduction Reduce 10-min Reserve Appeals Disconnect Load Figure 4(b) - Summer 2016 Expected Use of the Indicated Operating Procedures Base Case Assumptions, Extreme Load Level (May September) Base Case Assumptions The following summary of Base Case assumptions represents system conditions consistent with those assumed in the NPCC CO-12 Working Group's "Reliability Assessment for Summer 2016, April The Base Case assumptions are summarized below: System - As-Is System for the year Transfers allowed between Areas Load Shape adjusted to Area s year 2016 forecast (expected and extreme assumptions) Ontario - Forecast consistent with the IESO s 18-Month Outlook: An Assessment of the Reliability and Operability of the Ontario Electricity System From April 2016 to September 2017 (March 22, 2016) 13 - Existing generation resources of 35,591 MW and planned resources - Demand Measures modeled as per the 2016-Q1 18-Month Outlook - Pricing, conservation and embedded generation effects modeled as per the 18-Month Outlook demand forecast New England - Seasonal claimed capability is used for generating resources, and capacity supply obligation is used for demand resources and capacity imports - existing and planned generation resources based on 2016 CELT report - demand supply resources based on rd Annual Reconfiguration Auction - capacity import based on rd Annual Reconfiguration Auction - natural gas transportation (pipeline) maintenance is completed as scheduled within each pipeline s posted capability. CP-8 Working Group April 19, Final Report

128 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION New York - Updated Load Forecast - (NYCA 33,360 MW; NYC 11,794 MW; LI 5,479 MW) - Assumptions consistent with the New York Control Area Installed Capacity Requirements for the Period May 2016 Through April Maritimes - ~ 980 MW of installed wind generation (modeled using April 2011 to March 2012 hourly wind year excluding 164 MW of energy only units in Nova Scotia) - no import/export contracts assumed MW of demand response (interruptible load) available Québec - Planned resources and load forecast are consistent with the 2015 Quebec Interim Review of Resource Adequacy for the Summer 2016 period, including ~ 5,200 MW of maintenance and restrictions - Wind generation resources are derated by 100 % percent for the Summer peak period - ~ 2,000 MW of sales to neighboring areas. PJM-RTO 37 - As-Is System for the Summer 2016 period based on the PJM 2015 Reserve Requirement Study Load Shapes & Load Forecast Uncertainty adjusted to the 2016 forecast provided by PJM - Operating Reserve 3,400 MW (30-min. 2,765 MW; 10-min. 635 MW) - ~2,500 MW of high ambient temperature generator derates MISO 38 - As-Is System for the Summer 2016 period based on NERC ES&D database, updated by MISO, compiled by PJM staff Load Shapes and Load Forecast Uncertainty adjusted to the most recent monthly forecast provided by PJM - Operating Reserve 3,906 MW (30-min. 2,670 MW; 10-min. 1,236 MW) New York Details The Base Case assumes that the New York City and Long Island localities will meet their locational installed capacity requirements as described in the New York ISO report 15 - "Locational Installed Capacity Requirements Study covering the New York Control Area for the Capability Year" and New York State will meet the capacity requirements described in the New York Control Area Installed Capacity Requirements PJM Reserve Requirement Study (RRS), dated October 8, 2015 available at: 38 Does not include the recently integrated Entergy region (MISO South) CP-8 Working Group April 19, Final Report

129 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION for the Period May 2016 April 2017 New York State Reliability Council, December 4, 2015 Technical Study Report. 16 The capacity rating for each thermal generating unit is based on its Dependable Maximum Net Capability (DMNC) values from the 2015 Load & Capacity Data of the NYISO (Gold Book). 39 The source of DMNC ratings are seasonal tests required by procedures in the NYISO Installed Capacity Manual. Additionally, each generating resource has an associated capacity CRIS (Capacity Resource Interconnection Service) value. When the associated CRIS value is less than the DMNC rating, the CRIS value is modeled. Existing Resources All in-service New York generation resources were modeled; the following unit was rerated: Project Name (MW) Location Bowline 2 Rerate Zone G Retirements There were no retirements scheduled during the study period. Planned Units for 2016 No generator units scheduled to come on-line during the study period. Special Case Resources and Emergency Demand Response Programs Special Case Resources (SCRs) are loads capable of being interrupted, and distributed generators, rated at 100 kw or higher, that are not directly telemetered. SCRs offer load curtailment as ICAP resources and provide energy/load curtailment when activated in accordance with the NYISO Emergency Operating Manual. SCRs are required to respond to a deployment request for a minimum of four hours; however there is no limit to the number of calls or the time of day in which the Special Case Resources may be deployed. SCRs receive a capacity payment for load curtailment capability sold in the ICAP market and an energy payment for energy performance during a demand response event. The Emergency Demand Response Program (EDRP) is a voluntary reliability program that allows registered interruptible loads and standby generators when activated in accordance with the NYISO Emergency Operating Manual. EDRP resources are only paid for their energy performance during a demand response event. There is no limit to the number of calls or the time of day in which EDRP resources may be deployed. 39 See: lanning_data_and_reference_docs/data_and_reference_docs/2015_goldbook_final.pdf CP-8 Working Group April 19, Final Report

130 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION SCRs and EDRPs are modeled as an operating procedure step activated to minimize the probability of customer load disconnection. The GE-MARS models the NYISO operations practice of only activating operating procedures in zones from which are capable of being delivered. For the month of July, 1,254 MW (ICAP value) of SCRs were modeled. At the time of the August New York peak, this amount was further discounted to 961 MW, modeled based on historical availability. EDRPs are modeled as a 75 MW operating procedure step in July and August and they are also limited to a maximum of five EDRP calls per month. This value is discounted based on actual experience from the forecast registered amount to 12 MW. New England Details The New England generating unit s ratings were consistent with their summer seasonal capability to be reported for the 2016 Capacity Energy Load & Transmission (CELT) report. 40 Demand Supply Resources The passive non-dispatchable demand resources, On-Peak and Seasonal-Peak, are expected to provide ~1,885 MW of load relief during the peak hours. Approximately 556 MW of active demand resources, including Real-Time Demand Resources and Real- Time Emergency Generation Resources, provide additional real time peak load relief at a request by ISO New England, during or in anticipation of expected operable capacity shortage conditions, to implement ISO-NE Operating Procedure No. 4, Actions During a Capacity Deficiency. These demand resources are discounted in the assessment to account for performance based on the observed availability factors of demand response programs in the past. Ontario Details For the purposes of this study, the Base Case assumptions for Ontario are consistent with the IESO 18-Month Outlook: An Assessment of the Reliability and Operability of the Ontario Electricity System From April 2016 September Existing Resources All in-service Ontario generation resources were modeled. 40 See: CP-8 Working Group April 19, Final Report

131 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION Resource Additions Project Name Zone Fuel Type Estimated Effective Date Project Status Planned (MW) Bow Lake Phase 1 Northeast Wind Commercial Operation 20 Bow Lake Phase 2b Northeast Wind Commercial Operation 40 Cedar Point Wind Commercial Southwest Wind Power Project Phase II Operation 100 Northland Power Solar Commercial Northeast Solar Empire Operation 10 Northland Power Solar Commercial Northeast Solar Abitibi Operation 10 Northland Power Solar Commercial Northeast Solar Martin's Meadows Operation 10 Northland Power Solar Commercial Northeast Solar Long Lake Operation 10 Grand Valley Wind Commercial Southwest Wind Farms (Phase 3) Operation 40 Armow Wind Southwest Wind Commercial Operation 180 Grand Bend Wind Farm Southwest Wind 2016-Q2 Commissioning 99 Green Electron Power West Gas 2016-Q2 Under Development 298 Gitchi Animki (White River) Generating Station Northwest Water 2016-Q2 Under Development 19 CP-8 Working Group April 19, Final Report

132 Appendix VIII - CP SUMMER MULTI-AREA PROBABILISTIC RELIABILITY ASSESSMENT SUPPORTING DOCUMENTATION 2016 Severe Case Results Table 8 - (see Appendix B) shows the estimated need for the indicated operating procedures (in days/period) during May through September 2016 for the Severe Case Scenario for all NPCC Areas. Figure 5(a) shows, following activation of demand response resources, the expected use of the indicated operating procedures occurrences under the Severe Case assumptions for the expected load. The expected load level results were based on the probabilityweighted average of seven load levels simulated. Estimated Number of Occurrences (days/period) NE NY ON MT QC Activation of DR/SCR Reduce 30-min Reserve Initiate Voltage Reduction Reduce 10-min Reserve Appeals Disconnect Load Figure 5(a) - Summer 2016 Expected Use of the Indicated Operating Procedures Severe Case Assumptions, Expected Load Level (May September) Figure 5(b) shows the corresponding results for the extreme load level (represents the second to highest load level, having approximately a 6% chance of occurring). Estimated Number of Occurrences (days/period) NE NY ON MT QC Activation of DR/SCR Reduce 30-min Reserve Initiate Voltage Reduction Reduce 10-min Reserve Appeals Disconnect Load Figure 5(b) - Summer 2016 Expected Use of the Indicated Operating Procedures Severe Case Assumptions, Extreme Load Level (May September) CP-8 Working Group April 19, Final Report